Lonestar Resources US (LONE) 10-K 13 Apr 20 2019 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Apr. 06, 2020	Jun. 30, 2019
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Entity Registrant Name	Lonestar Resources US Inc.
Entity Central Index Key	0001661920
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	true
Entity Ex Transition Period	false
Entity Shell Company	false
Entity Public Float			$ 45.3
Entity Common Stock, Shares Outstanding		25,270,595

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Current assets
Cash and cash equivalents	$ 3,137	$ 5,355
Accounts receivable
Oil, natural gas liquid and natural gas sales	15,991	15,103
Joint interest owners and other, net	1,310	4,541
Related parties	0	301
Derivative financial instruments	5,095	15,841
Prepaid expenses and other	2,208	1,966
Total current assets	27,741	43,107
Oil and gas properties, using the successful efforts method of accounting
Proved properties	1,050,168	960,711
Unproved properties	76,462	81,850
Other property and equipment	21,401	17,727
Less accumulated depreciation, depletion, amortization and impairment	(464,671)	(369,529)
Property and equipment, net	683,360	690,759
Accounts receivable related party	5,816	0
Derivative financial instruments	1,754	7,302
Other non-current assets	2,108	2,944
Total assets	720,779	744,112
Current liabilities
Accounts payable	33,355	18,260
Accounts payable – related parties	189	181
Oil, natural gas liquid and natural gas sales payable	14,811	13,022
Accrued liabilities	26,905	28,128
Derivative financial instruments	8,564	430
Current maturities of long-term debt	247,000	0
Total current liabilities	330,824	60,021
Long-term liabilities
Long-term debt	255,068	436,882
Asset retirement obligations	7,055	7,195
Deferred tax liability, net	931	12,370
Equity warrant liability	129	366
Equity warrant liability - related parties	235	689
Derivative financial instruments	1,898	21
Other non-current liabilities	3,752	4,021
Total long-term liabilities	269,068	461,544
Commitments and contingencies
Stockholders’ equity
Class A voting common stock, $0.001 par value, 100,000,000 shares authorized, 24,945,594 and 24,645,825 issued and outstanding, respectively	142,655	142,655
Series A-1 convertible participating preferred stock, $0.001 par value, 100,328 and 91,784 shares issued and outstanding, respectively	0	0
Additional paid-in capital	175,738	174,379
Accumulated deficit	(197,506)	(94,487)
Total stockholders’ equity	120,887	222,547
Total liabilities and stockholders’ equity	$ 720,779	$ 744,112

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2019	Dec. 31, 2018
Class A Voting Common Stock
Common stock, par value (in dollars per share)	$ 0.001	$ 0.001
Common stock, shares authorized (in shares)	100,000,000	100,000,000
Common stock, shares issued (in shares)	24,945,594	24,645,825
Common stock, shares outstanding (in shares)	24,945,594	24,645,825
Series A-1 Convertible Participating Preferred Stock
Preferred stock, par value (in dollars per share)	$ 0.001	$ 0.001
Preferred stock, shares issued (in shares)	100,328	91,784
Preferred stock, shares outstanding (in shares)	100,328	91,784

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Revenues
Revenues	$ 195,152	$ 201,169
Expenses
Lease operating and gas gathering	36,581	26,008
Production and ad valorem taxes	11,169	11,029
Depreciation, depletion and amortization	88,618	83,582
Loss on sale of oil and gas properties	33,508	0
Impairment of oil and gas properties	48,412	12,169
General and administrative	16,489	16,017
Acquisition costs and other	1,840	1,821
Total expenses	236,617	150,626
(Loss) income from operations	(41,465)	50,543
Other income (expense)
Interest expense	(43,879)	(38,943)
Unrealized gain on warrants	691	416
(Loss) gain on derivative financial instruments	(30,861)	22,744
Loss on extinguishment of debt	0	(8,620)
Total other expense, net	(74,049)	(24,403)
(Loss) income before income taxes	(115,514)	26,140
Income tax benefit (expense)	12,495	(6,792)
Net (loss) income	(103,019)	19,348
Preferred stock dividends	(8,544)	(7,816)
Net (loss) income attributable to common stockholders	$ (111,563)	$ 11,532
Net (loss) income per common share attributable to common stockholders
Basic (in dollars per share)	$ (4.48)	$ 0.29
Diluted (in dollars per share)	$ (4.48)	$ 0.28
Weighted Average Shares Outstanding
Basic (in shares)	24,875,793	24,619,730
Diluted (in shares)	24,875,793	24,801,143
Oil sales
Revenues
Revenues	$ 157,873	$ 167,743
Natural gas liquid sales
Revenues
Revenues	15,668	18,471
Natural gas sales
Revenues
Revenues	$ 21,611	$ 14,955

Consolidated Statements of Chan

Consolidated Statements of Changes in Stockholders' Equity - USD ($) $ in Thousands	Total	Class A Common Stock	Series A-1 Preferred Stock	Additional Paid-in Capital	Accumulated Deficit
Beginning balance (in shares) at Dec. 31, 2017		24,506,647	83,968
Beginning balance at Dec. 31, 2017	$ 203,690	$ 142,655		$ 174,871	$ (113,836)
Shares issued pursuant to stock-based compensation plan (in shares)		139,178
Shares issued pursuant to stock-based compensation plan	(601)			(601)
Retirement of class B common stock	(10)			(10)
Payment-in-kind dividends (in shares)			7,816
Stock-based compensation	119			119
Net loss	19,348				19,348
Ending balance (in shares) at Dec. 31, 2018		24,645,825	91,784
Ending balance at Dec. 31, 2018	$ 222,547	$ 142,655		174,379	(94,487)
Shares issued pursuant to stock-based compensation plan (in shares)	299,769
Payment-in-kind dividends (in shares)			8,544
Stock-based compensation	$ 1,359			1,359
Net loss	(103,019)				(103,019)
Ending balance (in shares) at Dec. 31, 2019		24,945,594	100,328
Ending balance at Dec. 31, 2019	$ 120,887	$ 142,655		$ 175,738	$ (197,506)

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Cash flows from operating activities
Net (loss) income	$ (103,019)	$ 19,348
Adjustments to reconcile net (loss) income to net cash provided by operating activities
Depreciation, depletion and amortization	88,618	83,582
Stock-based compensation	1,822	1,707
Stock-based payments	0	(601)
Deferred taxes	(11,440)	7,601
Loss (gain) on derivative financial instruments	30,861	(22,744)
Settlements of derivative financial instruments	(3,550)	(22,623)
Impairment of oil and natural gas properties	48,412	12,169
Loss on sale or abandonment of property and equipment	34,560	170
Non-cash interest expense	2,652	5,194
Unrealized gain on warrants	(691)	(416)
Changes in operating assets and liabilities
Accounts receivable	(4,481)	(5,391)
Prepaid expenses and other assets	(623)	(3,296)
Accounts payable and accrued expenses	(2,799)	13,372
Net cash provided by operating activities	80,322	88,072
Cash flows from investing activities
Acquisition of oil and gas properties	(5,642)	(45,539)
Development of oil and gas properties	(148,438)	(171,413)
Proceeds from Sale of Oil and Gas Property and Equipment	11,470	0
Purchases of other property and equipment	(3,682)	(2,518)
Net cash used in investing activities	(146,292)	(219,470)
Cash flows from financing activities
Proceeds from borrowings	139,000	423,745
Payments on borrowings	(75,248)	(289,520)
Repurchase and retirement of Class B Common Stock	0	(10)
Net cash provided by financing activities	63,752	134,215
Increase in cash and cash equivalents	(2,218)	2,817
Cash and cash equivalents, beginning of the period	5,355	2,538
Cash and cash equivalents, end of the period	3,137	5,355
Supplemental information:
Cash paid for taxes	38	1,242
Cash paid for interest	41,217	24,395
Non-cash investing and financing activities:
Asset retirement obligation	(440)	1,331
Increase (decrease) in liabilities for capital expenditures	$ 17,993	$ (4,603)

Basis of Presentation

Basis of Presentation	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation	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. Going Concern Assessment The Company did not satisfy the consolidated current ratio covenant under the Company’s Credit Facility (as defined below) as of the December 31, 2019 measurement date and such failure represents an event of default under the Company's revolving credit facility. The Company received a waiver for such failure but does not anticipate maintaining compliance with the consolidated current ratio covenant over the next twelve months. As the Company does not anticipate maintaining compliance with the consolidated current ratio covenant under its revolving credit facility over the next twelve months, it is evaluating the available financial alternatives, including obtaining acceptable alternative financing as well as seeking additional waivers or amendments to the covenants or other provisions of our revolving credit facility to address any future default. If, upon a future default, the Company is unable reach an agreement with its lenders or find acceptable alternative financing, the lenders under the Company's revolving credit facility may choose to accelerate repayment, which in turn may result in an event of default and an acceleration of the 11.25% Senior Notes (as defined below). If the Company's lenders or its noteholders accelerate the payment of amounts outstanding under its Credit Facility or the 11.25% Senior Notes, respectively, it does not currently have sufficient liquidity to repay such indebtedness and would need additional sources of capital to do so. The Company could attempt to obtain additional sources of capital from asset sales, public or private issuances of debt, equity or equity-linked securities, debt for equity swaps, or any combination thereof. However, the Company cannot provide any assurances that it will be successful in obtaining capital from such transactions on acceptable terms, or at all, and if the Company fails to obtain sufficient additional capital to repay the outstanding indebtedness and provide sufficient liquidity to meet its operating needs, it may be necessary for the Company to seek protection from creditors under Chapter 11 of the U.S. Bankruptcy Code (“Chapter 11”), or an involuntary petition for bankruptcy may be filed against the Company. The Company has concluded that these circumstances create substantial doubt regarding its ability to continue as a going concern. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty. Principles of Reporting and Consolidation The consolidated financial statements have been prepared using the accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America ("GAAP”) and include the accounts of Lonestar and entities in which we hold a controlling financial interest. Undivided interests in oil and gas joint ventures are consolidated on a proportionate basis. All intercompany balances and transactions have been eliminated. Use of Estimates The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Depletion of oil and gas properties and impairment of proved and unproved oil and gas properties, in part, is determined using estimates of proved oil and gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Significant estimates underlying these financial statements also include the estimated costs and timing of asset retirement obligations, the fair value of commodity derivatives, the fair value of warrants, restricted stock units and stock appreciation rights, accruals related to oil and natural gas volumes and revenues, and estimates related to income taxes. Changes in facts and circumstances or additional information may result in revised estimates, actual results may differ from these estimates. Cash Equivalents The Company considers all highly-liquid investments to be cash equivalents if they have maturities of three months or less when purchased. Concentrations and Credit Risk Lonestar's financial instruments exposed to concentrations of credit risk consist primarily of cash and cash equivalents, accounts receivable and derivative receivables (see Note 3. Commodity Price Risk Activities ). The Company places its cash and cash equivalents with reputable financial institutions. At times, the balances deposited may exceed amounts covered by insurance provided by the U.S. Federal Deposit Insurance Corporation (“FDIC”). The Company has not incurred any losses related to amounts in excess of FDIC limits. Substantially all of the Company’s accounts receivable are due from either purchasers of oil, NGL and natural gas or working interest partners in oil and natural gas wells for which a subsidiary of the Company serves as the operator. Generally, operators of oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells. The Company’s receivables are generally unsecured. For the year ended December 31, 2019, oil, NGL and natural gas revenues from Shell Trading (US) Company, Texla Energy Management, Enterprise Crude Oil LLC, Ace Gathering, Inc., GulfMark Energy, Inc. and NGL Crude Logistics LLC represented 23% , 17% , 16% , 14% , 13% and 10% , respectively, of total revenues. For the year ended December 31, 2018, oil, NGL and natural gas revenues from Enterprise Crude Oil LLC, Vitol Inc., Shell Trading (US) Company, Texla Energy Management, Inc. and NGL Crude Logistics LLC, represented 27% , 16% , 15% , 15% , and 11% , respectively, of total revenues. As of December 31, 2019, receivables relating to oil, NGL and natural gas sales from Texla Energy Management, Ace Gathering, Inc. and Shell Trading (US) Company, represented 59% , 13% and 11% of total receivables. As of December 31, 2018, receivables relating to oil, NGL and natural gas sales from Enterprise Crude Oil LLC, Phillips 66, Shell Trading (US) Company and NGL Crude Logistics LLC represented 37% , 23% , 22% , and 10% , respectively, of total receivables. Oil and Natural Gas Properties Lonestar uses the successful efforts method of accounting to account for its oil and natural gas properties. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The Company’s policy is to expense the costs of such exploratory wells if a determination of proved reserves has not been made within a 12-month period after drilling is complete. As of December 31, 2019 , the Company did not have any capitalized exploratory well costs that were pending determination of proved reserves. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred, whether productive or nonproductive. Capitalized costs attributed to the proved properties are subject to depreciation and depletion. Depreciation and depletion of the cost of oil and gas properties is calculated using the units-of-production method aggregating properties on a field basis. For leasehold acquisition costs and the cost to acquire proved properties, the reserve base used to calculate depreciation and depletion is the sum of proved developed reserves and proved undeveloped reserves. For well costs, the reserve base used to calculate depletion and depreciation is proved developed reserves only. Unproved properties consist of costs incurred to acquire unproved leases. Unproved lease acquisition costs are capitalized until the leases expire or when the Company specifically identifies leases that will revert to the lessor, at which time the Company expenses the associated unproved lease acquisition costs. The expensing of the unproved lease acquisition costs is recorded as an impairment of oil and gas properties in the consolidated statement of operations, as applicable. Unproved oil and gas property costs are transferred to proven oil and gas properties if the properties are subsequently determined to be productive or are assigned proved reserves. Unproved oil and gas properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, future plans to develop acreage, and other relevant factors. On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and any gain or loss is recognized. On the sale or retirement of a partial unit of a proved property, a pro-rata portion of the cost and related accumulated depreciation, depletion and amortization may be eliminated from the property accounts if the field depletion rate is significantly altered. Other Property and Equipment Other property and equipment, consisting primarily of office, transportation and computer equipment, as well as our new corporate headquarters, is carried at cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets, ranging from 3 to 5 years , with the exception of our corporate headquarters, which is 30 years . Major renewals and improvements are capitalized, while expenditures for maintenance and repairs are expensed as incurred. Upon sale or abandonment, the cost of the equipment and related accumulated depreciation are removed from the accounts, and any gain or loss is recognized. Impairment of Long-Lived Assets The carrying value of long-lived assets and certain identifiable intangibles are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. When it is determined that the estimated future net cash flows of an asset will not be sufficient to recover its carrying amount, an impairment loss must be recorded to reduce the carrying amount to its estimated fair value. Judgments and assumptions are inherent in management’s estimate of undiscounted future cash flows and an asset’s fair value. These judgments and assumptions include such matters as the estimation of oil and gas reserve quantities, risks associated with the different categories of oil and gas reserves, the timing of development and production, expected future commodity prices, capital expenditures, production costs, and appropriate discount rates. The Company evaluates impairment of proved and unproved oil and gas properties on a region basis. On this basis, certain regions may be impaired because they are not expected to recover their entire carrying value from future net cash flows. As a result of this evaluation, the Company recorded impairment of unproved oil and gas properties of approximately $14.5 million and $12.2 million for the years ended December 31, 2019 and 2018 , respectively, and impairment of proven oil and gas properties of $33.9 million for the year ended December 31, 2019. If pricing remains depressed, it is reasonably likely that the Company may have to record impairment of its oil and gas properties subsequent to December 31, 2019 . Asset Retirement Obligations Asset retirement obligations are recognized at their fair value at the time that the obligations are incurred. Oil and gas producing companies incur such a liability upon acquiring or drilling a well. Under ASC 410, an asset retirement obligation is recorded as a liability at its estimated present value at the asset’s inception, with an offsetting increase to producing properties in the accompanying consolidated balance sheets, which is allocated to expense over the useful life of the asset. Periodic accretion of the discount on asset retirement obligations is recorded as part of depreciation, depletion and amortization ("DD&A") expense in the accompanying consolidated statement of operations. See Note 7. Asset Retirement Obligations , for more information. Revenue Recognition Lonestar recognizes revenue at an amount that reflects the consideration to which we expect to be entitled in exchange for transferring goods or services to a customer, using a five-step process, in accordance with ASC 606, Revenue from Contracts with Customers. See Note 5. Revenue Recognition . Derivatives The Company utilizes oil and natural gas derivative contracts to mitigate its exposure to commodity price risk associated with its future oil and natural gas production. These derivative contracts have historically consisted of fixed-price swaps, basis swaps, and collars. We do not apply hedge accounting; accordingly, all derivatives are recorded in the accompanying consolidated balance sheets at estimated fair value. The Company recognizes all changes in the fair values of its derivative contracts as gains or losses in the earnings of the periods in which they occur. See Note 3. Commodity Price Risk Activities for more information. Income Taxes Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, operating losses and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which these temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. The Company periodically evaluates the realizable tax benefits of deferred tax assets and records a valuation allowance, if required, based on an estimate of the amount of deferred tax assets the Company believes does not meet the more likely than not criteria of being realized. See Note 10. Income Taxes for more information. The Company evaluates uncertain tax positions, which requires significant judgments and estimates regarding the recoverability of deferred tax assets, the likelihood of the outcome of examinations of tax positions that may or may not be currently under review, and potential scenarios involving settlements of such matters. Changes in these estimates could materially impact the consolidated financial statements. No liability for material uncertain tax positions existed as of December 31, 2019 or 2018 . Share-Based Payments Lonestar accounts for equity-based awards in accordance with ASC 718, Compensation-Stock Compensation, which requires companies to recognize in the statement of operations all share-based payments granted to employees based on their fair value. Share-based compensation is recognized by the Company on the graded vesting method over the requisite service period, which approximates the option vesting period of three years . Grants that can be settled in either cash or shares are treated as liabilities on the accompanying consolidated balance sheets. Net (Loss) Income 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 (loss) income 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. The following is a reconciliation of basic and diluted earnings per share: In thousands, except shares and per-share data Year ended December 31, 2019 2018 Numerator - Basic Total net (loss) income attributable to common stockholders $ (111,563 ) $ 11,532 Less: allocation to participating securities — (4,270 ) Net (loss) income allocated to common stockholders - basic $ (111,563 ) $ 7,262 Numerator - Diluted Net (loss) income allocated to common stockholders - basic $ (111,563 ) $ 7,262 Unrealized gain on Warrants, net of income tax — (329 ) Net (loss) income allocated to common stockholders - diluted $ (111,563 ) $ 6,933 Denominator Weighted average number of common shares - basic 24,875,793 24,619,730 Warrants converted under the Treasury Stock method — 181,413 Weighted average number of common shares - diluted 24,875,793 24,801,143 Earnings per share Basic $ (4.48 ) $ 0.29 Diluted $ (4.48 ) $ 0.28 The following weighted average securities could potentially dilute earnings per share for the periods indicated, but were excluded from the computation of diluted net (loss) income per share, as their effect would have been antidilutive: Year ended December 31, 2019 2018 Preferred stock 15,828,683 14,480,730 Warrants 760,000 — Stock appreciation rights 1,010,000 922,945 Restricted stock units 1,555,676 847,542 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. The Company adopted these standards on January 1, 2019. See Note 4. Leases for more information.

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2019
Business Combinations [Abstract]
Acquisitions and Divestitures	Acquisitions and Divestitures Pirate Divestiture On March 22, 2019, Lonestar completed the divestiture of its Pirate assets in Wilson County for an adjusted cash purchase price of $11.5 million , after closing adjustments, to a private third-party. The assets were comprised of 3,400 net undeveloped acres, six producing wells, held seven proved undeveloped locations as of the closing date, and were producing approximately 200 BOE/d. 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 the Company's Credit Facility, as well as cash from operations. The Sooner Acquisition was accounted for as an asset acquisition. 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, Lonestar closed on the purchase of an office building in Fort Worth, Texas, with an acquisition price approximating $10 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 Other Expense 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 .

Commodity Price Risk Activities

Commodity Price Risk Activities	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity Price Risk Activities	Commodity Price Risk Activities Lonestar enters into certain commodity derivative instruments to mitigate commodity price risk associated with a portion of its future oil and natural gas production and related cash flows. The oil and natural gas revenues and cash flows are affected by changes in commodity product prices, which are volatile and cannot be accurately predicted. The objective for entering into these commodity derivatives is to protect the operating revenues and cash flows related to a portion of the future oil and natural gas sales 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 December 31, 2019, the Company had no open physical delivery obligations. The following table summarizes Lonestar's commodity derivative contracts as of December 31, 2019: Contract Volume Hedged Weighted Commodity Type Period Range (1) (Bbls/Mcf per day) Average Price Oil – WTI Swaps Jan - June 2020 $48.90 - $65.56 7,393 $ 56.51 Oil – WTI Swaps July - Dec 2020 51.60 - 65.56 7,565 57.38 Oil - WTI Swaps Jan - Dec 2021 51.05 - 56.50 4,000 53.93 Natural Gas - Henry Hub Swaps Jan - Dec 2020 2.38 - 2.80 20,000 2.58 (1) Ranges presented for fixed-price swaps and basis swaps represent the lowest and highest fixed prices of all open contracts for the period presented. During January 2020, the Company entered into additional WTI swaps for 365,000 Bbls ( 1,000 Bbls per day) at an average strike price of $55.05 per Bbl for the period of January through December 2021. During March 2020, the Company entered into additional WTI swaps for 730,000 Bbls ( 2,000 Bbls per day) at an average strike price of $41 for the period of January through December 2021 and entered into additional Henry Hub swaps for 10,037,500 Mcf ( 27,500 Mcf per day) at an average strike price of $2.36 per Mcf. During March 2020, the Company entered into one-month LIBOR interest rate swaps for $190 million of notional amount at a rate of 0.68% for the period of March 2020 through March 2023. The interest rate swaps were entered into to hedge variable interest rate changes associated with our Credit Line. See Note 9. Long-Term Debt for more information on the Credit Line's interest terms. As of December 31, 2019, all of the Company’s 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. None of the Company’s derivative instruments contain credit-risk related contingent features.

Leases

Leases	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Leases	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. Adoption of this standard resulted in the recording of net operating lease ROU assets and corresponding operating lease liabilities of $0.3 million with no impact to retained earnings as of January 1, 2019. 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 consolidated balance sheet as of December 31, 2019. The current portion of operating lease liabilities are presented within Accrued Liabilities, and the non-current portion of operating lease liabilities are presented within Other Non-Current Liabilities on the consolidated balance sheet. Operating lease ROU assets and operating lease liabilities are recognized based on the present value of the future minimum lease payments over the lease term at commencement date. As most of the Company's leases do not provide an implicit rate, the Company uses an incremental collateralized borrowing rate based on the information available at commencement date, including lease term, in determining the present value of future payments. The operating lease ROU asset also includes any lease payments made and excludes lease incentives and initial direct costs incurred. The Company's lease terms may include options to extend or terminate the lease when it is reasonably certain that the option will be exercised. Operating lease expense is recognized on a straight-line basis over the lease term. The Company's operating lease portfolio includes field equipment such as compressors and amine units, office space and office equipment. The Company currently does not have any financing leases. Our compressor and amine unit arrangements are typically structured with a non-cancelable primary term of one to two -years and continue thereafter on a month-to-month basis subject to termination by either party with thirty days notice. The Company's compressor and amine unit rental agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. Upon completion of the primary term, both parties have substantive rights to terminate the lease. As a result, enforceable rights and obligations do not exist under the rental agreement subsequent to the primary term. The Company enters into daywork contracts for drilling rigs with third parties to support its drilling activities. The drilling rig arrangements are typically structured with a term that is in effect until drilling operations are completed on a contractually-specified well or well pad. Upon mutual agreement with the contractor, the Company typically has the option to extend the contract term for additional wells or well pads by providing thirty days notice prior to the end of the original contract term. Drilling rig arrangements represent short-term operating leases. The accounting guidance requires the Company to make an assessment at contract commencement if it is reasonably certain that it will exercise the option to extend the term. Due to the continuously evolving nature of the Company's drilling schedules and the potential volatility in commodity prices in an annual period, the Company's strategy to enter into shorter term drilling rig arrangements allows it the flexibility to respond to changes in our operating and economic environment. The Company exercises its discretion in choosing to extend or not extend contracts on a rig-by-rig basis depending on the conditions present at the time the contract expires. At the time of contract commencement, the Company has determined it cannot conclude with reasonable certainty if it will choose to extend the contract beyond its original term. Pursuant to the successful efforts method of accounting, these costs are capitalized as part of natural gas and oil properties on our balance sheet when paid. The Company leases a small part of the corporate building it owns to a third-party, with a lease term that ends in 2023 and is non-cancelable. Third-party leasing income is insignificant and is included in Acquisition Costs and Other on the consolidated statements of operations. The components of our total lease expense for the year ended December 31, 2019 are as follows: In thousands Year ended December 31, 2019 Operating Leases $ 273 Short-term leases (1) 2,766 Total lease expense $ 3,039 Short-term lease costs capitalized to oil and gas properties (2) $ 11,747 (1) Short-term leases represent expenses related to leases with a contract term of one year or less. The majority of these leases relate to field operating equipment and are included in lease operating and gas gathering expense on the consolidated statement of operations. (2) Short-term lease costs represent leases with a contract term of one year or less, the majority of which are related to drilling rigs and are capitalized as part of Oil and Gas Properties on the consolidated balance sheets. Supplemental balance sheet information related to leases follows: In thousands, except lease term and discount rate data December 31, 2019 Operating leases Assets Other property and equipment $ 45 Liabilities Accrued liabilities $ 45 Weighted-average remaining lease term (years) 0.2 Weighted-average discount rate 5.0 % Supplemental cash flow information related to leases follows: In thousands Year ended December 31, 2019 Cash paid for amounts included in the measurement of lease liabilities Operating cash flows for operating leases $ 273 Right-of-use assets obtained in exchange for lease obligations: Operating leases $ 273 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 December 31, 2019: In thousands Operating Leases 2020 $ 45 Thereafter — Total minimum lease payments 45 Amount of lease payments representing interest — Present value of future minimum lease payments $ 45 The table below summarizes by year the remaining non-cancelable future lease payments under our leases, as accounted for under previous accounting guidance as of December 31, 2018, a majority of which represents lease payments on our old corporate office space which was impaired in 2018: In thousands Amount 2019 $ 422 2020 477 2021 368 Total minimum lease payments $ 1,267

Revenue Recognition

Revenue Recognition	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Revenue Recognition	Revenue Recognition Operating revenues are comprised of sales of crude oil, NGLs and natural gas. Revenue is recognized when performance obligations under the terms of a contract with a customer are satisfied. The Company recognizes revenue when control has been transferred to the customer, generally at the time commodities reach an agreed-upon delivery point. Revenue is measured as the amount of consideration the Company expects to receive in exchange for transferring products and is generally based upon a negotiated formula, list or fixed price based on a market index. Typically, the Company sells its products directly to customers generally under agreements with payment terms less than 30 days. Oil Revenues Oil is sold at a contractually-specified index price plus or minus a differential; title and control of the product generally transfers at the delivery point specified in the contract, at which point related revenue is recognized. For those leases in which Lonestar operates with other working interest owners, the Company recognizes oil revenue proportionate to its entitled share of volumes sold. Currently, all of Lonestar’s oil production comes from the Eagle Ford Shale play in South Texas, and direct sales to four purchasers account for the majority of its oil sales. The Company’s oil purchase contracts are generally written to provide month-to-month terms with a 30-day cancellation notice. Sales of Lonestar’s oil production are typically invoiced monthly based on actual volumes measured at the agreed-upon delivery point and stated contract pricing for the month. NGLs and Natural Gas Revenues The Company’s NGL and natural gas purchase contracts are generally structured such that Lonestar commits and dedicates for sale a specified volume of NGL and/or natural gas production per day from agreed-upon leases to a purchaser. NGLs and natural gas are sold at a percentage of index prices of each component less any stated deductions. Control transfers at the delivery point specified in the contract, which typically is stated as the inlet or tailgate of a plant where the produced NGLs and natural gas are processed for subsequent transportation and consumption. In certain situations, Lonestar takes processed natural gas in-kind from a processing plant for sale under a separate purchase agreement with a different delivery point. The stated delivery point determines whether certain conditioning, treating, transportation and fractionation fees associated with the sold NGLs and natural gas are treated as operating expenses (occurring before the delivery point) or as deductions to revenues (occurring after the delivery point). For those leases in which Lonestar operates with other working interest owners, the Company recognizes NGL and natural gas revenue proportionate to its entitled share of volumes sold. Currently, all of Lonestar’s NGL and natural gas production comes from the Eagle Ford Shale play in South Texas. Sales of Lonestar’s NGL and natural gas production is typically invoiced monthly based on actual volumes at the agreed-upon delivery point and stated contract pricing and allocations for the month. Lonestar uses a third-party broker for its NGL and natural gas marketing. In this capacity, the third-party is responsible for carrying out marketing activities such as submission of nominations, receipt of payments, submission of invoices and negotiation of contracts. In this agreement, Lonestar retains final approval of contracts and is not entitled to sales proceeds from the third-party until they are collected from the related purchasers. Commissions payable to the third-party broker for these services are treated as operating expenses in the financial statements. Production Imbalances Revenue is recorded based on the Company’s share of volumes sold, regardless of whether the Company has taken its proportional share of volumes produced. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. There were no imbalances at December 31, 2019 and 2018. 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 years ended December 31, 2019 and 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. 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.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Fair Value Measurements	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. Assets and liabilities measured at fair value on a recurring basis The following table presents Lonestar's assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2019 and 2018: Fair Value Measurements Using In thousands Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total December 31, 2019 Assets: Commodity derivatives $ — $ 6,849 $ — $ 6,849 Liabilities: Commodity derivatives — (10,462 ) — (10,462 ) Warrants — — (364 ) (364 ) Stock-based compensation (1,792 ) — (573 ) (2,365 ) Total $ (1,792 ) $ (3,613 ) $ (937 ) $ (6,342 ) December 31, 2018 Assets: Commodity derivatives $ — $ 23,143 $ — $ 23,143 Liabilities: Commodity derivatives — (451 ) — (451 ) Warrants — — (1,055 ) (1,055 ) Stock-based compensation (1,267 ) — (636 ) (1,903 ) Total $ (1,267 ) $ 22,692 $ (1,691 ) $ 19,734 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 12. Stock-Based Compensation below for more information. Level 3 gains and losses The table below sets forth a summary of changes in the fair value of the Company’s Level 3 liabilities for the year ended December 31, 2019. In thousands Warrant Stock-Based Compensation Total Balance at December 31, 2018 $ (1,055 ) $ (636 ) $ (1,691 ) Unrealized gains 691 63 754 Balance at December 31, 2019 $ (364 ) $ (573 ) $ (937 ) Assets and liabilities measured at fair value on a nonrecurring basis Non-recurring fair value measurements include certain non-financial assets and liabilities as may be acquired in a business combination and thereby measured at fair value; impaired oil and natural gas property assessments; warrants issued in debt or equity offerings and the initial recognition of asset retirement obligations for which fair value is used. These estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, the Company has designated these estimates as Level 3. Other fair value measurements The book values of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term nature of these instruments. The carrying value of debt approximates fair value since it is subject to a short-term floating interest rate that approximates the rate available to the Company, except for bonds, which are recorded at amortized cost less debt issuance costs. The fair value of the 11.25% Senior Notes (as defined in Note 9. Long-Term Debt below) was approximately $173 million as of December 31, 2019, and are considered a Level 3 liability, as they are based on market transactions that occur infrequently as well as internally generated inputs.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations Lonestar recognizes its asset retirement obligations related to the plugging, abandonment and remediation of oil and gas producing properties. The present value of the estimated asset retirement costs has been capitalized as part of the carrying amount of the related long-lived assets. The liability has been accreted to its present value as of December 31, 2019 . The Company evaluated its wells and has determined a range of abandonment dates through December 2069. The following provides a reconciliation of activity in the asset retirement obligations for the years ended December 31, 2019 and 2018: Year Ended December 31, In thousands 2019 2018 Beginning asset retirement obligations $ 7,195 $ 5,649 Wells drilled during the year 26 408 Wells acquired during the year — 223 Wells sold during the year (388 ) — Accretion expense 300 215 Revisions in estimated retirement obligations (1) 191 790 Wells plugged and abandoned during the year (269 ) (90 ) Ending asset retirement obligations $ 7,055 $ 7,195 (1) Revisions of previous estimates during the year ended December 31, 2019 are primarily attributable to changes in estimates of the timing of future costs for oilfield services required to plug and abandon wells.

Accrued Liabilities

Accrued Liabilities	12 Months Ended
	Dec. 31, 2019
Payables and Accruals [Abstract]
Accrued Liabilities	Accrued Liabilities The following table provides detail of Lonestar's accrued liabilities as of December 31, 2019 and 2018: December 31, In thousands 2019 2018 Bonus payable $ 2,353 $ 3,244 Accrued interest - 11.25% Senior Notes 14,063 14,063 Accrued well costs 8,932 9,026 Other 1,557 1,795 Total accrued liabilities $ 26,905 $ 28,128

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt The following long-term debt obligations were outstanding as of December 31, 2019 and 2018: December 31, In thousands 2019 2018 Senior Secured Credit Facility $ 247,000 $ 183,000 11.25% Senior Notes due 2023 250,000 250,000 Mortgage debt 8,931 9,151 Other 271 275 Total 506,202 442,426 Less unamortized discount (3,375 ) (4,500 ) Less unamortized debt issuance costs (759 ) (1,044 ) Total net of discount and debt issuance costs 502,068 436,882 Less current obligations (1) (247,000 ) — Long-term debt $ 255,068 $ 436,882 (1) Current obligations represent the Senior Secured Credit Facility obligations which were classified as current liabilities as of December 31, 2019. See Waiver and Eleventh Amendment below for further discussion. 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 December 31, 2019, $247.0 million was borrowed under the Credit Facility, and the weighted average interest rate on borrowings under the Credit Facility for the year was 5.28% . Borrowing availability was $42.6 million as of December 31, 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 December 31, 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 and the next borrowing base redetermination will be May 1, 2020. Given current market conditions, it is reasonably possible that the borrowing base will decrease as a result of this next redetermination, which could lead to a deficiency and require the Company to prepay the deficiency over six months beginning within 45 days of the election notice. Borrowings under the Credit Facility, at Lonestar's election, bear interest at either: (i) an alternate base rate (“ABR”) equal to the higher of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.5% per annum, and (c) the adjusted LIBO rate of a three-month interest period on such day plus 1.0% ; or (ii) the adjusted LIBO rate, which is the rate stated on Reuters screen LIBOR1 page, for one, two, three, six or twelve months, as adjusted for statutory reserve requirements for Eurocurrency liabilities, plus, in each of the cases described in clauses (i) and (ii) above, an applicable margin ranging from 1.0% to 2.0% for ABR loans and from 2.0% to 3.0% for adjusted LIBO rate loans. Subject to certain permitted liens, the Company's obligations under the Credit Facility have been secured by the grant of a first priority lien on no less than 80% of the value of the proved oil and gas properties of the Company and its subsidiaries ( 90% at December 31, 2019). The Credit Facility contains certain financial performance covenants, as defined in the Credit Facility, including the following: • A maximum debt to EBITDAX ratio of 4.0 to 1.0, and • A current ratio of not less than 1.0 to 1.0. The Company was not in compliance with the terms of the Credit Facility as of December 31, 2019 because the Company did not satisfy the consolidated current ratio at that time and the audit report corresponding to these financial statements includes an explanatory paragraph expressing uncertainty as to our ability to continue as a “going concern.” Such failures represent defaults under our revolving credit facility which we received a Waiver for (see below). Seventh Amendment In January 2018, the Company entered into the Limited Waiver, Borrowing Base Redetermination Agreement, and Amendment No. 7 to the Credit Agreement (the "Seventh Amendment"), which (i) maintained the borrowing base of $160 million until the next redetermination date; (ii) waived the borrowing base redetermination that would otherwise have occurred in connection with the incurrence of the 11.25% Senior Notes (see below), and (iii) amended certain other provisions of the Credit Facility. Eighth Amendment In May 2018, the Company entered into the Borrowing Base Redetermination Agreement and Amendment No. 8 to Credit Agreement (the "Eighth Amendment"), which (i) increased the borrowing base from $160 million to $190 million and (ii) reallocated the commitments and outstanding loans among lenders. Ninth Amendment In November 2018, the Company entered into the Ninth Amendment and Joinder (the "Ninth Amendment"), which (i) increased the borrowing base from $190 million to $275 million ; (ii) extended the maturity date of the Credit Facility to November 15, 2023, and (iii) amended certain other provisions of the Credit Facility. Tenth Amendment 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. Waiver and Eleventh Amendment The Company entered into the Limited Waiver and Eleventh Amendment to Credit Agreement (the “Waiver”), effective as of April 7, 2020, with certain lenders and Citibank, N.A., as administrative bank, to waive the events of default arising from our failure to comply with the consolidated current ratio as of December 31, 2019, to timely provide audited financial statements, and to provide financial statements that are not subject to any “going concern” or like qualification or exception for the fiscal year ended December 31, 2019. Although the Company has entered into the Waiver, there is no guarantee that the Company's lenders will agree to waive events of default or potential events of default in the future. Accordingly, the amount outstanding under the Credit Facility as of December 31, 2019 has been classified as current on the accompanying Consolidated 2019 Balance Sheet. 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 merge, or sell substantially all of the Company’s assets. The indenture also contains cross-default provisions for defaults of the Company's other debt instruments, including the Credit Facility, caused by payment default or events which cause the acceleration of repayment prior to the stated maturity of such instrument. 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 December 31, 2019 and 2018, the Company had approximately $0.7 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. Indebtedness Repayment Schedule As of December 31, 2019, our debt is payable over the next five years and thereafter as follows: In thousands 2020 $ 247,084 2021 71 2022 76 2023 250,081 2024 86 Thereafter 8,804 Total debt $ 506,202

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The income tax provision is as follows: Year Ended December 31, In thousands 2019 2018 Current income tax (benefit) expense Federal $ (591 ) $ (1,100 ) State (464 ) 291 Total current income tax benefit (1,055 ) (809 ) Deferred tax (benefit) expense Federal (20,989 ) 7,686 State 673 (85 ) Valuation allowance 8,876 — Total deferred income tax (benefit) expense (11,440 ) 7,601 Total income tax (benefit) expense $ (12,495 ) $ 6,792 The following table provides a reconciliation of Lonestar's actual income tax provision amounts from the expected income tax provision amount by applying the U.S. federal statutory corporate income tax rate of 21% for the years ended December 31, 2019 and 2018, respectively: Year Ended December 31, In thousands 2019 2018 Expected income tax expense (benefit) at statutory rate $ (24,258 ) $ 5,489 Permanent differences (48 ) 123 Return to provision adjustment 2,567 1,119 Change in valuation allowance 8,876 — Other 368 61 Actual income tax (benefit) expense $ (12,495 ) $ 6,792 Significant components of the Company's deferred tax assets and liabilities as of December 31, 2019 and 2018 are as follows: December 31, In thousands 2019 2018 Deferred tax assets Net operating loss carryforward $ 27,025 $ 17,765 Stock-based compensation 922 1,973 Intangibles 257 304 Derivative instruments 606 — Interest expense limitation 19,243 2,254 Organizational expenses and other 3,306 4,477 Total deferred tax assets $ 51,359 $ 26,773 Deferred tax liabilities Oil and gas properties, and other property and equipment, principally due to intangible drilling costs $ (43,414 ) $ (34,332 ) Derivative instruments — (4,811 ) Net deferred tax assets (liabilities) 7,945 (12,370 ) Valuation allowance for deferred tax assets (8,876 ) — Net deferred tax liability, net of valuation allowance $ (931 ) $ (12,370 ) The net operating loss carryforward as of December 31, 2019, approximates $128.6 million and begins to expire in 2030 with the exception of $49.9 million related to fiscal years 2018 and 2019, which has no expiration, however, they are limited to usage of 80% of income. On December 22, 2016, the Company completed a public offering of 13.8 million of its Class A common stock. A change of ownership, as defined under the provisions of IRC Section 382 occurred on this date. As a result, a portion of our net operating loss and tax credit carryforwards will be limited in future periods. IRC Section 382 places limitations on the amount of taxable income which may be offset by tax carryforward attributes, such as net operating losses or tax credits after a change of ownership event. As a result of this ownership change, certain of our accumulated net operating losses will be subject to an annual limitation regarding their utilization against taxable income in future periods. The 2016 change creates an estimated annual utilization limit of approximately $1.0 million on our ability to utilize net operating losses generated prior to the ownership change event. Built-in gains associated with our deferred tax attributes on the date of the ownership change may increase the net operating loss utilization limit in future periods, allowing additional utilization of net operating losses generated prior to the date of the ownership change. Due to the ownership change and the resulting limitation on the utilization of net operating loss generated prior to the change, an estimated $141.7 million of the net operating loss carryforwards were written off in 2016. As of December 31, 2019, the Company has approximately $8.7 million of percentage depletion carryover which has no expiration. On June 15, 2017, the Company entered into an amended and restated purchase agreement with Chambers Energy Capital III, LP (“Chambers”) where the Company closed transactions issuing Chambers 5,400 shares of Series A-1 Preferred Stock and 74,600 shares of Series A-2 Preferred Stock. These transactions created an additional change of ownership under the provision of Section 382 of the IRC. The 2017 change creates an additional estimated annual utilization limit of approximately $0.8 million on our ability to utilize net operating losses generated subsequent to the 2016 change in ownership, but prior to the June, 2017 change in ownership. If the Company were to experience another ownership change in future periods, the net operating loss carryforwards may be subject to additional utilization limits. The Company files income tax returns in the United States federal jurisdiction and in various state jurisdictions. As of December 31, 2019 , there are no examinations of federal or state jurisdictions in progress. The Company’s income tax returns related to fiscal years ended December 31, 2010 through 2019 remain open to possible examination by the tax authorities. The Company has not recorded any interest or penalties associated with uncertain tax positions. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to reverse. The Company's deferred tax assets exceeded its deferred tax liabilities at December 31, 2019 primarily due to tax consequences of the impairment of the Company's Brazos properties during the fourth quarter; as a result, the Company established a valuation allowance against most of the deferred tax assets during the fourth quarter of 2019. With the exception of a $0.6 million deferred tax asset retained for existing refundable AMT credit carryovers (see below), the Company retained a full valuation allowance of $8.9 million at December 31, 2019 due to uncertainties regarding the future realization of its deferred tax assets. The valuation allowance will continue to be recognized until the realization of future deferred tax benefits is determined to be more likely than not. The Company recorded a deferred tax liability of $1.5 million at December 31, 2019 related to State taxes. As of December 31, 2019 , the Company had AMT credit carryovers of $0.6 million that are expected to be fully refunded by 2022 . The deductibility of interest expense for tax years beginning in January 1, 2018 has been limited to 30% of earnings before interest, taxes, depreciation, and amortization for the four years ending 2021. Deductibility of interest expense for tax years beginning in January 1, 2022 will then be limited to 30% of earnings before interest and taxes thereafter. For the years ended December 31, 2019 and 2018, our deductible interest expense was limited which resulted in a $19.2 million and $2.3 million deferred tax asset, respectively.

Stockholders_ Equity

Stockholders’ Equity	12 Months Ended
	Dec. 31, 2019
Equity [Abstract]
Stockholders’ Equity	Stockholders’ Equity Series A 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”). As a result of stockholder approval obtained in November 2017, all outstanding Series A-2 Preferred Stock was converted to Series A-1 Preferred 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 (two of which remain as of December 31, 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 all four 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 8,544 additional shares of Series A-1 Preferred Stock. The Company expects to elect the PIK Option for the foreseeable future. Repurchase and Retirement of Class B Common Stock In connection with the EF Realisation liquidation in October 2018 (see Note 13. Related Party Activities ), 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 in September 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.

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2019
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-Based Compensation	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 years ended December 31, 2019 and 2018, the Company recognized $ 2.6 million and $1.6 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 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 December 31, 2019 and 2018 was $ 1.8 million and $1.3 million , respectively. As of December 31, 2019, there was $ 3.0 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 1.9 years . The fair value of RSU grants that vested during 2019 and 2018 totaled $ 2.1 million and $1.3 million, respectively. A summary of the status of the Company's non-vested RSU grants issued, and the changes during the year ended December 31, 2019, is presented below: Shares Weighted Average Fair Value per Share Outstanding non-vested RSUs at December 31, 2018 1,011,045 $ 5.06 Granted 1,300,003 3.40 Vested (450,422 ) 4.56 Forfeited (10,950 ) — Outstanding non-vested RSUs at December 31, 2019 1,849,676 $ 4.04 Stock Appreciation Rights Lonestar grants 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 is generally 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 years ended December 31, 2019 and 2018, the Company recognized $ (0.1) million and $0.3 million, respectively, of stock-based compensation expense for SARs. The liability for SARs on the accompanying consolidated balance sheet as of December 31, 2019 and 2018 was approximately $ 0.6 million and $0.6 million , respectively. As of December 31, 2019, there was $ 0.1 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 0.7 years . 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 — — 0 Outstanding at December 31, 2019 1,010,000 $ 6.30 2.5 SARs vested and exercisable at December 31, 2019 606,250 $ 6.65 2.4

Related Party Activities

Related Party Activities	12 Months Ended
	Dec. 31, 2019
Related Party Transactions [Abstract]
Related Party Activities	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, the Company 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 through a common stock offering, which closed in December 2016. 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. 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 $1.7 million and $1.8 million for the years ended December 31, 2019 and 2018, respectively. In February 2019, the Company purchased a property adjacent to its corporate office for approximately $2.0 million. The transaction was funded with cash from operations. The seller of the property is indebted to certain trusts established in favor of the children of one of the Company's directors. The Company understands that the seller may have used some of the proceeds of the sale to satisfy such outstanding indebtedness, though the Company had no interest or influence over any particular outcome. The Company is party to a Joint Operating Agreement ("JOA") with a related party through common investors. The amounts owed the Company by the related party under the JOA are reflected as accounts receivable related party on the accompanying 2019 Consolidated Balance Sheet.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Litigation Lonestar is subject to certain claims and litigation arising in the normal course of business. In the opinion of management, the outcome of such matters will not have a materially adverse effect on the consolidated results of operations or financial position of the Company. Environmental Remediation Various federal, state, and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect the Company’s operations and the costs of its oil and gas exploration, development and production operations. The Company does not anticipate that it will be required in the near future to expend significant amounts in relation to the consolidated financial statements taken as a whole by reason of environmental laws and regulations, and appropriately no reserves have been recorded. Significant Contracts Lonestar has one drilling rig under contract which provides for a drilling rate of $19.0 thousand per day, and expires on September 7, 2020. Should the Company terminate the contract early, the early termination fee totals $15.0 thousand per day times the remaining number of days left on the contract after the termination date. 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.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2019
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events COVID-19 and Commodity Prices On January 30, 2020, the World Health Organization (“WHO”) announced a global health emergency because of a new strain of coronavirus (“COVID-19”) and the risks to the international community as the virus spreads globally beyond its point of origin. In March 2020, the WHO classified the COVID-19 as a pandemic, based on the rapid increase in exposure globally. In addition, in March 2020, members of OPEC failed to agree on production levels which is expected to cause an increased supply and has led to a substantial decrease in oil prices and an increasingly volatile market. Subsequent to December 31, 2019 the price of both oil and gas has decreased primarily as a result of oil demand concerns due to the economic impacts of the COVID-19 virus and anticipated increases in supply from Russia and OPEC, particularly Saudi Arabia. Declines in oil and natural gas prices affect the Company's liquidity to the extent that the Company's commodity hedges do not protect its cash flows from such price declines. Additionally, if oil or natural gas prices remain depressed or continue to decline the Company may be required to record oil and gas property write-downs. Consumer demand has decreased since the spread of the COVID-19 outbreak and new travel restrictions placed by governments in an effort to curtail the spread of the coronavirus. The full impact of the coronavirus and the decrease in oil prices continue to evolve as of the date of this report. As such, it is uncertain as to the full magnitude that they will have on the Company’s financial condition, liquidity and future results of operations. Management is actively monitoring the global situation and the impact or adverse effect on the Company’s results of future operations, financial position, and liquidity in fiscal year 2020. Due to the recent oil price volatility, the Company recently reduced its 2020 capital spending program by approximately 25% and will continue to evaluate going forward as conditions warrant. Gonzales County AMI In February 2020, the Company announced that it had entered into a Joint Development Agreement (the "JDA") in Gonzales County with one of the largest producers in the Eagle Ford which encompass an Area of Mutual Interest (the "AMI") totaling approximately 15,000 acres. The agreement calls for Lonestar to operate a minimum of three to four Eagle Ford Shale wells annually on behalf of the two companies through 2022 that are intended to hold-by-production approximately 6,000 gross acres within the AMI. The agreement gives Lonestar's partner the option to participate in each well with a 50% working interest or to participate via a carried working interest that ranges from approximately 9 to 17% , depending on location. Preferred Stock Dividend On March 16, 2020, the Company approved a dividend with respect to the Company’s Series A-1 Preferred Stock. Chambers, as the holder of A-1 Preferred Stock as of March 16, 2020, received an aggregate of 2,257 additional shares of A-1 Preferred Stock as a dividend for its A-1 Preferred Stock on March 31, 2020.

Basis of Presentation (Policies

Basis of Presentation (Policies)	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Principles of Reporting and Consolidation	Principles of Reporting and Consolidation The consolidated financial statements have been prepared using the accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America ("GAAP”) and include the accounts of Lonestar and entities in which we hold a controlling financial interest. Undivided interests in oil and gas joint ventures are consolidated on a proportionate basis. All intercompany balances and transactions have been eliminated.
Use of Estimates	Use of Estimates The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Depletion of oil and gas properties and impairment of proved and unproved oil and gas properties, in part, is determined using estimates of proved oil and gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Significant estimates underlying these financial statements also include the estimated costs and timing of asset retirement obligations, the fair value of commodity derivatives, the fair value of warrants, restricted stock units and stock appreciation rights, accruals related to oil and natural gas volumes and revenues, and estimates related to income taxes. Changes in facts and circumstances or additional information may result in revised estimates, actual results may differ from these estimates.
Cash Equivalents	Cash Equivalents The Company considers all highly-liquid investments to be cash equivalents if they have maturities of three months or less when purchased
Concentrations and Credit Risk	Concentrations and Credit Risk Lonestar's financial instruments exposed to concentrations of credit risk consist primarily of cash and cash equivalents, accounts receivable and derivative receivables (see Note 3. Commodity Price Risk Activities ). The Company places its cash and cash equivalents with reputable financial institutions. At times, the balances deposited may exceed amounts covered by insurance provided by the U.S. Federal Deposit Insurance Corporation (“FDIC”). The Company has not incurred any losses related to amounts in excess of FDIC limits. Substantially all of the Company’s accounts receivable are due from either purchasers of oil, NGL and natural gas or working interest partners in oil and natural gas wells for which a subsidiary of the Company serves as the operator. Generally, operators of oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells. The Company’s receivables are generally unsecured.
Oil and Natural Gas Properties	Oil and Natural Gas Properties Lonestar uses the successful efforts method of accounting to account for its oil and natural gas properties. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The Company’s policy is to expense the costs of such exploratory wells if a determination of proved reserves has not been made within a 12-month period after drilling is complete. As of December 31, 2019 , the Company did not have any capitalized exploratory well costs that were pending determination of proved reserves. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred, whether productive or nonproductive. Capitalized costs attributed to the proved properties are subject to depreciation and depletion. Depreciation and depletion of the cost of oil and gas properties is calculated using the units-of-production method aggregating properties on a field basis. For leasehold acquisition costs and the cost to acquire proved properties, the reserve base used to calculate depreciation and depletion is the sum of proved developed reserves and proved undeveloped reserves. For well costs, the reserve base used to calculate depletion and depreciation is proved developed reserves only. Unproved properties consist of costs incurred to acquire unproved leases. Unproved lease acquisition costs are capitalized until the leases expire or when the Company specifically identifies leases that will revert to the lessor, at which time the Company expenses the associated unproved lease acquisition costs. The expensing of the unproved lease acquisition costs is recorded as an impairment of oil and gas properties in the consolidated statement of operations, as applicable. Unproved oil and gas property costs are transferred to proven oil and gas properties if the properties are subsequently determined to be productive or are assigned proved reserves. Unproved oil and gas properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, future plans to develop acreage, and other relevant factors. On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and any gain or loss is recognized. On the sale or retirement of a partial unit of a proved property, a pro-rata portion of the cost and related accumulated depreciation, depletion and amortization may be eliminated from the property accounts
Other Property and Equipment	Other Property and Equipment Other property and equipment, consisting primarily of office, transportation and computer equipment, as well as our new corporate headquarters, is carried at cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets, ranging from 3 to 5 years , with the exception of our corporate headquarters, which is 30 years . Major renewals and improvements are capitalized, while expenditures for maintenance and repairs are expensed as incurred. Upon sale or abandonment, the cost of the equipment and related accumulated depreciation are removed from the accounts, and any gain or loss is recognized.
Impairment of Long-Lived Assets	Impairment of Long-Lived Assets The carrying value of long-lived assets and certain identifiable intangibles are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. When it is determined that the estimated future net cash flows of an asset will not be sufficient to recover its carrying amount, an impairment loss must be recorded to reduce the carrying amount to its estimated fair value. Judgments and assumptions are inherent in management’s estimate of undiscounted future cash flows and an asset’s fair value. These judgments and assumptions include such matters as the estimation of oil and gas reserve quantities, risks associated with the different categories of oil and gas reserves, the timing of development and production, expected future commodity prices, capital expenditures, production costs, and appropriate discount rates. The Company evaluates impairment of proved and unproved oil and gas properties on a region basis. On this basis, certain regions may be impaired because they are not expected to recover their entire carrying value from future net cash flows. As a result of this evaluation, the Company recorded impairment of unproved oil and gas properties of approximately $14.5 million and $12.2 million for the years ended December 31, 2019 and 2018 , respectively, and impairment of proven oil and gas properties of $33.9 million for the year ended December 31, 2019. If pricing remains depressed, it is reasonably likely that the Company may have to record impairment of its oil and gas properties subsequent to December 31, 2019 .
Asset Retirement Obligations	Asset Retirement Obligations Asset retirement obligations are recognized at their fair value at the time that the obligations are incurred. Oil and gas producing companies incur such a liability upon acquiring or drilling a well. Under ASC 410, an asset retirement obligation is recorded as a liability at its estimated present value at the asset’s inception, with an offsetting increase to producing properties in the accompanying consolidated balance sheets, which is allocated to expense over the useful life of the asset. Periodic accretion of the discount on asset retirement obligations is recorded as part of depreciation, depletion and amortization ("DD&A") expense in the accompanying consolidated statement of operations.
Revenue Recognition	Revenue Recognition Lonestar recognizes revenue at an amount that reflects the consideration to which we expect to be entitled in exchange for transferring goods or services to a customer, using a five-step process, in accordance with ASC 606, Revenue from Contracts with Customers.
Derivatives	Derivatives The Company utilizes oil and natural gas derivative contracts to mitigate its exposure to commodity price risk associated with its future oil and natural gas production. These derivative contracts have historically consisted of fixed-price swaps, basis swaps, and collars. We do not apply hedge accounting; accordingly, all derivatives are recorded in the accompanying consolidated balance sheets at estimated fair value. The Company recognizes all changes in the fair values of its derivative contracts as gains or losses in the earnings of the periods in which they occur.
Income Taxes	Income Taxes Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, operating losses and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which these temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. The Company periodically evaluates the realizable tax benefits of deferred tax assets and records a valuation allowance, if required, based on an estimate of the amount of deferred tax assets the Company believes does not meet the more likely than not criteria of being realized. See Note 10. Income Taxes for more information. The Company evaluates uncertain tax positions, which requires significant judgments and estimates regarding the recoverability of deferred tax assets, the likelihood of the outcome of examinations of tax positions that may or may not be currently under review, and potential scenarios involving settlements of such matters. Changes in these estimates could materially impact the consolidated financial statements.
Share-Based Payments	Share-Based Payments Lonestar accounts for equity-based awards in accordance with ASC 718, Compensation-Stock Compensation, which requires companies to recognize in the statement of operations all share-based payments granted to employees based on their fair value. Share-based compensation is recognized by the Company on the graded vesting method over the requisite service period, which approximates the option vesting period of three years . Grants that can be settled in either cash or shares are treated as liabilities on the accompanying consolidated balance sheets.
Net (Loss) Income per Common Share	Net (Loss) Income 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 (loss) income 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.
Recently Issued Accounting Pronouncements	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. The Company adopted these standards on January 1, 2019. See Note 4. Leases for more information.

Basis of Presentation (Tables)

Basis of Presentation (Tables)	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Earnings Per Share, Basic and Diluted	The following is a reconciliation of basic and diluted earnings per share: In thousands, except shares and per-share data Year ended December 31, 2019 2018 Numerator - Basic Total net (loss) income attributable to common stockholders $ (111,563 ) $ 11,532 Less: allocation to participating securities — (4,270 ) Net (loss) income allocated to common stockholders - basic $ (111,563 ) $ 7,262 Numerator - Diluted Net (loss) income allocated to common stockholders - basic $ (111,563 ) $ 7,262 Unrealized gain on Warrants, net of income tax — (329 ) Net (loss) income allocated to common stockholders - diluted $ (111,563 ) $ 6,933 Denominator Weighted average number of common shares - basic 24,875,793 24,619,730 Warrants converted under the Treasury Stock method — 181,413 Weighted average number of common shares - diluted 24,875,793 24,801,143 Earnings per share Basic $ (4.48 ) $ 0.29 Diluted $ (4.48 ) $ 0.28
Schedule of Antidilutive Securities	The following weighted average securities could potentially dilute earnings per share for the periods indicated, but were excluded from the computation of diluted net (loss) income per share, as their effect would have been antidilutive: Year ended December 31, 2019 2018 Preferred stock 15,828,683 14,480,730 Warrants 760,000 — Stock appreciation rights 1,010,000 922,945 Restricted stock units 1,555,676 847,542

Commodity Price Risk Activiti_2

Commodity Price Risk Activities (Tables)	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Transactions Outstanding	The following table summarizes Lonestar's commodity derivative contracts as of December 31, 2019: Contract Volume Hedged Weighted Commodity Type Period Range (1) (Bbls/Mcf per day) Average Price Oil – WTI Swaps Jan - June 2020 $48.90 - $65.56 7,393 $ 56.51 Oil – WTI Swaps July - Dec 2020 51.60 - 65.56 7,565 57.38 Oil - WTI Swaps Jan - Dec 2021 51.05 - 56.50 4,000 53.93 Natural Gas - Henry Hub Swaps Jan - Dec 2020 2.38 - 2.80 20,000 2.58 (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.

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Components of Lease Expense and Supplemental Cash Flow Information	The components of our total lease expense for the year ended December 31, 2019 are as follows: In thousands Year ended December 31, 2019 Operating Leases $ 273 Short-term leases (1) 2,766 Total lease expense $ 3,039 Short-term lease costs capitalized to oil and gas properties (2) $ 11,747 (1) Short-term leases represent expenses related to leases with a contract term of one year or less. The majority of these leases relate to field operating equipment and are included in lease operating and gas gathering expense on the consolidated statement of operations. (2) Short-term lease costs represent leases with a contract term of one year or less, the majority of which are related to drilling rigs and are capitalized as part of Oil and Gas Properties on the consolidated balance sheets. Supplemental cash flow information related to leases follows: In thousands Year ended December 31, 2019 Cash paid for amounts included in the measurement of lease liabilities Operating cash flows for operating leases $ 273 Right-of-use assets obtained in exchange for lease obligations: Operating leases $ 273
Supplemental Balance Sheet Information	Supplemental balance sheet information related to leases follows: In thousands, except lease term and discount rate data December 31, 2019 Operating leases Assets Other property and equipment $ 45 Liabilities Accrued liabilities $ 45 Weighted-average remaining lease term (years) 0.2 Weighted-average discount rate 5.0 %
Maturities of Operating Lease Liabilities	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 December 31, 2019: In thousands Operating Leases 2020 $ 45 Thereafter — Total minimum lease payments 45 Amount of lease payments representing interest — Present value of future minimum lease payments $ 45
Maturities of Operating Leases Under Previous Accounting Standard	The table below summarizes by year the remaining non-cancelable future lease payments under our leases, as accounted for under previous accounting guidance as of December 31, 2018, a majority of which represents lease payments on our old corporate office space which was impaired in 2018: In thousands Amount 2019 $ 422 2020 477 2021 368 Total minimum lease payments $ 1,267

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Schedule of Assets and Liabilities Measured at Fair Value on Recurring Basis	The following table presents Lonestar's assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2019 and 2018: Fair Value Measurements Using In thousands Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total December 31, 2019 Assets: Commodity derivatives $ — $ 6,849 $ — $ 6,849 Liabilities: Commodity derivatives — (10,462 ) — (10,462 ) Warrants — — (364 ) (364 ) Stock-based compensation (1,792 ) — (573 ) (2,365 ) Total $ (1,792 ) $ (3,613 ) $ (937 ) $ (6,342 ) December 31, 2018 Assets: Commodity derivatives $ — $ 23,143 $ — $ 23,143 Liabilities: Commodity derivatives — (451 ) — (451 ) Warrants — — (1,055 ) (1,055 ) Stock-based compensation (1,267 ) — (636 ) (1,903 ) Total $ (1,267 ) $ 22,692 $ (1,691 ) $ 19,734
Summary of Changes in Fair Value for the Level 3 Liabilities	The table below sets forth a summary of changes in the fair value of the Company’s Level 3 liabilities for the year ended December 31, 2019. In thousands Warrant Stock-Based Compensation Total Balance at December 31, 2018 $ (1,055 ) $ (636 ) $ (1,691 ) Unrealized gains 691 63 754 Balance at December 31, 2019 $ (364 ) $ (573 ) $ (937 )

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Change in Asset Retirement Obligations	The following provides a reconciliation of activity in the asset retirement obligations for the years ended December 31, 2019 and 2018: Year Ended December 31, In thousands 2019 2018 Beginning asset retirement obligations $ 7,195 $ 5,649 Wells drilled during the year 26 408 Wells acquired during the year — 223 Wells sold during the year (388 ) — Accretion expense 300 215 Revisions in estimated retirement obligations (1) 191 790 Wells plugged and abandoned during the year (269 ) (90 ) Ending asset retirement obligations $ 7,055 $ 7,195 (1) Revisions of previous estimates during the year ended December 31, 2019 are primarily attributable to changes in estimates of the timing of future costs for oilfield services required to plug and abandon wells.

Accrued Liabilities (Tables)

Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2019
Payables and Accruals [Abstract]
Schedule of Accrued Liabilities	The following table provides detail of Lonestar's accrued liabilities as of December 31, 2019 and 2018: December 31, In thousands 2019 2018 Bonus payable $ 2,353 $ 3,244 Accrued interest - 11.25% Senior Notes 14,063 14,063 Accrued well costs 8,932 9,026 Other 1,557 1,795 Total accrued liabilities $ 26,905 $ 28,128

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Schedule of Long-Term Debt	The following long-term debt obligations were outstanding as of December 31, 2019 and 2018: December 31, In thousands 2019 2018 Senior Secured Credit Facility $ 247,000 $ 183,000 11.25% Senior Notes due 2023 250,000 250,000 Mortgage debt 8,931 9,151 Other 271 275 Total 506,202 442,426 Less unamortized discount (3,375 ) (4,500 ) Less unamortized debt issuance costs (759 ) (1,044 ) Total net of discount and debt issuance costs 502,068 436,882 Less current obligations (1) (247,000 ) — Long-term debt $ 255,068 $ 436,882 (1) Current obligations represent the Senior Secured Credit Facility obligations which were classified as current liabilities as of December 31, 2019. See Waiver and Eleventh Amendment below for further discussion.
Schedule of Maturities of Long-term Debt	As of December 31, 2019, our debt is payable over the next five years and thereafter as follows: In thousands 2020 $ 247,084 2021 71 2022 76 2023 250,081 2024 86 Thereafter 8,804 Total debt $ 506,202

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Current and Deferred Components of Income Tax (Benefit) Expense	The income tax provision is as follows: Year Ended December 31, In thousands 2019 2018 Current income tax (benefit) expense Federal $ (591 ) $ (1,100 ) State (464 ) 291 Total current income tax benefit (1,055 ) (809 ) Deferred tax (benefit) expense Federal (20,989 ) 7,686 State 673 (85 ) Valuation allowance 8,876 — Total deferred income tax (benefit) expense (11,440 ) 7,601 Total income tax (benefit) expense $ (12,495 ) $ 6,792
Difference between Income Taxes Computed at Federal Statutory Rate and Provision for Income Taxes	The following table provides a reconciliation of Lonestar's actual income tax provision amounts from the expected income tax provision amount by applying the U.S. federal statutory corporate income tax rate of 21% for the years ended December 31, 2019 and 2018, respectively: Year Ended December 31, In thousands 2019 2018 Expected income tax expense (benefit) at statutory rate $ (24,258 ) $ 5,489 Permanent differences (48 ) 123 Return to provision adjustment 2,567 1,119 Change in valuation allowance 8,876 — Other 368 61 Actual income tax (benefit) expense $ (12,495 ) $ 6,792
Deferred Tax Assets and Liabilities	Significant components of the Company's deferred tax assets and liabilities as of December 31, 2019 and 2018 are as follows: December 31, In thousands 2019 2018 Deferred tax assets Net operating loss carryforward $ 27,025 $ 17,765 Stock-based compensation 922 1,973 Intangibles 257 304 Derivative instruments 606 — Interest expense limitation 19,243 2,254 Organizational expenses and other 3,306 4,477 Total deferred tax assets $ 51,359 $ 26,773 Deferred tax liabilities Oil and gas properties, and other property and equipment, principally due to intangible drilling costs $ (43,414 ) $ (34,332 ) Derivative instruments — (4,811 ) Net deferred tax assets (liabilities) 7,945 (12,370 ) Valuation allowance for deferred tax assets (8,876 ) — Net deferred tax liability, net of valuation allowance $ (931 ) $ (12,370 )

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2019
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of Outstanding Restricted Stock Units	A summary of the status of the Company's non-vested RSU grants issued, and the changes during the year ended December 31, 2019, is presented below: Shares Weighted Average Fair Value per Share Outstanding non-vested RSUs at December 31, 2018 1,011,045 $ 5.06 Granted 1,300,003 3.40 Vested (450,422 ) 4.56 Forfeited (10,950 ) — Outstanding non-vested RSUs at December 31, 2019 1,849,676 $ 4.04
Schedule of Outstanding Stock Appreciation Rights	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 — — 0 Outstanding at December 31, 2019 1,010,000 $ 6.30 2.5 SARs vested and exercisable at December 31, 2019 606,250 $ 6.65 2.4

Basis of Presentation - Additio

Basis of Presentation - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Jan. 31, 2018
Nature Of Business And Presentation [Line Items]
Maturity period of highly liquid investments	three months or less
Impairment of oil and gas properties	$ 48,412,000	$ 12,169,000
Liability for material uncertain tax positions	$ 0	0
Option vesting period	3 years
Corporate Headquarter
Nature Of Business And Presentation [Line Items]
Estimated useful lives	30 years
Unproved Oil and Gas Properties
Nature Of Business And Presentation [Line Items]
Impairment of oil and gas properties	$ 14,500,000	$ 12,200,000
Proved Oil And Gas Properties
Nature Of Business And Presentation [Line Items]
Impairment of oil and gas properties	$ 33,900,000
Minimum | Other Property and Equipment
Nature Of Business And Presentation [Line Items]
Estimated useful lives	3 years
Maximum | Other Property and Equipment
Nature Of Business And Presentation [Line Items]
Estimated useful lives	5 years
Sales Revenue, Net | Customer Concentration Risk | Shell Trading (US) Company
Nature Of Business And Presentation [Line Items]
Concentration risk, percentage	23.00%	15.00%
Sales Revenue, Net | Customer Concentration Risk | Texla Energy Management, Inc.
Nature Of Business And Presentation [Line Items]
Concentration risk, percentage	17.00%	15.00%
Sales Revenue, Net | Customer Concentration Risk | Enterprise Crude Oil LLC
Nature Of Business And Presentation [Line Items]
Concentration risk, percentage	16.00%	27.00%
Sales Revenue, Net | Customer Concentration Risk | Vitol Inc.
Nature Of Business And Presentation [Line Items]
Concentration risk, percentage		16.00%
Sales Revenue, Net | Customer Concentration Risk | Ace Gathering, Inc.
Nature Of Business And Presentation [Line Items]
Concentration risk, percentage	14.00%
Sales Revenue, Net | Customer Concentration Risk | GulfMark Energy, Inc.
Nature Of Business And Presentation [Line Items]
Concentration risk, percentage	13.00%
Sales Revenue, Net | Customer Concentration Risk | NGL Crude Logistics LLC
Nature Of Business And Presentation [Line Items]
Concentration risk, percentage	10.00%	11.00%
Accounts Receivable | Customer Concentration Risk | Shell Trading (US) Company
Nature Of Business And Presentation [Line Items]
Concentration risk, percentage	11.00%	22.00%
Accounts Receivable | Customer Concentration Risk | Texla Energy Management, Inc.
Nature Of Business And Presentation [Line Items]
Concentration risk, percentage	59.00%
Accounts Receivable | Customer Concentration Risk | Phillips 66
Nature Of Business And Presentation [Line Items]
Concentration risk, percentage		23.00%
Accounts Receivable | Customer Concentration Risk | Enterprise Crude Oil LLC
Nature Of Business And Presentation [Line Items]
Concentration risk, percentage		37.00%
Accounts Receivable | Customer Concentration Risk | Ace Gathering, Inc.
Nature Of Business And Presentation [Line Items]
Concentration risk, percentage	13.00%
Accounts Receivable | Customer Concentration Risk | NGL Crude Logistics LLC
Nature Of Business And Presentation [Line Items]
Concentration risk, percentage		10.00%
11.25% Senior Notes
Nature Of Business And Presentation [Line Items]
Debt instrument interest rate (as a percent)	11.25%		11.25%

Basis of Presentation - Earning

Basis of Presentation - Earnings per Common Share (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Numerator - Basic
Total net (loss) income attributable to common stockholders	$ (111,563)	$ 11,532
Less: allocation to participating securities	0	(4,270)
Net (loss) income allocated to common stockholders - basic	(111,563)	7,262
Numerator - Diluted
Net (loss) income allocated to common stockholders - basic	(111,563)	7,262
Unrealized gain on Warrants, net of income tax	0	(329)
Net (loss) income allocated to common stockholders - diluted	$ (111,563)	$ 6,933
Denominator
Weighted average number of common shares - basic (in shares)	24,875,793	24,619,730
Warrants converted under the Treasury Stock method (in shares)	0	181,413
Weighted average number of common shares - diluted (in shares)	24,875,793	24,801,143
Earnings Per Share [Abstract]
Basic (in dollars per share)	$ (4.48)	$ 0.29
Diluted (in dollars per share)	$ (4.48)	$ 0.28

Basis of Presentation - Schedul

Basis of Presentation - Schedule of Anti-dilutive Securities (Details) - shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Preferred stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share, amount (in shares)	15,828,683	14,480,730
Warrants
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share, amount (in shares)	760,000	0
Stock appreciation rights
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share, amount (in shares)	1,010,000	922,945
Restricted stock units
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share, amount (in shares)	1,555,676	847,542

Recently Issued Accounting Pron

Recently Issued Accounting Pronouncements - Additional Information (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Jan. 01, 2019
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Present value of future minimum lease payments	$ 45
Other property and equipment	$ 45
Accounting Standards Update 2016-02
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Present value of future minimum lease payments		$ 300
Other property and equipment		$ 300

Acquisitions and Divestitures -

Acquisitions and Divestitures - Additional Information (Details) $ in Thousands	Mar. 22, 2019USD ($)aBoewelllocation	Nov. 15, 2018USD ($)	Aug. 02, 2017USD ($)	Mar. 31, 2019USD ($)	Mar. 31, 2018USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Feb. 28, 2019USD ($)
Business Acquisition [Line Items]
Gain (loss) on disposition of oil and gas property						$ (33,508)	$ 0
Sooner Acquisition
Business Acquisition [Line Items]
Purchase consideration of oil and gas properties		$ 38,700
Transaction costs capitalized		$ 300
Fort Worth, Texas
Business Acquisition [Line Items]
Acquisition price of an office building			$ 10,000
Business combination, recognized identifiable assets acquired and liabilities assumed, land								$ 2,000
Other expense | Fort Worth, Texas
Business Acquisition [Line Items]
Impairment related to leased acreage					$ 1,600
Pirate
Business Acquisition [Line Items]
Proceeds from divestiture of businesses	$ 11,500
Gas and oil area, undeveloped, net | a	3,400
Productive oil wells, number of wells, net | well	6
Production, barrels of oil equivalents | Boe	200
Proved undeveloped locations | location	7
Gain (loss) on disposition of oil and gas property				$ (33,500)

Commodity Price Risk Activiti_3

Commodity Price Risk Activities - Schedule of Derivative Transactions Outstanding (Details)	12 Months Ended
	Dec. 31, 2019$ / bblbblMcf
Oil WTI Swaps January-June 2020
Derivative [Line Items]
Total Volume | bbl	7,393.40659340659
Weighted average price - swap	56.51
Weighted average price - floor	48.90
Weighted average price - ceiling	65.56
Oil WTI Swaps July-December 2020
Derivative [Line Items]
Total Volume | bbl	7,565
Weighted average price - swap	57.38
Weighted average price - floor	51.60
Weighted average price - ceiling	65.56
Oil WTI Swaps January-December 2021
Derivative [Line Items]
Total Volume | bbl	4,000
Weighted average price - swap	53.93
Weighted average price - floor	51.05
Weighted average price - ceiling	56.50
Natural Gas Henry Hub Swaps January-December 2020
Derivative [Line Items]
Total Volume | Mcf	20,000
Weighted average price - swap	2.58
Weighted average price - floor	2.38
Weighted average price - ceiling	2.80

Commodity Price Risk Activiti_4

Commodity Price Risk Activities - Additional Information (Details)	1 Months Ended		12 Months Ended
	Mar. 31, 2020bbl / dbblMcf	Jan. 31, 2020Mcf / dbbl	Dec. 31, 2019bblMcf	Mar. 30, 2020USD ($)	Mar. 01, 2020$ / bbl	Jan. 01, 2020$ / bbl
Oil WTI Swaps January-December 2021
Derivative [Line Items]
Derivative contracts, aggregate volume | bbl			4,000
Natural Gas Henry Hub Swaps January-December 2020
Derivative [Line Items]
Derivative contracts, aggregate volume | Mcf			20,000
Subsequent Event | Oil WTI Swaps January-December 2021
Derivative [Line Items]
Derivative contracts, aggregate volume | bbl	730,000	365,000
Derivative contracts, flow rate	2,000	1,000
Derivative contract weighted average strike price | $ / bbl					41	55.05
Subsequent Event | Natural Gas Henry Hub Swaps January-December 2020
Derivative [Line Items]
Derivative contracts, aggregate volume | Mcf	10,037,500
Derivative contracts, flow rate | bbl / d	27,500
Derivative contract weighted average strike price | $ / bbl					2.36
Subsequent Event | Interest Rate Swap
Derivative [Line Items]
Derivative, notional amount | $				$ 190,000,000
Derivative, interest rate				0.68%

Revenue Recognition - Additiona

Revenue Recognition - Additional Information (Details) - USD ($)	9 Months Ended	12 Months Ended
	Sep. 30, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Allowance for Doubtful Accounts Receivable		$ 0	$ 0	$ 0
Allowance for uncollectible accounts	$ 0	$ 0	$ 0

Leases - Addtional Information

Leases - Addtional Information (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2019	Dec. 31, 2019	Jan. 01, 2019
Lessee, Lease, Description [Line Items]
Right-of-use asset		$ 45
Present value of future minimum lease payments		$ 45
Accounting Standards Update 2016-02
Lessee, Lease, Description [Line Items]
Right-of-use asset			$ 300
Present value of future minimum lease payments			$ 300
Minimum
Lessee, Lease, Description [Line Items]
Non-cancelable primary lease term	1 year
Maximum
Lessee, Lease, Description [Line Items]
Non-cancelable primary lease term	2 years

Leases - Components of Lease Ex

Leases - Components of Lease Expense and Supplemental Cash Flow Information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Leases [Abstract]
Operating Leases	$ 273
Short-term leases	2,766
Total lease expense	3,039
Short-term lease costs capitalized to oil and gas properties	11,747
Cash paid for amounts included in the measurement of lease liabilities	273
Right-of-use assets obtained in exchange for operating lease obligations	$ 273

Leases - Supplemental Balance S

Leases - Supplemental Balance Sheet Information (Details) $ in Thousands	Dec. 31, 2019USD ($)
Leases [Abstract]
Other property and equipment	$ 45
Accrued liabilities	$ 45
Weighted-average remaining lease term (years)	2 months 12 days
Weighted-average discount rate	5.00%
Operating lease, right-of-use asset, statement of financial position [Extensible List]	us-gaap:PropertyPlantAndEquipmentOtherNet
Operating lease, liability, statement of financial position [Extensible List]	us-gaap:AccruedLiabilitiesCurrent

Leases - Maturities of Operatin

Leases - Maturities of Operating Lease Liabilities (Details)	Dec. 31, 2019USD ($)
Leases [Abstract]
2020	$ 45,000
Thereafter	0
Total minimum lease payments	45,000
Amount of lease payments representing interest	0
Present value of future minimum lease payments	$ 45,000

Leases - Maturities of Operat_2

Leases - Maturities of Operating Leases Under Previous Accounting Standard (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Sep. 30, 2019	Dec. 31, 2018
Leases [Abstract]
2019	$ 422
2020		$ 477
2021		$ 368
Total minimum lease payments			$ 1,267

Fair Value Measurements - Sched

Fair Value Measurements - Schedule of Assets and Liabilities Measured at Fair Value on Recurring Basis (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Warrants	$ (364)	$ (1,055)
Stock-based compensation	(2,365)	(1,903)
Total	(6,342)	19,734
Commodity Derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	6,849	23,143
Commodity derivatives	(10,462)	(451)
Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Warrants	0	0
Stock-based compensation	(1,792)	(1,267)
Total	(1,792)	(1,267)
Quoted Prices in Active Markets for Identical Assets (Level 1) | Commodity Derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	0	0
Commodity derivatives	0	0
Significant Other Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Warrants	0	0
Stock-based compensation	0	0
Total	(3,613)	22,692
Significant Other Observable Inputs (Level 2) | Commodity Derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	6,849	23,143
Commodity derivatives	(10,462)	(451)
Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Warrants	(364)	(1,055)
Stock-based compensation	(573)	(636)
Total	(937)	(1,691)
Significant Unobservable Inputs (Level 3) | Commodity Derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	0	0
Commodity derivatives	$ 0	$ 0

Fair Value Measurements - Summa

Fair Value Measurements - Summary of Changes in Fair Value for the Level 3 Liability (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	$ (1,691)
Unrealized gains	754
Ending balance	(937)
Warrants
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	(1,055)
Unrealized gains	691
Ending balance	(364)
Stock-Based Compensation
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	(636)
Unrealized gains	63
Ending balance	$ (573)

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Details) - 11.25% Senior Notes - USD ($) $ in Millions	Dec. 31, 2019	Jan. 31, 2018
Debt Instrument [Line Items]
Debt instrument interest rate (as a percent)	11.25%	11.25%
Fair value of senior notes	$ 173

Asset Retirement Obligations -

Asset Retirement Obligations - Schedule of Change in Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning asset retirement obligations	$ 7,195	$ 5,649
Wells drilled during the year	26	408
Wells acquired during the year	0	223
Wells sold during the year	(388)	0
Accretion expense	300	215
Revisions in estimated retirement obligations	191	790
Wells plugged and abandoned during the year	(269)	(90)
Ending asset retirement obligations	$ 7,055	$ 7,195

Accrued Liabilities - Schedule

Accrued Liabilities - Schedule of Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Payables and Accruals [Abstract]
Bonus payable	$ 2,353	$ 3,244
Accrued interest	14,063	14,063
Accrued well costs	8,932	9,026
Other	1,557	1,795
Total accrued liabilities	$ 26,905	$ 28,128

Long-Term Debt - Schedule of De

Long-Term Debt - Schedule of Debt (Details) - USD ($)	Dec. 31, 2019	Dec. 31, 2018	Jan. 31, 2018
Debt Instrument [Line Items]
Senior Secured Credit Facility	$ 247,000,000	$ 183,000,000
Other	271,000	275,000
Total	506,202,000	442,426,000
Less unamortized discount	(3,375,000)	(4,500,000)
Less unamortized debt issuance costs	(759,000)	(1,044,000)
Total net of discount and debt issuance costs	502,068,000	436,882,000
Less current obligations	(247,000,000)	0
Long-term debt	255,068,000	436,882,000
11.25% Senior Notes
Debt Instrument [Line Items]
11.25% Senior Notes due 2023	$ 250,000,000	250,000,000
Debt instrument interest rate (as a percent)	11.25%		11.25%
Mortgages Debt
Debt Instrument [Line Items]
Mortgage debt	$ 8,931,000	$ 9,151,000

Long-Term Debt - Senior Secured

Long-Term Debt - Senior Secured Credit Facility - Additional Information (Details) - USD ($)

Jul. 28, 2015

Jul. 31, 2015

Sep. 30, 2017

Sep. 30, 2019

Dec. 31, 2019

Dec. 31, 2018

Jun. 01, 2019

May 31, 2019

Nov. 30, 2018

May 31, 2018

Jan. 31, 2018

Jan. 04, 2018

Jun. 15, 2017

Debt Instrument [Line Items]

Senior Secured Credit Facility

$ 247,000,000

$ 183,000,000

Leverage ratio

4.00%

1.00%

Minimum

Debt Instrument [Line Items]

Debt instrument expanded borrowing base

$ 190,000,000

Maximum

Debt Instrument [Line Items]

Debt instrument expanded borrowing base

$ 275,000,000

$ 190,000,000

$ 160,000,000

Senior Secured Credit Facility

Debt Instrument [Line Items]

Weighted average interest rate on borrowings

5.28%

Current borrowing availability

$ 42,600,000

$ 160,000,000

Senior secured credit facility sub limit

$ 2,500,000

Debt instrument expanded borrowing base

$ 290,000,000

Senior Secured Credit Facility | Minimum

Debt Instrument [Line Items]

Commitment fee percentage

0.375%

Debt instrument expanded borrowing base

$ 275,000,000

Senior Secured Credit Facility | Minimum | Adjusted LIBOR Rate

Debt Instrument [Line Items]

Debt instrument basis spread on variable rate

2.00%

Senior Secured Credit Facility | Minimum | ABR

Debt Instrument [Line Items]

Debt instrument basis spread on variable rate

1.00%

Senior Secured Credit Facility | Maximum

Debt Instrument [Line Items]

Commitment fee percentage

0.50%

Debt instrument expanded borrowing base

$ 290,000,000

Senior Secured Credit Facility | Maximum | Adjusted LIBOR Rate

Debt Instrument [Line Items]

Debt instrument basis spread on variable rate

3.00%

Senior Secured Credit Facility | Maximum | ABR

Debt Instrument [Line Items]

Debt instrument basis spread on variable rate

2.00%

11.25% Senior Notes

Debt Instrument [Line Items]

Debt instrument face amount

$ 250,000,000

Debt instrument interest rate (as a percent)

11.25%

11.25%

LRAI | Senior Secured Credit Facility

Debt Instrument [Line Items]

Lien percentage of assets for senior secured credit facility

90.00%

LRAI | Senior Secured Credit Facility | Federal Funds Effective Rate

Debt Instrument [Line Items]

Debt instrument basis spread on variable rate

0.50%

LRAI | Senior Secured Credit Facility | Adjusted LIBOR Rate

Debt Instrument [Line Items]

Debt instrument basis spread on variable rate

1.00%

LRAI | Senior Secured Credit Facility | Minimum

Debt Instrument [Line Items]

Lien percentage of assets for senior secured credit facility

80.00%

LRAI | Citibank N A | Senior Secured Credit Facility

Debt Instrument [Line Items]

Debt instrument face amount

$ 500,000,000

Letter of Credit | Senior Secured Credit Facility

Debt Instrument [Line Items]

Current borrowing availability

$ 400,000

Long-Term Debt - 11.25% Senior

Long-Term Debt - 11.25% Senior Notes (Details) - USD ($)	Jan. 04, 2018	Apr. 15, 2016	Jan. 31, 2018	Dec. 31, 2019	Sep. 30, 2019	Dec. 31, 2018
108.438% January 1, 2021
Debt Instrument [Line Items]
Redemption price, percentage				108.438%
105.625% January 1, 2022
Debt Instrument [Line Items]
Redemption price, percentage				105.625%
100%, July 1, 2022
Debt Instrument [Line Items]
Redemption price, percentage				100.00%
11.25% Senior Notes
Debt Instrument [Line Items]
Debt instrument face amount			$ 250,000,000
Debt instrument interest rate (as a percent)			11.25%	11.25%
Proceeds from issuance of senior notes			$ 244,400,000
Percentage of senior notes redeem from aggregate principal amount	65.00%
Redemption price, percentage	111.25%
11.25% Senior Notes | Maximum
Debt Instrument [Line Items]
Percentage of senior notes redeem from aggregate principal amount	35.00%
Senior notes redemption period	180 days
11.25% Senior Notes | January 1, 2021
Debt Instrument [Line Items]
Percentage of senior notes redeem from aggregate principal amount	100.00%
8.750% Senior Notes Due April 15, 2019
Debt Instrument [Line Items]
Debt instrument interest rate (as a percent)			8.75%	8.75%	8.75%	8.75%
Early repayment of senior debt			$ 162,000,000
Debt instrument maturity date				Apr. 15, 2019
Redemption price, percentage		104.375%

Long-Term Debt - 8.750% Senior

Long-Term Debt - 8.750% Senior Notes - Additional Information (Details) - USD ($)	Jan. 04, 2018	Apr. 15, 2016	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Sep. 30, 2019	Jan. 31, 2018
Debt Instrument [Line Items]
Gain (loss) on extinguishment of debt				$ 0	$ (8,620,000)
8.750% Senior Notes Due April 15, 2019
Debt Instrument [Line Items]
Debt instrument interest rate (as a percent)				8.75%	8.75%	8.75%	8.75%
Debt instrument maturity date				Apr. 15, 2019
Redemption price, percentage		104.375%
Debt instrument redemption price amount excludes accrued interest		$ 158,500,000
11.25% Senior Notes
Debt Instrument [Line Items]
Debt instrument face amount							$ 250,000,000
Debt instrument interest rate (as a percent)				11.25%			11.25%
Redemption price, percentage	111.25%
Unsecured Debt | 8.750% Senior Notes Due April 15, 2019
Debt Instrument [Line Items]
Gain (loss) on extinguishment of debt			$ (8,600,000)

Long-Term Debt - Debt Issuance

Long-Term Debt - Debt Issuance Costs - Additional Information (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Senior Secured Credit Facility
Debt Instrument [Line Items]
Debt issuance costs, line of credit arrangements, net	$ 0.7	$ 1.7

Long-Term Debt - Securities Pur

Long-Term Debt - Securities Purchase Agreement and Second Lien Notes - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Sep. 30, 2019	Jan. 31, 2018
Debt Instrument [Line Items]
Gain on warrants	$ 691	$ 416
8.750% Senior Notes Due April 15, 2019
Debt Instrument [Line Items]
Debt instrument interest rate (as a percent)	8.75%	8.75%	8.75%	8.75%

Long Term Debt - Maturities (De

Long Term Debt - Maturities (Details) - USD ($)	Dec. 31, 2019	Dec. 31, 2018
Debt Disclosure [Abstract]
2020	$ 247,084,000
2021	71,000
2022	76,000
2023	250,081,000
2024	86,000
Thereafter	8,804,000
Total	$ 506,202,000	$ 442,426,000

Income Taxes - Current and Defe

Income Taxes - Current and Deferred Components of Income Tax (Benefit) Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Current income tax (benefit) expense
Federal	$ (591)	$ (1,100)
State	(464)	291
Total current income tax benefit	(1,055)	(809)
Deferred tax (benefit) expense
Federal	(20,989)	7,686
State	673	(85)
Valuation allowance	8,876	0
Total deferred income tax (benefit) expense	(11,440)	7,601
Total income tax (benefit) expense	$ (12,495)	$ 6,792

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($) $ in Thousands	Dec. 22, 2016	Dec. 31, 2019	Dec. 31, 2016	Dec. 31, 2018	Jun. 15, 2017
Income Taxes [Line Items]
Subject to expiration		$ 128,600
Not subject to expiration		49,900
Operating loss carryforwards annual installment amount			$ 1,000
Net operating loss carryforward written off			$ 141,700
Depletion carryover amount		8,700
AMT credit carryovers		600
Valuation allowance		8,876		$ 0
Net deferred tax liability, net of valuation allowance		$ 931		12,370
AMT expected to refund Year		2022
Maximum percentage of deductible interest expense for tax of earnings before interest, taxes, depreciation, and amortization		30.00%
Maximum percentage of deductible interest expense for tax of earnings before interest and taxes		30.00%
Deferred tax assets		$ 19,200		$ 2,300
Amended and Restated Purchase Agreement | Chambers
Income Taxes [Line Items]
Additional estimated annual utilization limit of net operating losses					$ 800
Net operating loss carryforwards limitations on use description		The 2017 change creates an additional estimated annual utilization limit of approximately $0.8 million on our ability to utilize net operating losses generated subsequent to the 2016 change in ownership, but prior to the June, 2017 change in ownership.
Common Class A
Income Taxes [Line Items]
Sale of common stock, net of offering costs (in shares)	13,800,000
Series A-1 Convertible Participating Preferred Stock | Amended and Restated Purchase Agreement | Chambers
Income Taxes [Line Items]
Preferred stock, shares issued (in shares)					5,400
Series A-2 Convertible Participating Preferred Stock | Amended and Restated Purchase Agreement | Chambers
Income Taxes [Line Items]
Preferred stock, shares issued (in shares)					74,600
State and Local Jurisdiction
Income Taxes [Line Items]
Net deferred tax liability, net of valuation allowance		$ 1,500

Income Taxes - Difference betwe

Income Taxes - Difference between Income Taxes Computed at Federal Statutory Rate and Provision for Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Expected income tax expense (benefit) at statutory rate	$ (24,258)	$ 5,489
Permanent differences	(48)	123
Adjustment to NOL	2,567	1,119
Change in valuation allowance	8,876	0
Other	368	61
Total income tax (benefit) expense	$ (12,495)	$ 6,792

Income Taxes - Deferred Tax Ass

Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Deferred tax assets
Net operating loss carryforward	$ 27,025	$ 17,765
Stock-based compensation	922	1,973
Intangibles	257	304
Derivative instruments	606	0
Interest expense limitation	19,243	2,254
Organizational expenses and other	3,306	4,477
Total deferred tax assets	51,359	26,773
Deferred tax liabilities:
Oil and gas properties, and other property and equipment, principally due to intangible drilling costs	(43,414)	(34,332)
Derivative instruments	0	(4,811)
Net deferred tax assets (liabilities)	7,945
Net deferred tax assets (liabilities)		(12,370)
Valuation allowance for deferred tax assets	(8,876)	0
Net deferred tax liability, net of valuation allowance	$ (931)	$ (12,370)

Stockholders' Equity - Addition

Stockholders' Equity - Additional Information (Details) $ / shares in Units, $ in Thousands	Sep. 28, 2018USD ($)shares	Jun. 30, 2017$ / sharesshares	Sep. 30, 2019$ / sharesRate	Dec. 31, 2019shares	Dec. 31, 2018shares	Dec. 31, 2018shares	Nov. 03, 2017shares	Dec. 22, 2016shares
Class of Stock [Line Items]
Minimum percentage of outstanding common stock beneficially own by approved holders		10.00%
Senior Unsecured Notes
Class of Stock [Line Items]
Unsecured notes, maturity period			2 years
Debt instrument interest rate (as a percent)			9.00%
Series A-1 Convertible Participating Preferred Stock
Class of Stock [Line Items]
Preferred stock, dividend rate, percentage			20.00%
Preferred stock dividends (in shares)				8,544	7,816	11,784
Stock conversion terms				the Company, at its option, may instead elect to exchange each share of Series A-1 Preferred Stock for senior unsecured notes of the Company with a two-year maturity, a 9.0% per annum coupon payable semi-annually in cash, and governed by terms substantially similar to the Company’s most recent high yield indenture at that time.
Series A-1 Convertible Participating Preferred Stock | Battlecat and Marquis
Class of Stock [Line Items]
Number of shares issued (in shares)		5,400
Preferred stock, par value (in dollars per share) | $ / shares		$ 0.001
Series A-2 Convertible Participating Preferred Stock | Battlecat and Marquis
Class of Stock [Line Items]
Preferred stock, par value (in dollars per share) | $ / shares		$ 0.001
Convertible participating preferred stock, number of shares issued (in shares)		74,600
Series B Convertible Participating Preferred Stock
Class of Stock [Line Items]
Shares issued upon conversion (in shares)							1
Series A Preferred Stock
Class of Stock [Line Items]
Minimum percentage of outstanding preferred stock beneficially own by approved holders		15.00%
Preferred stock, dividend rate, percentage			9.00%
Shares issued, price per share (in dollars per share) | $ / shares			$ 975
Preferred stock, increase in dividend rate for next succeeding dividend period | Rate			5.00%
Preferred stock, additional increase in dividend rate for each successive dividend period | Rate			1.00%
Preferred stock redemption percentage of stated value				110.00%
Preferred stock redemption percentage of stated value two				105.00%
Preferred stock redemption percentage of stated value three				100.00%
Series A Preferred Stock | Maximum
Class of Stock [Line Items]
Preferred stock, dividend rate, percentage | Rate			20.00%
Class A Voting Common Stock
Class of Stock [Line Items]
Preferred stock, liquidation preference per share (in dollars per share) | $ / shares		$ 1,000
Conversion threshold percentage of conversion price, one				1.75
Conversion threshold percentage of conversion price, two				1.50
Convertible, conversion ratio				0.1667
Shares issued upon conversion (in shares)								1
Common stock, shares issued (in shares)				24,945,594	24,645,825	24,645,825
Common stock, shares outstanding (in shares)				24,945,594	24,645,825	24,645,825
Class B Non-Voting Common Stock
Class of Stock [Line Items]
Stock repurchased and retired (in shares)	2,500
Stock repurchased and retired during period, value | $	$ 10
Common Class B
Class of Stock [Line Items]
Common stock, shares issued (in shares)				0
Common stock, shares outstanding (in shares)				0

Stock-Based Compensation - Addi

Stock-Based Compensation - Additional Information (Details) - USD ($)	1 Months Ended	12 Months Ended
	Feb. 28, 2017	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock options vesting periods		3 years
Cash dividend on common shares		$ 0
Restricted stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock options vesting periods		3 years
Share based compensation expense		$ 2,600,000	$ 1,600,000
Vested		$ 2,054,622	1,300,000
Period for recognition		1 year 10 months 25 days
Stock-based compensation liability		$ 1,800,000	1,300,000
Unrecognized compensation expense		$ 3,000,000
Restricted stock units | Vesting on Third Anniversary
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation award vesting rights, percentage		30.00%
Stock appreciation rights
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share based compensation expense		$ (100,000)	300,000
Period for recognition		8 months 15 days
Share-based compensation expiration period	5 years
Number of RSUs or SARs granted		0
Stock-based compensation liability		$ 600,000	$ 600,000
Unrecognized compensation expense		$ 100,000
Stock appreciation rights | Vesting on Third Anniversary
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation award vesting rights, percentage	30.00%

Stock-Based Compensation - Sche

Stock-Based Compensation - Schedule of Outstanding Restricted Stock Units (Details) - Restricted stock units	12 Months Ended
	Dec. 31, 2019$ / sharesshares
Non-vested Shares [Roll Forward]
Outstanding non-vested options at beginning of period, Shares | shares	1,011,045
Granted, Shares | shares	1,300,003
Vested, Shares | shares	(450,422)
Forfeited, Shares | shares	(10,950)
Outstanding non-vested options at end of period, Shares | shares	1,849,676
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Outstanding non-vested options at beginning of period, Weighted Average Fair Value per Share | $ / shares	$ 5.06
Granted, weighted average fair value per share | $ / shares	3.40
Vested, weighted average fair value per share | $ / shares	4.56
Forfeited, weighted average fair value per share | $ / shares	0
Outstanding non-vested options at ending of period, Weighted Average Fair Value per Share | $ / shares	$ 4.04

Stock-Based Compensation - Sc_2

Stock-Based Compensation - Schedule of Outstanding Stock Appreciation Rights (Details) - Stock appreciation rights - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Outstanding Shares [Roll Forward]
Outstanding at beginning of period (in shares)	1,010,000
Granted (in shares)	0
Outstanding at beginning of period (in shares)	1,010,000	1,010,000
Options vested and exercisable, (in shares)	606,250	280,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Additional Disclosures [Abstract]
Outstanding at end of period, weighted average exercise price per share (in dollars per share)	$ 6.30
Granted, weighted average exercise price per share (in dollars per share)	0
Outstanding at end of period, weighted average exercise price per share (in dollars per share)	6.30	$ 6.30
Options vested and exercisable, weighted average exercise price per share (in dollars per share)	$ 6.65	$ 7.20
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Outstanding, weighted average remaining contractual term (in years)	2 years 6 months	3 years 6 months
Granted non-vested options, weighted average remaining contractual term (in years)	0 years
Options vested and exercisable, Weighted Average Remaining Contractual Term (in years)	2 years 4 months 24 days	3 years 2 months 12 days

Related Party Activities - Addi

Related Party Activities - Additional Information (Details) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended
	Feb. 28, 2019USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2016USD ($)shares	Sep. 30, 2019	Oct. 09, 2018shares	Oct. 26, 2016directorDirector	Aug. 31, 2016USD ($)$ / sharesshares
Related Party Transaction [Line Items]
Registration rights agreement description		the Company entered into a Registration Rights Agreement with EF Realisation, pursuant to which the Company agreed to register for resale Class A voting common stock indirectly owned by EF Realisation. The Company agreed to file a registration statement providing for the resale of Class A voting common stock held by EF Realisation no later than the earlier of (i) October 26, 2017, and (ii) 30 days after the date the Company first becomes eligible to file a registration statement on Form S-3. The Form S-3 registration statement was filed with the Securities and Exchange Commission on November 7, 2017, and is effective. The Company has also granted EF Realisation certain piggyback and demand registration rights.
Juneau Energy, LLC | Securities Purchase Agreement
Related Party Transaction [Line Items]
Warrants to purchase common stock (in shares) | shares				500,000
Juneau Energy, LLC | Securities Purchase Agreement | 12% Senior Secured Second Lien Notes Due 2021
Related Party Transaction [Line Items]
Sale of stock, description of transaction		(i) up to $49.9 million aggregate principal amount of LRAI’s 12% senior secured second lien notes due 2021 (“Second Lien Notes”) and (ii) five-year warrants to purchase up to an aggregate 998,000 shares of the Company’s Class A voting common stock at a price equal to $5.00 per share (the “Warrants”). During 2016, LRAI issued $25.0 million in aggregate principal amount of Second Lien Notes and the Company issued Warrants to purchase 500,000 shares of its Class A voting common stock to Juneau. In December 2016, LRAI repaid to Juneau $21.0 million principal of the Second Lien Notes with proceeds from the 2016 Common Stock Offering.
Juneau Energy, LLC | Securities Purchase Agreement | Second Lien Notes
Related Party Transaction [Line Items]
Debt instrument face amount				$ 25
Repayment of principal second lien notes				$ 21
Leucadia | Class A Voting Common Stock
Related Party Transaction [Line Items]
Number of common shares issued (in shares) | shares				3,478,261
Ownership percentage required to appoint board of directors					50.00%
Leucadia | Securities Purchase Agreement | 12% Senior Secured Second Lien Notes Due 2021
Related Party Transaction [Line Items]
Debt instrument interest rate (as a percent)								12.00%
Warrants term								5 years
Warrants to purchase common stock (in shares) | shares								988,000
Common stock price per share (in dollars per share) | $ / shares								$ 5
Leucadia | Securities Purchase Agreement | 12% Senior Secured Second Lien Notes Due 2021 | Maximum
Related Party Transaction [Line Items]
Debt instrument face amount								$ 49.9
EF Realisation | Class A Voting Common Stock | Board Representation Agreement
Related Party Transaction [Line Items]
Minimum ownership percentage on common stock issued and outstanding required for nominating two directors							15.00%
Minimum ownership percentage on common stock issued and outstanding required for nominating one director							10.00%
EF Realisation | Maximum | Class A Voting Common Stock
Related Party Transaction [Line Items]
Number of directors to be nominated | Director							2
EF Realisation | Minimum | Class A Voting Common Stock
Related Party Transaction [Line Items]
Number of directors to be nominated | director							1
Affiliated Entity
Related Party Transaction [Line Items]
Payments to acquire land	$ 2
Affiliated Entity | Class A Voting Common Stock
Related Party Transaction [Line Items]
Sale or distribution of common stock (in shares) | shares						4,174,259
Amount of outstanding common stock sold and distributed						17.00%
New Tech Global Ventures, LLC, And New Tech Global Environmental, LLC
Related Party Transaction [Line Items]
Cost of consultancy services		$ 1.7	$ 1.8

Contingencies and Commitments -

Contingencies and Commitments - Additional Information (Details)	12 Months Ended
	Dec. 31, 2019USD ($)rig
Loss Contingencies [Line Items]
Number of drilling rights under contract | rig	1
Aggregate drilling rate	$ 19,000
Early termination fee amount	$ 15,000

Subsequent Events - Additional

Subsequent Events - Additional Information (Details) a in Thousands	Mar. 16, 2020shares	Feb. 29, 2020awell	Jan. 31, 2020	Dec. 31, 2019shares	Dec. 31, 2018shares	Dec. 31, 2018shares
Subsequent Event
Subsequent Event [Line Items]
Reduction in capital spending program			0.25
One Of Largest Producers In The Eagle Ford | Subsequent Event
Subsequent Event [Line Items]
Oil and gas agreement, area of mutual interest | a		15
Oil and gas agreement, hold-by-production area | a		6
Oil and gas agreement, working interest		50.00%
Minimum | One Of Largest Producers In The Eagle Ford | Subsequent Event
Subsequent Event [Line Items]
Number Of Wells To Be Operated | well		3
Oil and gas agreement, carried working interest		9.00%
Maximum | One Of Largest Producers In The Eagle Ford | Subsequent Event
Subsequent Event [Line Items]
Number Of Wells To Be Operated | well		4
Oil and gas agreement, carried working interest		17.00%
Series A-1 Preferred Stock
Subsequent Event [Line Items]
Preferred stock dividends (in shares) | shares				8,544	7,816	11,784
Series A-1 Preferred Stock | Subsequent Event
Subsequent Event [Line Items]
Preferred stock dividends (in shares) | shares	2,257