Lilis Energy (LLEX) 10-K 30 Apr 20 2019 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2019	Apr. 30, 2020	Jun. 28, 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	LILIS ENERGY, INC.
Entity Central Index Key	0001437557
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Current Reporting Status	Yes
Entity Well Known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Public Float			$ 35,554,508
Entity Common Stock, Shares Outstanding (in shares)		95,422,277

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 3,753	$ 21,137
Accounts receivable, net of allowance of $448 and $25, respectively	18,146	20,546
Derivative instruments	427	2,551
Prepaid expenses and other current assets	4,438	1,851
Total current assets	26,764	46,085
Property and equipment:
Oil and natural gas properties, full cost method of accounting, net	228,855	430,379
Other property and equipment, net	421	524
Total property and equipment, net	229,276	430,903
Right-of-use assets	1,722	0
Other assets	837	3,785
Total assets	258,599	480,773
Current liabilities:
Current portion of long-term debt	115,000	0
Accounts payable	24,834	47,112
Accrued liabilities and other	13,972	14,794
Revenue payable	11,442	14,546
Derivative instruments	5,044	515
Total current liabilities	170,292	76,967
Asset retirement obligations	3,423	2,433
Long-term debt	0	157,804
Long-term derivative instruments and other non-current liabilities	3,762	4,699
Long-term deferred revenue and other long-term liabilities	73,749	52,513
Total liabilities	251,226	294,416
Commitments and Contingencies - Note 21
Stockholders’ equity (deficit):
Common stock, $0.0001 par value per share, 150,000,000 shares authorized 91,584,460 and 71,182,016 issued and outstanding as of December 31, 2019 and December 31, 2018, respectively	9	7
Additional paid-in capital	342,382	321,753
Treasury stock, 253,598 shares at cost	(997)	(997)
Accumulated deficit	(579,552)	(307,431)
Total stockholders’ equity (deficit)	(238,158)	13,332
Total liabilities, mezzanine equity and stockholders’ equity (deficit)	258,599	480,773
Series C-1 Preferred Stock
Current liabilities:
Mezzanine equity:	80,446	106,774
Series C-2 Preferred Stock
Current liabilities:
Mezzanine equity:	18,857	25,522
Series D Preferred Stock
Current liabilities:
Mezzanine equity:	29,082	40,729
Series E Preferred Stock
Current liabilities:
Mezzanine equity:	66,285	0
Series F Preferred Stock
Current liabilities:
Mezzanine equity:	$ 50,861	$ 0

Consolidated Balance Sheets _Pa

Consolidated Balance Sheets [Parenthetical] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Allowance related to accounts receivable	$ 448	$ 25
Common stock, par value (in dollars per share)	$ 0.0001	$ 0.0001
Common stock, shares authorized (in shares)	150,000,000	150,000,000
Common stock, shares issued (in shares)	91,584,460	71,182,016
Common stock, shares outstanding (in shares)	91,584,460	71,182,016
Treasury stock, shares (in shares)	253,598	253,598
Series C-1 Preferred Stock
Redeemable preferred stock, dividend rate, percentage	9.75%	9.75%
Mezzanine equity, shares authorized (in shares)	10,000,000	10,000,000
Mezzanine equity, shares issued (in shares)	100,000	100,000
Mezzanine equity, shares outstanding (in shares)	100,000	100,000
Mezzanine equity, stated value (in dollars per share)	$ 1,203	$ 1,093
Series C-2 Preferred Stock
Redeemable preferred stock, dividend rate, percentage	9.75%	9.75%
Mezzanine equity, shares authorized (in shares)	10,000,000	10,000,000
Mezzanine equity, shares issued (in shares)	25,000	25,000
Mezzanine equity, shares outstanding (in shares)	25,000	25,000
Mezzanine equity, stated value (in dollars per share)	$ 1,128	$ 1,024
Series D Preferred Stock
Redeemable preferred stock, dividend rate, percentage	8.25%	8.25%
Mezzanine equity, shares authorized (in shares)	10,000,000	10,000,000
Mezzanine equity, shares issued (in shares)	39,254	39,254
Mezzanine equity, shares outstanding (in shares)	39,254	39,254
Mezzanine equity, stated value (in dollars per share)	$ 1,107	$ 1,021
Series E Preferred Stock
Redeemable preferred stock, dividend rate, percentage	8.25%
Mezzanine equity, shares authorized (in shares)	10,000,000
Mezzanine equity, shares issued (in shares)	60,000
Mezzanine equity, shares outstanding (in shares)	60,000	0
Mezzanine equity, stated value (in dollars per share)	$ 1,069
Series F Preferred Stock
Redeemable preferred stock, dividend rate, percentage	9.00%
Mezzanine equity, shares authorized (in shares)	10,000,000
Mezzanine equity, shares issued (in shares)	55,000
Mezzanine equity, shares outstanding (in shares)	55,000	0
Mezzanine equity, stated value (in dollars per share)	$ 1,076

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Revenues:
Revenues	$ 66,063	$ 70,216
Operating expenses:
Production taxes	3,302	3,709
General and administrative	28,371	33,251
Depreciation, depletion, amortization and accretion	33,252	25,367
Impairment of oil and natural gas properties	228,324	0
Total operating expenses	313,336	79,562
Operating loss	(247,273)	(9,346)
Other income (expense):
Loss on early extinguishment of debt	(1,299)	(20,370)
Gain (loss) from commodity derivatives	(8,985)	55
Change in fair value of financial instruments	(3,573)	58,343
Interest expense	(11,426)	(32,827)
Other income	435	2
Total other income (expense)	(24,848)	5,203
Net loss before income taxes	(272,121)	(4,143)
Income tax expense	0	0
Net loss	(272,121)	(4,143)
Paid-in-kind dividends on preferred stock	(25,397)	(10,687)
Net loss attributable to common stockholders	$ (297,518)	$ (14,830)
Net loss per common share-basic and diluted: (Note 18)
Basic (in dollars per share)	$ (3.38)	$ (0.24)
Diluted (in dollars per share)	$ (3.38)	$ (0.47)
Weighted average common shares outstanding:
Basic (in shares)	87,912,362	62,854,214
Diluted (in shares)	87,912,362	78,451,341
Oil sales
Revenues:
Revenues	$ 59,015	$ 58,042
Operating expenses:
Costs of goods and services sold	16,127	13,843
Natural gas sales
Revenues:
Revenues	3,180	5,246
Natural gas liquid sales
Revenues:
Revenues	3,868	6,928
Gathering, processing and transportation
Operating expenses:
Costs of goods and services sold	$ 3,960	$ 3,392

Consolidated Statements of Chan

Consolidated Statements of Changes in Stockholders’ Equity (Deficit) - USD ($) $ in Thousands	Total	Common Shares	Additional Paid-In Capital	Treasury Shares	Accumulated Deficit
Beginning balance (in shares) at Dec. 31, 2017		53,368,331		0
Beginning balance at Dec. 31, 2017	$ (30,948)	$ 5	$ 272,335	$ 0	$ (303,288)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock-based compensation	9,000		9,000
Common stock for restricted stock (in shares)		404,093
Common stock for restricted stock	0
Common stock withheld for taxes on stock-based compensation (in shares)		(484,727)
Common stock withheld for taxes on stock-based compensation	(2,230)		(2,230)
Common stock for acquisition of oil and natural gas properties (in shares)		6,940,722
Common stock for acquisition of oil and natural gas properties	24,778	$ 1	24,777
Exercise of warrants and stock options (in shares)		5,000,834
Exercise of warrants and stock options	3,751		3,751
Common stock issued for extinguishment of debt (in shares)		5,952,763
Common stock issued for extinguishment of debt	24,585	$ 1	24,584
Reclassification of warrant derivative liabilities	223		223
Purchase of treasury stock (in shares)				(253,598)
Purchase of treasury stock	(997)			$ (997)
Dividends on preferred stock	(10,687)		(10,687)
Net loss	(4,143)				(4,143)
Ending balance (in shares) at Dec. 31, 2018		71,182,016		(253,598)
Ending balance at Dec. 31, 2018	13,332	$ 7	321,753	$ (997)	(307,431)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock-based compensation	6,506		6,506
Common stock for restricted stock (in shares)		3,178,448
Common stock for restricted stock	0
Common stock withheld for taxes on stock-based compensation (in shares)		(417,642)
Common stock withheld for taxes on stock-based compensation	(546)		(546)
Common stock for acquisition of oil and natural gas properties	0
Common stock issued for extinguishment of debt (in shares)		17,641,638
Common stock issued for extinguishment of debt	32,990	$ 2	32,988
Gain on extinguishment of debt	7,078		7,078
Dividends on preferred stock	(25,397)		(25,397)
Net loss	(272,121)				(272,121)
Ending balance (in shares) at Dec. 31, 2019		91,584,460		(253,598)
Ending balance at Dec. 31, 2019	$ (238,158)	$ 9	$ 342,382	$ (997)	$ (579,552)

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	$ (272,121)	$ (4,143)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Stock-based compensation	6,506	9,000
Bad debt recovery	422	106
Amortization of debt issuance cost and accretion of debt discount	2,460	15,656
Payable in-kind interest	1,590	12,213
Loss on early extinguishment of debt	1,299	20,370
Loss (gain) from commodity derivatives, net	8,985	(55)
Net settlements paid on commodity derivatives	(3,214)	(2,742)
Change in fair value of financial instruments	3,573	(58,343)
Deferred revenue realized	(232)	0
Impairment of oil and natural gas properties	228,324	0
Depreciation, depletion, amortization and accretion	33,252	25,367
Operating lease ROU amortization	(453)	0
Changes in operating assets and liabilities:
Accounts receivable	(6,378)	(13,226)
Prepaid expenses and other assets	(944)	(473)
Accounts payable and accrued liabilities	(31,393)	53,402
Proceeds from options associated with future midstream services	2,500	35,000
Net cash (used in) provided by operating activities	(25,824)	92,132
Cash flows from investing activities:
Acquisition of oil and natural gas properties	0	(92,410)
Proceeds from the sale of assets	16,851	17,500
Capital expenditures	(82,378)	(168,025)
Net cash used in investing activities	(65,527)	(242,935)
Cash flows from financing activities:
Proceeds from term loans, net of financing costs	0	47,806
Proceeds from revolving credit agreement, net of financing costs	56,883	72,566
Repayment of term loans and notes payable	0	(88,836)
Repayment of revolving credit agreement	(18,000)	0
Proceeds from the issuance of Series C Preferred Stock	0	122,418
Proceeds from the Värde financing arrangement, net of transaction costs	38,230	0
Partial repayment of the Värde financing arrangement	(2,600)	0
Repurchase of common stock	0	(997)
Proceeds from exercise of warrants and stock options	0	3,751
Payment for tax withholding on stock-based compensation	(546)	(2,230)
Net cash provided by financing activities	73,967	154,478
Net increase (decrease) in cash and cash equivalents	(17,384)	3,675
Cash and cash equivalents at beginning of period	21,137	17,462
Cash and cash equivalents at end of period	3,753	21,137
Supplemental disclosure:
Cash paid for interest	$ 6,488	$ 4,958

ORGANIZATION

ORGANIZATION	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
ORGANIZATION	Lilis Energy, Inc. (“Lilis” or the “Company”) is an independent oil and natural gas exploration and production company focused on the Delaware Basin in Winkler, Loving, and Reeves Counties, Texas and Lea County, New Mexico.

LIQUIDITY AND GOING CONCERN

LIQUIDITY AND GOING CONCERN	12 Months Ended
	Dec. 31, 2019
Liquidity Disclosure [Abstract]
LIQUIDITY AND GOING CONCERN	These consolidated financial statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business for the twelve-month period following the date of issuance of these consolidated financial statements. As such, the accompanying consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets and their carrying amount, or the amount and classification of liabilities that may result should the Company be unable to continue as a going concern. As of December 31, 2019, we were fully drawn against the borrowing base under our Revolving Credit Agreement (as defined in Note 11 - Long-Term Debt ), with $115.0 million of indebtedness outstanding under our Revolving Credit Agreement. As provided for in the Seventh Amendment to our Revolving Credit Agreement and as a result of a decrease in commodity prices, on January 17, 2020, the borrowing base was decreased to $90.0 million . As a result of the January 17, 2020 redetermination of the borrowing base, a borrowing base deficiency in the amount of $25.0 million (the “Borrowing Base Deficiency”) was created under the Revolving Credit Agreement. The Borrowing Base Deficiency constitutes the difference between the principal amount of borrowings currently outstanding under the Revolving Credit Agreement ( $115.0 million ) and the borrowing base as so redetermined ( $90.0 million ). On February 28, 2020, we paid $17.3 million towards the Borrowing Base Deficiency. Pursuant to the Fourteenth Amendment to the Revolving Credit Agreement, the remaining payment of $7.8 million is due June 5, 2020. The Company is seeking additional funding and considering certain strategic transactions to enable it to pay the remaining Borrowing Base Deficiency amount of $7.8 million . Unless funding or additional transactions are completed, the Company will not be able to pay the remaining Borrowing Base Deficiency. There is no assurance that such transactions will occur or that the bank group will agree to further deficiency payment extensions. If the Company is unable to repay the remaining borrowing base deficiency as and when required under the Revolving Credit Agreement, an event of default would occur under the Revolving Credit Agreement. Our next borrowing base redetermination is scheduled to occur on or about June 5, 2020. If the borrowing base is further reduced by the lenders in connection with this redetermination, we will be required to repay borrowings in excess of the borrowing base or eliminate the borrowing base deficiency by pledging additional oil and natural gas properties to secure our obligations under the Revolving Credit Agreement. Under the Revolving Credit Agreement, we have the option to affect such repayment either in full within 30 days after the redetermination or in monthly installments over a six-month period after the redetermination. We have experienced losses and negative cash flows from operations and working capital deficiencies. Additionally, our liquidity and operating forecasts have been negatively impacted by the recent decrease in commodity prices, which impacts our ability to comply with debt covenants under our Revolving Credit Agreement. The commodity prices have fallen significantly since the beginning of 2020, due in part to failed OPEC negotiations as well as concerns about the COVID-19 pandemic, which has significantly decreased worldwide demand for oil and natural gas. Our Revolving Credit Agreement contains financial covenants that require the Company to maintain a ratio of Total Debt to EBITDAX (each as defined in the Revolving Credit Agreement) (the “Leverage Ratio”) of not more than 4.00 to 1.00 and a ratio of Current Assets to Current Liabilities (each as defined in the Revolving Credit Agreement) (the “Current Ratio”) of not less than 1.00 to 1.00 as of the last day of each fiscal quarter thereafter. See Note 11-Long-term Debt for additional information regarding the financial covenants under our Revolving Credit Agreement. As of December 31, 2019, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants under the Revolving Credit Agreement. Pursuant to the Twelfth Amendment (as defined in Note 11 - Long-Term Debt ), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants, among other waivers of default, as of December 31, 2019. As of March 31, 2020, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants. Pursuant to the Fourteenth Amendment (as defined in Note 11 - Long-Term Debt ), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants as of March 31, 2020. If we are not able to pay or defer the $7.8 million Borrowing Base Deficiency due on June 5, 2020 or do not maintain compliance with our debt covenants, the obligations of the Company under the Revolving Credit Agreement may be accelerated, which would have a material adverse effect on our business. The Company does not expect to be in compliance with debt covenants in future periods without additional sources of liquidity or future amendments to the Revolving Credit Agreement. Fluctuations in oil and natural gas prices have a material impact on our financial position, results of operations, cash flows and quantities of oil, natural gas and NGL reserves that may be economically produced. Historically, oil and natural gas prices have been volatile, and may be subject to wide fluctuations in the future. If continued depressed prices persist, the Company will continue to experience operating losses, negative cash flows from operating activities, and negative working capital. In order to improve our leverage position and current ratio to meet the financial covenants under the Revolving Credit Agreement, we are currently pursuing or considering a number of actions, which in certain cases may require the consent of current lenders and stockholders. In November 2019, our board of directors formed a committee of independent directors (the “Special Committee”) tasked with reviewing and evaluating strategic alternatives that may enhance the value of the Company, including alternatives that may be available to identify and access further sources of liquidity through financing alternatives or deleveraging transactions. The Special Committee hired financial and legal advisors to advise the Special Committee on these matters. The Special Committee continues to explore financing alternatives and deleveraging transactions. We are also addressing operational matters such as adjusting our capital budget and improving cash flows from operations by continuing to reduce costs and intend to continue to pursue and consider other strategic alternatives. There can be no assurance that we will be able to implement any of these plans successfully, or that such plans, if executed, will result in the ability to pay borrowing base deficiencies, generate sufficient liquidity to continue as a going concern or comply with our Revolving Credit Agreement covenants. The factors discussed above raise substantial doubt about our ability to continue as a going concern within twelve-month period following the date of issuance of these consolidated financial statements.

BASIS OF PRESENTATION AND SUMMA

BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	NOTE 3 - BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Principles of Consolidation and Presentation The accompanying consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, Brushy Resources, Inc., ImPetro Operating, LLC, ImPetro Resources, LLC, Lilis Operating Company, LLC, and Hurricane Resources LLC. All significant intercompany accounts and transactions have been eliminated in consolidation. Use of Estimates The accompanying consolidated financial statements are prepared in conformity with GAAP which requires the Company to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities; disclosure of contingent assets and liabilities at the date of the financial statements; the reported amounts of revenues and expenses during the reporting period; and the quantities and values of proved oil, natural gas and natural gas liquid (“NGL”) reserves used in calculating depletion and assessing impairment of its oil and natural gas properties. The most significant estimates pertain to the evaluation of unproved properties for impairment, proved oil and natural gas reserves and related cash flow estimates used in the depletion and impairment of oil and natural gas properties; the timing and amount of transfers of our unevaluated properties into our amortizable full cost pool; the fair value of embedded derivatives and commodity derivative contracts, accrued oil and natural gas revenues and expenses, valuation of options and warrants, and common stock; and the allocation of general and administrative expenses. Actual results could differ significantly from these estimates. Reclassifications Certain reclassifications have been made to the prior year comparative financial statements to conform to the 2019 presentation. These reclassifications have no effect on the Company’s previously reported results of operations, stockholders’ equity or cash flows. Cash and Cash Equivalents Cash and cash equivalents include highly liquid instruments with an original maturity of three months or less are stated at cost, which approximates fair value. Accounts Receivable The Company has accounts receivable from joint interest owners of properties operated by the Company. The Company typically has the right to withhold future revenue disbursements to recover any non-payment of related joint interest billings. Management routinely assesses accounts receivable amounts to determine their collectability and accrues an allowance for uncollectible receivables when, based on the judgment of management, it is probable that a receivable will not be collected. The Company records actual and estimated oil and natural gas revenue receivable from third parties at its net revenue interest. In addition, the Company has receivables derived from sales of certain oil and natural gas production which are collateral under the Company’s credit agreements. The Company had an allowance for doubtful accounts of $0.4 million as of December 31, 2019. There was no allowance for doubtful accounts as of December 31, 2018. Fair Value of Financial Instruments As of December 31, 2019 , and 2018 , the carrying value of cash and cash equivalents, accounts receivable, accounts payable, accrued liabilities, revenue payable and advances from joint interest partners approximates fair value due to the short-term nature of such items. The carrying value of the Company’s secured debt is carried at cost which approximates the fair value of the debt as the related interest rates approximates interest rates currently available to the Company. Oil and Natural Gas Properties The Company uses the full cost method of accounting for oil and natural gas operations. Under this method, costs related to the exploration, non-production related development and acquisition of oil and natural gas reserves are capitalized. Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling, developing and completing productive wells, and any other costs directly related to acquisition and exploration activities. Proceeds from property sales are generally applied as a credit against capitalized exploration and development costs, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of proved reserves. Depletion of exploration and development costs and depreciation of wells and tangible production assets is computed using the units-of-production method based upon estimated proved oil and natural gas reserves. Costs included in the depletion base to be amortized include (a) all proved capitalized costs including capitalized asset retirement costs net of estimated salvage values, less accumulated depletion, and (b) estimated future development cost to be incurred in developing proved reserves, that are not otherwise included in capitalized costs. Under the full cost method of accounting, capitalized oil and natural gas property costs less accumulated depletion (net of deferred income taxes) may not exceed an amount equal to the sum of the present value, discounted at 10% , of estimated future net revenues from proved oil and natural gas reserves and the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are not subject to amortization. Should capitalized costs exceed this ceiling, an impairment expense is recognized. The present value of estimated future net cash flows was computed by applying a flat oil price to forecast revenues from estimated future production of proved oil and natural gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves (assuming the continuation of existing economic conditions), less any applicable future taxes. For the year ended December 31, 2019 , the ceiling value of the Company’s reserves was calculated based upon SEC pricing of $55.69 per barrel for oil and $2.58 per MMBtu for natural gas. For the year ended December 31, 2018 , the ceiling value of the Company’s reserves was calculated based upon SEC pricing of $65.56 per barrel for oil and $3.10 per MMBtu for natural gas. Full-cost ceiling impairments totaling $228.3 million were recorded for the year ended December 31, 2019 and resulted primarily from decreased commodity prices and reduction in expected PUDs used in preparation of estimated future net revenues from proved oil and natural gas reserves as compared to the commodity prices used for the year ended December 31, 2018 , when no such impairments were recognized. The costs of unproved oil and natural gas properties are excluded from amortization until the properties are evaluated. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved oil and natural gas reserves are established or if impairment is determined. Unproved oil and natural gas properties are assessed periodically, at least annually, to determine whether impairment had occurred. The assessment considers the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, the economic viability of development if proved reserves were assigned and other current market conditions. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and were then subject to amortization. Wells in Progress Wells in progress connotes wells that are currently in the process of being drilled or completed or otherwise under evaluation as to their potential to produce oil and natural gas reserves in commercial quantities. Such wells continue to be classified as wells in progress and withheld from the depletion calculation and the ceiling test until such time as either proved reserves can be assigned, or the wells are otherwise abandoned. Upon either the assignment of proved reserves or abandonment, the costs for these wells are then transferred to the full cost pool and become subject to both depletion and the ceiling test calculations in accordance with full cost accounting under Rule 4-10 of Regulation S-X of the Securities Exchange Act of 1934, as amended. Capitalized Interest For significant oil and natural gas investments in unproved properties, and significant exploration and development projects that have not commenced production, interest is capitalized as part of the historical cost of developing and constructing assets. Capitalized interest is determined by multiplying the Company’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depreciation or impairment. As of December 31, 2019 , there were no significant exploratory projects on unproved properties and none of the development projects exceeded the interest capitalization qualifying asset limit. As a result, no interest was capitalized as of December 31, 2019 and 2018 . Other Property and Equipment Property and equipment include vehicles, office equipment and furniture which are stated at cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets. The estimated useful lives of property and equipment range from 4 to 20 years. The Company recorded approximately $0.2 million and $0.1 million of depreciation for the years ended December 31, 2019 and 2018 , respectively. Asset Retirement Obligation s The Company incurs retirement obligations for certain assets at the time they are placed in service. The fair values of these obligations are recorded as liabilities on a discounted basis. The costs associated with these liabilities are capitalized as part of the related assets and depreciated. Over time, the liabilities are accreted for the change in their present value. For purposes of depletion, the Company includes estimated dismantlement and abandonment cost, net of salvage values, associated with future development activities that have not yet been capitalized as asset retirement obligations. Asset retirement obligations incurred are classified as Level 3 (unobservable inputs) fair value measurements. Revenue Recognition Revenue is recognized when control passes to the purchaser which generally occurs when production is transferred to the purchaser. The Company measures revenue as the amount of consideration it expects to receive in exchange for the commodities transferred. All of the Company’s revenues from contracts with customers represent products transferred at a point in time as control is transferred to the customer. The Company records revenue based on consideration specified in its contracts with its customers. The amounts collected on behalf of third parties are recorded in revenue payable. The Company recognizes revenue in the amount that reflects the consideration it expects to receive in exchange for transferring control of those goods to the customer. The contract consideration in the Company’s variable price contracts is typically allocated to specific performance obligations in the contract according to the price stated in the contract. Payment is generally received one or two months after the sale has occurred. Stock based Compensation The Company applies a fair value method of accounting for stock based compensation, which requires recognition in the financial statements of the cost of services received in exchange for equity awards. For equity awards, compensation expense is based on the fair value on the grant date or modification date and is recognized in the Company’s financial statements over the vesting period. The Company utilizes the Black-Scholes Merton option-pricing model to measure the fair value of stock options based on several criteria, including but not limited to, the valuation model used and associated input factors, such as expected term of the award, stock price volatility, risk free interest rate, dividend rate. These inputs are subjective and are determined using management’s judgment. If differences arise between the assumptions used in determining stock based compensation expense and the actual factors, which become known over time, the Company may change the input factors used in determining future stock based compensation expense. The fair value of restricted stock awards is identified as the closing stock price on the day the award was granted. The Company recognizes forfeitures as and when the stock awards are forfeited. The Company accounts for warrant grants to nonemployees whereby the fair values of such warrants are determined using the option pricing model at the earlier of the date at which the nonemployee’s performance is complete or a performance commitment is reached. Income Taxes The Company uses the asset and liability method in accounting for income taxes. Deferred tax assets and liabilities are recognized for temporary differences between financial statement carrying amounts and the tax bases of assets and liabilities and are measured using the tax rates expected to be in effect when the differences reverse. Deferred tax assets are also recognized for operating loss and tax credit carry forwards. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the results of operations in the period that includes the enactment date. A valuation allowance is used to reduce deferred tax assets when uncertainty exists regarding their realization. The Company recognizes its tax benefits only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely to be realized upon settlement. A liability for “unrecognized tax benefits” is recorded for any tax benefits claimed that do not meet these recognition and measurement standards. As of December 31, 2019 and 2018 , the Company has determined that no liability is required to be recognized. The Company’s policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense. No interest or penalties were required to be accrued at December 31, 2019 and 2018 . Further, the Company does not expect that the total amount of unrecognized tax benefits will significantly increase or decrease during the next 12 months. Concentration of Credit Risk The Company operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payment for costs associated with the property and seeks reimbursement from the other joint interest owners in the property for their portion of those costs. When warranted, prepayments are required from joint interest owners for drilling and completion projects. Joint interest owners consist primarily of independent oil and natural gas producers whose ability to reimburse the Company could be negatively impacted by adverse market conditions. The purchasers of the Company’s oil, natural gas and NGL production consist primarily of independent marketers, major oil and natural gas companies, refiners and natural gas pipeline companies. Credit evaluations are performed on the Company’s purchasers of its production and their financial condition is monitored on an ongoing basis. Based on those evaluations and monitoring, the Company may obtain letters of credit or parental guarantees from some purchasers. All of the Company’s oil and natural gas derivative transactions are carried out in the over-the-counter market and are not typically subject to margin-deposit requirements. The use of derivative transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. The Company monitors the credit ratings of its derivative counterparties on an ongoing basis. If a counterparty were to default on its obligations to the Company under the derivative contracts or seek bankruptcy protection, it could have a material adverse effect on its ability to fund planned activities and could result in a larger percentage of our future production being subject to commodity price volatility. In addition, in poor economic environments and tight financial markets, the risk of a counterparty default is heightened and fewer counterparties may participate in derivative transactions, which could result in greater concentration of exposure to any one counterparty or a larger percentage of the Company’s future production being subject to commodity price changes. Derivative Instruments All derivative instruments are recorded on the consolidated balance sheet at fair value as either an asset or a liability with changes in fair value recognized currently in earnings. Although derivative instruments are used by the Company to manage the price risk attributable to its expected oil and natural gas production, those derivative instruments have not been designated as accounting hedges under the accounting guidance. All of our derivatives are accounted for as mark-to-market activities. Under ASC Topic 815, “Derivatives and Hedging,” these instruments are recorded on the consolidated balance sheets at fair value as either short term or long-term assets or liabilities based on their anticipated settlement date. The Company nets derivative assets and liabilities by commodity for counterparties where a legal right to such offset exists. Changes in the derivatives’ fair values are recognized in current earnings since the Company has elected not to designate its current derivative contracts as cash flow hedges for accounting purposes. The Company has recognized certain conversion features within its Second Lien Term Loan as embedded derivatives that have been bifurcated from the Second Lien Term Loan, as defined in Note 9 - Derivatives , and accounted for separately from the debt. The Company has recognized that our crude oil sales agreement with ARM no longer meets the criteria for the “normal purchase normal sales” exception under ASC 815, “Derivatives and Hedging,” due to the Company not meeting the minimum quantities deliverable under the contract and the net settlement criteria being met. As a result, an embedded derivative exists as it is no longer probable the contract will only result in physical deliveries of crude oil and may net settle. See Note 9 - Derivatives for additional information. Recently Adopted Accounting Standards In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (ASU) No. 2016-02, Leases (Topic 842), a standard on lease accounting requiring a lessee to recognize assets and liabilities on the balance sheet for leases with lease terms greater than 12 months. This standard was effective for annual and interim periods beginning after December 15, 2018. We adopted this standard effective January 1, 2019, utilizing a modified retrospective transition approach. We chose to use the effective date as our date of initial application. Consequently, financial information was not updated and the disclosures required under the new standard were not provided for dates and periods before January 1, 2019. The standard includes optional transition practical expedients intended to simplify its adoption. We elected to adopt the package of practical expedients, which allowed us to retain the historical lease classification, including treatment for land easements, determined under legacy GAAP as well as a relief from reviewing expired or existing contracts to determine if they contain leases. This standard does not apply to the Company’s leases that provide the right to explore for minerals, oil, or natural gas resources. Upon adoption, we recognized operating lease liabilities totaling approximately $7.5 million, with corresponding right of use assets totaling $7.4 million. The liabilities were calculated as the present value of the remaining minimum rental payments for existing operating leases. This standard did not materially impact our consolidated net earnings and had no impact on our cash flows (see Note 10 - Leases ). Accounting Standards Not Yet Adopted In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments , which replaces the currently required incurred loss methodology with an expected loss methodology. This new methodology requires that a financial asset measured at amortized cost be presented at the net amount expected to be collected. The update is intended to provide financial statement users with more useful information about expected credit losses on financial instruments. The amended standard is effective for the Company on January 1, 2023, with early adoption permitted, and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Company is evaluating the impact the adoption of ASU 2016-13 will have on its consolidated financial statements. In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement , which modifies the fair value disclosure requirements based on application of the disclosure framework. The provisions removed or amended certain disclosures and in some cases, the ASU requires additional disclosures. The standard is effective for the Company for fiscal years, and interim periods within those years, beginning after December 15, 2019. The Company is evaluating the impact the adoption of ASU 2018-13 will have on its consolidated financial statements. Accrued Liabilities and Other At December 31, 2019 and 2018 , the Company’s accrued liabilities consisted of the following: 2019 2018 (In thousands) Accrued personnel costs $ — $ 2,300 Accrued drilling and completion costs 5,021 2,849 Drilling advances 1,328 5,001 Accrued production expenses 3,326 2,926 Other accrued liabilities 3,885 1,718 Short-term operating lease liabilities 412 — $ 13,972 $ 14,794

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES	12 Months Ended
	Dec. 31, 2019
Extractive Industries [Abstract]
OIL AND NATURAL GAS PROPERTIES	NOTE 4 - OIL AND NATURAL GAS PROPERTIES The following table sets forth a summary of oil and natural gas property costs (net of divestitures) at December 31, 2019 and 2018 : December 31, 2019 2018 (In thousands) Oil and natural gas properties: Proved $ 478,569 $ 358,858 Unproved 109,590 169,863 Total oil and natural gas properties 588,159 528,721 Accumulated depletion, depreciation, amortization and impairment (359,304 ) (98,342 ) Oil and natural gas properties, net $ 228,855 $ 430,379 The following table sets forth a summary of costs withheld from amortization as of December 31, 2019: Year of Acquisition Total 2019 2018 2017 (In thousands) Unamortized costs: Unproved leasehold costs $ 109,590 $ 1,643 $ 85,598 $ 22,349 Total $ 109,590 $ 1,643 $ 85,598 $ 22,349 For the years ended December 31, 2019 and 2018 , $56.2 million and $11.1 million, respectively, of unproved property costs were recorded as impairments of unproved property costs and transferred to proved properties. Impairments for 2019 were the result of title defects, lease expirations, changes to management’s development plans and uncertainty that the Company will have access to necessary funding to either extend the leases expiring in 2020 or begin drilling before their expiration dates. The 2018 impairment of $11.1 million was the result of defective titles for certain leases. Depreciation, depletion and amortization expense related to proved properties was approximately $32.6 million and $25.2 million, respectively for the years ended December 31, 2019 and 2018 . Full-cost ceiling impairments totaling $228.3 million were recorded for the year ended December 31, 2019 . For the year ended December 31, 2018 , no such impairments were recognized. The 2019 impairment charges were the result of a decrease in crude oil and natural gas prices used in preparation of the proved reserves estimates. Additionally, proved undeveloped reserves previously included in the Company’s proved reserves report were reclassified as unproved because of the uncertainty regarding the availability of capital for development those reserves as of December 31, 2019. The reclassification of proved undeveloped reserves to unproved are recognized in the Company’s proved reserves report as of December 31, 2019. These changes have contributed, in part, to higher depletion rates for 2019 as compared to 2018.

ACQUISITIONS AND DIVESTITURES

ACQUISITIONS AND DIVESTITURES	12 Months Ended
	Dec. 31, 2019
Business Combinations and Divestitures [Abstract]
ACQUISITIONS AND DIVESTITURES	NOTE 5 - ACQUISITIONS AND DIVESTITURES Divestitures During 2019 On July 31, 2019, the Company entered into two agreements with Winkler Lea Royalty, L.P. (“WLR”) and Winkler Lea WI, L.P. (“WLWI”) for the sale of an overriding royalty interest and a non-operated working interest in undeveloped assets, respectively, for combined cash proceeds of $39.0 million , including WLWI’s drilling advance (the “Asset Sales”). WLR and WLWI are affiliates of Värde Partners, Inc., a related party (see Note 13 - Related Party Transactions ). The Company entered into a Purchase and Sale Agreement with WLR (the “ORRI Agreement”), pursuant to which the Company sold to WLR an overriding royalty interest (the “ORRI”) in approximately 1,446 net royalty acres in Winkler and Loving Counties, Texas, and Lea County, New Mexico. The ORRI is equal to the positive difference, if any, between 25% and existing royalties and other burdens, subject to proportionate reduction and the other terms and conditions set forth in the instrument of conveyance. The ORRI Agreement provides the Company with a right to repurchase all, but not less than all, of the ORRI for a period of three years and an obligation, at WLR’s election only upon a change of control, to repurchase all, but not less than all, of the ORRI, and also includes certain limitations on WLR’s right to transfer the ORRI during such three year period without the consent of the Company. The repurchase price for the first two years of the repurchase period is 1.5 times the purchase price paid by WLR, less the proportionate share of production paid by the Company. For the third year, the repurchase price is the same with the multiplier increased to 1.75 . After the third year, the repurchase period expires. The Company entered into a Purchase and Sale Agreement with WLWI (the “WI Agreement”), pursuant to which the Company sold an undivided 49% of its right, title and interest in certain undeveloped assets located in Winkler and Loving Counties, Texas, consisting of approximately 749 net acres. The WI Agreement provides that the Company must drill, complete and equip five commitment wells after closing (the “Development Plan”). Contemporaneously with the purchase, WLWI paid a drilling advance which funded its proportionate share of the development costs to drill, complete and equip such commitment wells. Any drilling cost overruns or costs incurred below estimated costs are the responsibility of the Company. As of December 31, 2019 , three of the five commitment wells are producing, the fourth well is drilled and awaiting completion and the fifth well has not yet been drilled. Under the WI Agreement, the fourth and fifth wells are required to begin production mid-year 2020, subject to reasonable delays on account of Force Majeure or modifications or revisions to the Development Plan as approved by both parties. Should the Company otherwise breach the scheduled Development Plan, WLWI shall be entitled to liquidated damages of an amount equal to $150,000 plus $1,500 for each day beyond a 60 -day period after Development Plan commitment date until the actual date of first production. The WI Agreement provides the Company with a right to repurchase all, but not less than all, of the interest for a period of three years and an obligation, at WLWI’s election only upon a change of control, to repurchase all, but not less than all, of the interest, and also includes certain limitations on WLWI’s right to transfer the interest during such three year period without the consent of the Company. The repurchase price is 1.5 times the consideration paid by WLWI plus additional capital expenditures of WLWI. The repurchase period expires after three years . As a result of the repurchase rights, the agreements with WLR and WLWI do not meet the criteria for a conveyance or sale of assets under ASC 932, “Extractive Activities - Oil & Gas”, and are accounted for as a financing arrangement. The net proceeds of the transaction of $39.0 million are included in long-term deferred revenue and other long-term liabilities on the Company’s consolidated balance sheet as of December 31, 2019 . WLR’s proportionate share of revenue of $0.4 million and WLWI’s proportionate share of net revenues, (revenues less production costs), of $0.5 million for the year ended December 31, 2019 is included in interest expense on the Company’s consolidated statements of operations. On August 16, 2019, we sold approximately 513 noncontiguous net acres in New Mexico for net cash proceeds of $16.7 million, which was recorded as a reduction to the full cost pool. The Company repurchased certain overriding royalty interests in the acreage previously sold to WLR under the ORRI Agreement for $2.6 million , resulting in a $1.3 million loss on extinguishment of a portion of the financing arrangement and is included in loss on early extinguishment of debt on the Company’s consolidated statements of operations. On February 28, 2020, the Company closed on the sale of approximately 1,185 undeveloped net acres in Lea County, New Mexico, for net cash proceeds of approximately $24.1 million, subject to customary purchase price adjustments (the “Marlin Disposition”). The proceeds were used to fund a substantial portion of the Borrowing Base Deficiency with the balance to be used for general corporate purposes. Acquisitions During 2018 During the year ended December 31, 2018 , the Company acquired the following oil and natural gas properties: • Certain leasehold acreage in the Delaware Basin in Lea County, New Mexico from OneEnergy Partners Operating, LLC for $40.0 million in cash and 6,940,722 shares of the Company’s common stock valued at approximately $24.9 million, for total consideration of approximately $64.9 million . Transaction costs associated with this acquisition were approximately $1.1 million. The transaction was recorded as an asset acquisition. • Certain leasehold interests and other oil and natural gas assets in Loving and Winkler Counties, Texas from VPD Texas, L.P. for total cash consideration of approximately $11.1 million , including approximately $0.5 million of related acquisition costs. The transaction was recorded as an asset acquisition. • Certain leasehold interests and other oil and natural gas assets in Loving and Winkler Counties, Texas from Anadarko for total cash consideration of $7.1 million. The transaction was recorded as an asset acquisition. • Certain leasehold interests and other oil and natural gas assets in Lea County, New Mexico from Ameradev II, LLC for total cash consideration of $7.2 million and was recorded as an adjustment to the full cost pool. • Certain leasehold interests and other oil and natural gas assets in Loving and Winkler Counties, Texas from Felix Energy Holdings II, LLC for total cash consideration of $0.4 million and was recorded as an adjustment to the full cost pool. • Proved property and certain leasehold interests located in Winkler County, Texas from Southwest Royalties, LLC for total consideration of approximately $17.0 million . The acquisition was accounted for as a business combination. Therefore the purchase price was allocated to the assets acquired and liabilities assumed based on their estimated acquisition date fair values available at closing. Transaction costs associated for this acquisition were immaterial and were expensed in the Consolidated Statements for Operations during the year ended December 31, 2018. Revenues and operating expenses associated with the proved properties were insignificant to the December 31, 2018 Consolidated Statements of Operations. The following table presents the final allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date: As of October 16, 2018 (In thousands) Fair value of net assets: Proved oil and natural gas properties $ 12,562 Unproved oil and natural gas properties 4,542 Total assets acquired 17,104 Asset retirement obligations assumed (65 ) Fair value of net assets acquired $ 17,039

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT OBLIGATIONS	NOTE 6 - ASSET RETIREMENT OBLIGATIONS The Company’s asset retirement obligations (“ARO”) represent the present value of the estimated cash flows expected to be incurred to plug, abandon and remediate producing properties, excluding salvage values, at the end of their productive lives in accordance with applicable laws. Revisions in estimated liabilities during the period relate primarily to changes in estimates of asset retirement costs. Revisions in estimated liabilities can also include, but are not limited to, revisions of estimated inflation rates, changes in property lives and expected timing of settlement. The following table summarizes the changes in the Company’s ARO for the years ended December 31, 2019 and 2018 : For the Year Ended December 31, 2019 2018 (In thousands) ARO, beginning of period $ 2,444 $ 952 Additional liabilities incurred 186 374 Accretion expense 433 85 Liabilities settled (78 ) (87 ) Revision in estimates 438 1,120 ARO, end of period 3,423 2,444 Less: current portion of ARO (1) — (11 ) ARO, non-current $ 3,423 $ 2,433 (1) The current portion of ARO is included in accrued liabilities in the consolidated balance sheets.

REVENUE

REVENUE	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
REVENUE	NOTE 7 - REVENUE Revenue is recognized when control passes to the purchaser, which generally occurs when production is transferred to the purchaser. The Company measures revenue as the amount of consideration it expects to receive in exchange for the commodities transferred. All the Company’s revenues from contracts with customers represent products transferred at a point in time as control is transferred to the customer. The Company records revenue based on consideration specified in its contracts with its customers. The amounts collected on behalf of third parties are recorded in revenue payable. The Company recognizes revenue in the amount that reflects the consideration it expects to receive in exchange for transferring control of those goods to the customer. The contract consideration in the Company’s variable price contracts is typically allocated to specific performance obligations in the contract according to the price stated in the contract. Payment is generally received one or two months after the sale has occurred. Crude Oil Revenues Crude oil from our operated properties is produced and stored in field tanks. The Company recognizes crude oil revenue when control passes to the purchaser. Effective January 1, 2019 through February 28, 2019, the Company’s crude oil was sold under a single short-term contract. The purchaser’s commitment included all quantities of crude oil from the leases that were covered by the contract, with no quantity-based restrictions or variable terms. Pricing was based on posted indexes for crude oil of similar quality, less a negotiable fees deduction of $ 5.15 per barrel. Effective March 1, 2019, the Company’s crude oil is sold under a single long-term contract with a term that extends to at least December 31, 2024. The purchaser’s commitment has a quantity-based minimum set forth in the contract, measured in barrels per day, with the minimum quantity commitment increasing at periodic intervals over the life of the contract to coincide with the Company’s expected growth in production. Pursuant to the long-term contract, pricing is based on posted indexes for crude oil of similar quality, with a differential based on pipeline delivery to Houston, as opposed to the previous contract differential based on truck delivery to Midland-Cushing, along with a differential basis reduction of $9.25 per barrel that was effective from March 1, 2019 through June 30, 2019, which decreased to $6.50 per barrel for the period of July 1, 2019 through June 30, 2020, and then to $4.95 per barrel for the period from July 1, 2020 through December 31, 2024. The posted index prices and differentials change monthly based on the average of daily index price points for each sales month. The purchaser’s affiliate shipper also charges a tariff fee of $0.75 as a deduction from the received price (see Note 12 - Long-Term Deferred Revenue Liabilities and Other Long-Term Liabilities ). Natural Gas and NGL Revenues Natural gas from our properties is produced and transported via pipelines to gas processing facilities. NGLs are extracted from the natural gas at the processing facilities and processed natural gas and NGLs are marketed and sold separately on the Company’s behalf after processing. All our operated natural gas production is sold under one of two natural gas contracts, both of which are long-term in nature; however, one of these natural gas contracts includes 30-day cancellation provisions, and the Company therefore classifies such contract as short-term. The processor’s commitment to sell on the Company’s behalf includes all quantities of natural gas and NGLs produced from specific wellbores or dedicated acreage as defined in the contract, with no quantity-based restrictions or variable terms. Pricing under the gas contracts is generally market-based pricing less adjustments for transportation and processing fees. A portion of natural gas delivered to the processing plants is used as fuel at the processing plant without reimbursement. The Company recognizes revenue for natural gas and NGLs when control passes at the tailgate of the processing plant. Gathering, Processing and Transportation Natural gas must be transported to a gas processing plant facility for treatment and to extract NGLs, then the final residue gas and liquid products are marketed for sale to end users at the tailgate of the plant. As a result of these activities, the Company incurs costs that are contractually passed to it from the gatherer per customary industry practice. Such costs include fees for gathering the gas and moving it from wellhead to plant inlet, plant electricity usage, inlet compression, carbon dioxide and hydrogen sulfide treatments, processing tax, fuel usage, and marketing at the tailgate. Gathering, processing and transportation costs are presented as operating expenses in the consolidated statement of operations. Imbalances Natural gas imbalances occur when the Company sells more or less than its entitled ownership percentage of total natural gas production. Any amount received in excess of its share is treated as a liability. If the Company receives less than its entitled share, the under production is recorded as a receivable. The Company did not have any significant natural gas imbalance positions as of December 31, 2019 and 2018 . Contract balances and prior period performance obligations The Company is entitled to payment from purchasers once its performance obligations have been satisfied upon delivery of the product, at which point payment is unconditional, and the Company records these invoiced amounts as accounts receivable in its condensed consolidated balance sheets. To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and also recorded as accounts receivable in the accompanying consolidated balance sheets. In this scenario, payment is unconditional, as the Company has satisfied its performance obligations through delivery of the relevant product. As a result, the Company has concluded that its product sales do not give rise to contract assets or liabilities. The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and NGL sales may not be received for 30 to 60 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production that was delivered to the customer and the price that will be received for the sale of the product. Additionally, to the extent actual volumes and prices of oil, natural gas and NGLs are unavailable for a given reporting period because of timing or information not received from third-party purchasers, the expected sales volumes and prices for those barrels of oil, cubic feet of gas and gallons of NGL are also estimated. 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. The Company has existing internal controls in place for its estimation process, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. Significant judgments 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 the Company’s behalf per gas purchase contracts. These types of transactions require judgment to determine whether the Company is the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net. The Company maintains control of the natural gas and NGLs during processing and considers itself the principal in these arrangements. Practical expedients A significant number of the Company’s product sales are short-term in nature with contract term of one year or less. For those contracts, the Company utilizes the practical expedient that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For the Company’s product sales that have contract terms less than one year, the Company utilizes the practical expedient in the new revenue standard that states that it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. The following table disaggregates the Company’s revenue by contract type ( in thousands ) for the year ended December 31, 2019 : Year Ended December 31, 2019 Short-term contracts Long-term contracts Total Crude oil $ 9,711 $ 49,304 $ 59,015 Natural gas 220 2,960 3,180 NGLs 188 3,680 3,868 Customer Credit Risk Our principal exposure to credit risk is through receivables from the sale of our oil and natural gas production of approximately $9.1 million and $8.2 million at December 31, 2019 and 2018 , respectively, and through actual and accrued receivables from our joint interest partners of approximately $9.5 million and $11.4 million at December 31, 2019 and 2018 , respectively. We are subject to credit risk due to the concentration of our oil and natural gas receivables with our most significant customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. Major Customers During the year ended December 31, 2019 , the Company’s major customers as a percentage of total revenue consisted of the following: Year ended December 31, 2019 2018 ARM Energy Management, LLC 68 % — % Texican Crude & Hydrocarbon, LLC 19 % 87 % Lucid Energy Delaware, LLC 12 % 10 % Other below 10% 1 % 3 % 100 % 100 %

FAIR VALUE OF FINANCIAL INSTRUM

FAIR VALUE OF FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
FAIR VALUE OF FINANCIAL INSTRUMENTS	NOTE 8 - FAIR VALUE OF FINANCIAL INSTRUMENTS The Company measures the fair value of its financial assets on a three-tier value hierarchy, which prioritizes the inputs used in the valuation methodologies in measuring fair value: ● Level 1 - Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets. ● Level 2 - Other inputs that are directly or indirectly observable in the marketplace. ● Level 3 - Unobservable inputs which are supported by little or no market activity. The fair value hierarchy also requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Determination of the fair values of our derivative contracts incorporates various factors, including not only the impact of our non-performance risk on our liabilities, but also the credit standing of the counterparties involved. The Company utilizes counterparty rate of default values to assess the impact of non-performance risk when evaluating both our liabilities to, and receivables from, counterparties. Recurring Fair Value Measurements Fair Value Measurement Classification Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total (In thousands) As of December 31, 2019 Oil and natural gas derivative instruments: Oil and natural gas derivative swap contracts $ — $ (3,932 ) $ — $ (3,932 ) Oil and natural gas derivative collar contracts — 301 — 301 Embedded derivative instruments: Net settlement provisions under ARM sales agreement — — (3,238 ) (3,238 ) Total $ — $ (3,631 ) $ (3,238 ) $ (6,869 ) As of December 31, 2018 Oil and natural gas derivative instruments: Oil and natural gas derivative swap contracts $ — $ (2,923 ) $ — $ (2,923 ) Oil and natural gas derivative collar contracts — 4,047 — 4,047 Embedded derivative instruments: Second Lien Term Loan conversion features — — (1,965 ) (1,965 ) Total $ — $ 1,124 $ (1,965 ) $ (841 ) Derivative assets and liabilities include unsettled amounts related to commodity derivative positions, including swaps and collars, as of December 31, 2019 and 2018 . The fair value of the Company’s derivatives is based on third-party pricing models which utilize inputs that are either readily in the public market or which can be corroborated from active markets of broker quotes. Swaps and collars generally have observable inputs and these instruments are measured using Level 2 inputs. In addition, derivative liabilities as of December 31, 2019 include an embedded derivative associated with the ARM sales agreement (see Note 21 - Commitments and Contingencies ). The Company recognized a derivative liability and an unrealized loss of $3.2 million as of December 31, 2019 . This embedded derivative has fewer observable inputs from objective sources and are therefore measured using Level 3 inputs. The fair value of the net settlement provisions under the agreement was determined based on certain assumptions including (1) forward pricing for crude oil basis differentials, (ii) future LIBOR rates and (iii) the Company’s implied credit rating. The Company’s derivative liabilities as of December 31, 2018 also include embedded derivatives associated with the Second Lien Term Loan (as defined in Note 11 - Long-Term Debt ). These instruments have fewer observable inputs from objective sources and are therefore measured using Level 3 inputs. The Company recorded an unrealized loss of $0.3 million and $58.3 million on the change in fair value of derivative liabilities associated with the Second Lien Term Loan conversion features for the years ended December 31, 2019 and 2018, respectively. The fair value of the holder conversion features was determined using a binomial lattice model based on certain assumptions including (i) the Company’s stock price, (ii) risk-free rate, (iii) expected volatility, (iv) the Company’s implied credit rating, and (v) the implied credit yield of the Loan. The following table sets forth a reconciliation of changes in the fair value of the Company’s financial assets and liabilities classified as Level 3 in the fair value hierarchy, except for the commodity derivatives classified as Level 2, as disclosed in Note 9 , as of December 31, 2019 and 2018 : Firm Takeaway and Pricing Agreement Net Settlement Provisions Second Lien Term Loan Conversion Features Total (in thousands) Balance at January 1, 2019 $ — $ (1,965 ) $ (1,965 ) Fair value of the converted portion of the embedded derivatives associated with the Second Lien Term Loan — 2,300 2,300 Fair value of the embedded derivatives in ARM Sales Agreement (3,238 ) (335 ) (3,573 ) Balance at December 31, 2019 $ (3,238 ) $ — $ (3,238 ) Second Lien Term Loan Conversion Features Warrant Liabilities Total (in thousands) Balance at January 1, 2018 $ (72,714 ) $ (223 ) $ (72,937 ) Transferred to equity — 223 223 Fair value of the converted portion of the embedded derivatives associated with the Second Lien Term Loan 12,406 — 12,406 Change in fair value of derivative liabilities 58,343 — 58,343 Balance at December 31, 2018 $ (1,965 ) $ — $ (1,965 )

DERIVATIVES

DERIVATIVES	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVES	NOTE 9 - DERIVATIVES The Company’s derivative instruments as of December 31, 2019 and 2018 , include the following: December 31, 2019 2018 (In thousands) Derivative assets (liabilities): Derivative assets - current $ 427 $ 2,551 Derivative assets - non-current (1) 187 1,822 Derivative liabilities - current (3) (5,044 ) (515 ) Derivative liabilities - non-current (2) (3) (4) (2,439 ) (4,699 ) Total derivative liabilities, net $ (6,869 ) $ (841 ) (1) The non-current derivative assets are included in other assets in the consolidated balance sheets. (2) The non-current derivative liabilities are included in long-term derivative instruments and other non-current liabilities in the consolidation balance sheets. (3) The ARM sales agreement includes an embedded derivative. As of December 31, 2019 , the embedded derivative is included as current liabilities and non-current liabilities of $0.8 million and $2.4 million, respectively. (4) Includes $2.0 million embedded derivative associated with Second Lien Term Loan and $2.7 million in commodity derivatives as of December 31, 2018 . Embedded Derivatives As discussed in Note 21 - Commitments and Contingencies , the ARM sales agreement contains minimum quantity commitments. Should the Company be unable to meet those minimum commitments, the agreement contains a two way make whole provision that allows for net settlement. As of December 31, 2019 , the Company concluded it is no longer probable they will be able to make delivery of the minimum quantities specified in the agreement. The Company has, therefore recorded the fair value of the embedded derivative as of December 31, 2019 . The net settlement feature for remaining future minimum commitment volumes are considered embedded derivatives that are recorded, with changes in fair value included in the Company’s consolidated statement of operations. As of December 31, 2019, the derivative liability associated with the ARM sales agreement was approximately $3.2 million with $0.8 million recorded in current derivative instruments and $2.4 million recorded in long-term derivative instruments on the Company’s consolidated balance sheets. As discussed in Note 11 - Long-Term Debt , the Second Lien Term Loan contained conversion features that were exercisable at the option of the lead lender thereunder or, in certain circumstances, the Company. The conversion features have been identified as embedded derivatives which (i) contain economic characteristics that are not clearly and closely related to the host contract, the Second Lien Term Loan, and (ii) are separate, stand-alone instruments with similar terms that would qualify as derivative instruments. As such, the conversion features were bifurcated and accounted for separately from the Second Lien Term Loan. The conversion features are recorded at fair value for each reporting period with changes in fair value included in the Company’s consolidated statement of operations for each reporting period. As of December 31, 2018 , the derivative liabilities associated with the Second Lien Term Loan were approximately $2.0 million . On March 5, 2019, the embedded derivative associated with the Second Lien Term Loan was written off against the gain on extinguishment of debt following the extinguishment of the Second Lien Term Loan on March 5, 2019, pursuant to the provisions of the 2019 Transaction Agreement (as defined in Note 11 - Long-Term Debt ) . Commodity Derivatives To reduce the impact of fluctuations in oil and natural gas prices on the Company’s revenues and to protect the economics of property acquisitions, the Company periodically enters into derivative contracts with respect to a portion of its projected oil and natural gas production through various transactions that fix or modify the future prices to be realized. The derivative contracts may include fixed-for-floating price swaps (whereby, on the settlement date, the Company will receive or pay an amount based on the difference between a pre-determined fixed price and a variable market price for a notional quantity of production), put options (whereby the Company pays a cash premium in order to establish a fixed floor price for a notional quantity of production and, on the settlement date, receives the excess, if any, of the fixed floor price over a variable market price), and costless collars (whereby, on the settlement date, the Company receives the excess, if any, of a variable market price over a fixed floor price up to a fixed ceiling price for a notional quantity of production). Our hedging activities are intended to support oil and natural gas prices at targeted levels and manage exposure to oil and natural gas price fluctuations, as well as to meet our obligations under our Revolving Credit Agreement (as defined in Note 11 - Long-Term Debt ). It is our policy to enter into derivative contracts only with counterparties that are creditworthy and competitive market makers. All of our derivatives are designated as unsecured. Certain of our derivative counterparties may require the posting of cash collateral under certain conditions. The Company does not enter into derivative contracts for speculative trading purposes. All of our derivatives are accounted for as mark-to-market activities. Under Accounting Standard Codification (“ASC”) Topic 815, “Derivatives and Hedging,” these instruments are recorded on the Company’s consolidated balance sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. The Company nets derivative assets and liabilities by commodity for counterparties where a legal right to such offset exists. Because the Company has elected not to designate its current derivative contracts as cash flow hedges for accounting purposes, changes in the fair values of the derivatives are recognized in current earnings. The following table presents the Company’s derivative position for the production periods indicated as of December 31, 2019 : Description Notional Volume (Bbls/d) Production Period Weighted Average Price ($/Bbl) Oil Positions Oil Swaps 1,028 January 2020 - December 2020 $ 56.28 Oil Swaps 370 January 2021 - December 2021 $ 53.07 Basis Swaps (1) 1,500 January 2020 - December 2020 $ (5.62 ) 3 Way Collar Floor sold price (put) 228 January 2020 - December 2020 $ 40.00 3 Way Collar Floor purchase price (put) 228 January 2020 - December 2020 $ 50.00 3 Way Collar Ceiling sold price (call) 228 January 2020 - December 2020 $ 59.60 3 Way Collar Floor sold price (put) 80 January 2021 - December 2021 $ 37.50 3 Way Collar Floor purchase price (put) 80 January 2021 - December 2021 $ 47.50 3 Way Collar Ceiling sold price (call) 80 January 2021 - December 2021 $ 59.30 Oil Collar Floor purchase price (put) 512 January 2020 - December 2020 $ 49.50 Oil Collar Ceiling sold price (call) 512 January 2020 - December 2020 $ 63.87 Oil Collar Floor purchase price (put) 742 January 2021 - December 2021 $ 50.00 Oil Collar Ceiling sold price (call) 742 January 2021 - December 2021 $ 59.70 Description Notional Volume (MMBtus/d) Production Period Weighted Average Price ($/MMBtu) Natural Gas Positions Gas Swaps 4,557 January 2020 - December 2020 $ 2.57 Gas Swaps 4,184 January 2021 - March 2021 $ 2.77 3 Way Collar Floor sold price (put) 563 January 2020 - December 2020 $ 1.60 3 Way Collar Floor purchase price (put) 563 January 2020 - December 2020 $ 2.10 3 Way Collar Ceiling sold price (call) 563 January 2020 - December 2020 $ 3.00 3 Way Collar Floor sold price (put) 133 January 2021 - December 2021 $ 1.65 3 Way Collar Floor purchase price (put) 133 January 2021 - December 2021 $ 2.15 3 Way Collar Ceiling sold price (call) 133 January 2021 - December 2021 $ 3.05 Gas Collar Floor purchase price (put) 2,748 January 2020 - December 2020 $ 2.55 Gas Collar Ceiling sold price (call) 2,748 January 2020 - December 2020 $ 3.07 Gas Collar Floor purchase price (put) 4,464 January 2021 - December 2021 $ 2.20 Gas Collar Ceiling sold price (call) 4,464 January 2021 - December 2021 $ 2.97 (1) The weighted average price under these basis swaps is the fixed price differential between the index prices of the Midland WTI and the Cushing WTI. The table below summarizes the Company’s net gain (loss) on commodity derivatives for the year ended December 31, 2019 and 2018 : Year Ended December 31, 2019 2018 (in thousands) Unrealized gain (loss) on unsettled derivatives $ (5,575 ) $ 1,977 Net settlements paid on derivative contracts (3,214 ) (2,742 ) Net settlements receivable (payable) on derivative contracts (196 ) 820 Net gain (loss) on commodity derivatives $ (8,985 ) $ 55 The following information summarizes the gross fair values of derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Company’s consolidated balance sheets as of December 31, 2019 and as of December 31, 2018 : As of December 31, 2019 Gross Amount of Recognized Assets and Liabilities Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets (In thousands) Offsetting Derivative Assets: Current assets $ 1,009 $ (582 ) $ 427 Long-term assets 359 (172 ) 187 Total assets $ 1,368 $ (754 ) $ 614 Offsetting Derivative Liabilities: Current liabilities $ (4,827 ) $ 582 $ (4,245 ) Current embedded derivative liabilities (799 ) — (799 ) Long-term commodity derivative liabilities (172 ) 172 — Long-term embedded derivative liabilities (2,439 ) — (2,439 ) Total liabilities $ (8,237 ) $ 754 $ (7,483 ) As of December 31, 2018 Gross Amount of Recognized Assets and Liabilities Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets (In thousands) Offsetting Derivative Assets: Current assets $ 4,122 $ (1,571 ) $ 2,551 Long-term assets 1,854 (32 ) 1,822 Total assets $ 5,976 $ (1,603 ) $ 4,373 Offsetting Derivative Liabilities: Current liabilities $ (2,086 ) $ 1,571 $ (515 ) Long-term commodity derivative liabilities (2,766 ) 32 (2,734 ) Long-term embedded derivative liabilities (1,965 ) — (1,965 ) Total liabilities $ (6,817 ) $ 1,603 $ (5,214 )

LEASES

LEASES	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
LEASES	NOTE 10 - LEASES Lease Recognition The Company has entered into contractual lease arrangements to rent office space, compressors, drilling rigs and other equipment from third-party lessors. Right-of-use (“ROU”) assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make future lease payments arising from the lease. Operating lease ROU assets and liabilities are recorded at commencement date based on the present value of lease payments over the lease term. Lease payments included in the measurement of the lease liability include fixed payments and termination penalties or extensions that are reasonably certain to be exercised. Variable lease costs associated with leases are recognized when incurred and generally represent maintenance services provided by the lessor, allocable real estate taxes and local sales and business taxes. Leases with an initial term of 12 months or less are not recorded on the balance sheet. The Company recognizes lease expense on a straight-line basis over the lease term. The Company does not account for lease components separately from the non-lease components. The Company uses the implicit interest rate when readily determinable; however, most of the Company’s lease agreements do not provide an implicit interest rate. As such, at implementation and for new or modified leases subsequent to January 1, 2019, the Company uses its incremental borrowing rate based on the information available at commencement date of the contract in determining the present value of future lease payments. The incremental borrowing rate is calculated using a risk-free interest rate adjusted for the Company’s risk. Operating lease ROU assets also include any lease incentives received in the recognition of the present value of future lease payments. Certain of the Company’s leases may also include escalation clauses or options to extend or terminate the lease. These options are included in the present value recorded for the leases when it is reasonably certain that the Company will exercise that option. Lease expense for lease payments is recognized on a straight-line basis over the lease term. The Company determines if an arrangement is or contains a lease at inception of the contract and records the resulting operating lease asset on the consolidated balance sheets as an asset, with offsetting liabilities recorded as a liability. The Company recognizes a lease in the consolidated financial statements when the arrangement either explicitly or implicitly involves property or equipment, the contract terms are dependent on the use of the property or equipment, and the Company has the ability or right to operate the property or equipment or to direct others to operate the property or equipment and receives greater than 10% of the economic benefits of the assets. As of December 31, 2019 , the Company does not have any financing leases. The Company has adopted the modified retrospective method for the new lease recognition rule. Therefore, prior periods are not presented as prior period amounts have not been adjusted under the modified retrospective. Refer to Note 3 - Basis of Presentation and Summary of Significant Accounting Policies for additional information. The Company’s ROU assets and operating lease liabilities were included in the consolidated balance sheets as follows (in thousands): December 31, 2019 Right of use assets: Right of use assets - long-term (1) $ 1,722 Lease liabilities: Lease liabilities - current (2) $ 412 Lease liabilities - long-term (3) 1,323 Total lease liabilities $ 1,735 (1) Right of use assets - long-term are included in other assets on the consolidated balance sheets. (2) Lease liabilities - current are included in accrued liabilities and other on the consolidated balance sheets. (3) Lease liabilities - long-term are included in long-term derivatives instruments and other non-current liabilities on the consolidated balance sheets. During the second quarter of 2019, the Company canceled a long-term drilling rig lease, within the terms of the agreement, which resulted in the write-off of the related lease liability and ROU asset of $5.4 million . During the third quarter of 2019, the Company entered into a new long-term drilling rig lease which resulting in a lease liability and ROU asset of $10.8 million . During the 4th quarter of 2019, the Company canceled the long-term drilling rig lease, within the terms of the agreement, which resulted in the write-off of the related lease liability and ROU asset of $10.4 million . Lease costs represent the straight line lease expense of ROU assets, short-term leases, and variable lease costs. The components of lease cost were classified as follows (in thousands): Year Ended December 31, 2019 Fixed lease costs $ 5,084 Short-term lease costs 1,096 Variable lease costs 575 Total lease costs $ 6,755 Lease Cost included in the Consolidated Financial Statements Year Ended December 31, 2019 Oil and natural gas properties, full cost method of accounting, net (1) Total lease costs capitalized $ 5,688 Production costs 593 General and administrative 474 Total lease costs expensed 1,067 Total lease costs $ 6,755 (1) Represents short-term lease capital expenditures related to drilling rigs for the year ended December 31, 2019 . During the year ended December 31, 2019 , the following cash activities were associated with the Company’s leases as follows (in thousands): Cash paid for amounts included in the measurement of operating lease liabilities: Operating cash flows from operating leases $ 222 Investing cash flows from operating leases $ 4,768 As of December 31, 2019 , the weighted average lease term and discount rate related to the Company’s remaining leases were as follows: Lease term and discount rate Weighted-average remaining lease term (years) 4.45 Weighted-average discount rate 5.3 % As of December 31, 2019 , minimum future payments, including imputed interest, for long-term operating leases under the scope of ASC Topic 842, “Leases”, were as follows (in thousands): Year Amount 2020 $ 477 2021 425 2022 353 2023 379 2024 315 After 2024 — Less: the effects of discounting (214 ) Present value of lease liabilities $ 1,735 As of December 31, 2018 , minimum future payments, including imputed interest, for long-term operating leases under the scope of ASC Topic 840, “Leases”, were as follows (in thousands): Year Amount 2019 $ 7,586 2020 66 2021 — 2022 — 2023 — After 2023 — Total lease commitment $ 7,652

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
LONG-TERM DEBT	NOTE 11 - LONG-TERM DEBT December 31, 2019 2018 (In thousands) 8.25% Second Lien Term Loan, due 2021, net of debt issuance costs and debt discount $ — $ 82,804 Revolving Credit Agreement, due October 2023 115,000 75,000 Total long-term debt $ 115,000 $ 157,804 Less: current portion (115,000 ) — Total long-term debt, net of current portion $ — $ 157,804 Revolving Credit Agreement On October 10, 2018, the Company entered into a five -year, $500.0 million senior secured revolving credit agreement by and among the Company, as borrower, certain subsidiaries of the Company, as guarantors (the “Guarantors”), BMO Harris Bank, N.A., as administrative agent, and the lenders party thereto (the “Revolving Credit Agreement”). The Revolving Credit Agreement provides for a senior secured reserves based revolving credit facility with an initial borrowing base of $95.0 million . The borrowing base is subject to semiannual re-determinations in May and November of each year. In December 2018, the borrowing base was increased to $108.0 million in connection with our scheduled borrowing base re-determination. On March 5, 2019, the Company’s borrowing base under the Revolving Credit Agreement was increased from $108.0 million to $125.0 million , as the result of an acceleration of the scheduled May 2019 borrowing base redetermination pursuant to the First Amendment (as defined below). As provided in the Third Amendment (as defined below) and as a result of the Asset Sales (as defined in Note 5 - Acquisitions and Divestitures ), in July 2019, the borrowing base was decreased to $115.0 million . As provided for in the Seventh Amendment and as a result of a decrease in commodity prices, on January 17, 2020, the borrowing base was decreased to $90.0 million . The reduction in the borrowing base resulted in a borrowing base deficiency as of January 17, 2020, of $25.0 million . We have made scheduled repayments of $17.3 million and the remaining $7.8 million is due on June 5, 2020. Borrowings under the Revolving Credit Agreement bear interest at a floating rate of either LIBOR or a specified base rate plus a margin determined based upon the usage of the borrowing base. The Company is required to pay a commitment fee of 0.5% per annum on any unused portion of the borrowing base. The Company’s obligations under the Revolving Credit Agreement are secured by first priority liens on substantially all of the Company’s and the Guarantors’ assets and are unconditionally guaranteed by each of the Guarantors. As of December 31, 2019 , outstanding borrowings under the Revolving Credit Agreement were $115.0 million . The Revolving Credit Agreement also provides for issuance of letters of credit in an aggregate amount of up to $5.0 million . As of December 31, 2019, we were fully drawn against the borrowing base under our Revolving Credit Agreement, with $115.0 million of indebtedness outstanding under our Revolving Credit Agreement, classified as current liability due to uncertainty of the Company’s ability to meet debt covenants over the next twelve months. The Company capitalizes certain direct costs associated with the debt issuance under the Revolving Credit Agreement and amortizes such costs over the term of the debt instrument. The deferred financing costs related to the Revolving Credit Agreement are classified in assets. For the year ended December 31, 2019 and 2018, the Company amortized debt issuance costs associated with the Revolving Credit Agreement of $0.8 million and $2.2 million , respectively. As of December 31, 2019 , the Company had $2.6 million of unamortized deferred financing costs in other current assets. As of December 31, 2018, the Company had $0.5 million and $1.7 million of unamortized deferred financing costs in other current assets and non-current assets, respectively. The Revolving Credit Agreement matures on October 10, 2023. Borrowings under the Revolving Credit Agreement are subject to mandatory repayment in certain circumstances, including upon certain asset sales and debt incurrences or if a borrowing base deficiency occurs. The Company also may voluntarily repay borrowings from time to time and, subject to the borrowing base limitation and other customary conditions, may re-borrow amounts that are voluntarily repaid. Mandatory and voluntary repayments generally will be made without premium or penalty. Pursuant to the Fourteenth Amendment to the Revolving Credit Agreement, our next borrowing base redetermination is scheduled to occur on or about June 5, 2020. If the borrowing base is further reduced by the lenders in connection with this redetermination, we will be required to repay borrowings in excess of the borrowing base or eliminate the borrowing base deficiency by pledging additional oil and natural gas properties to secure our obligations under the Revolving Credit Agreement. Under the Revolving Credit Agreement, we have the option to affect such repayment either in full within 30 days after the redetermination or in monthly installments over a six-month period after the redetermination. The Revolving Credit Agreement contains certain customary representations and warranties and affirmative and negative covenants, including covenants relating to: maintenance of books and records; financial reporting and notification; compliance with laws; maintenance of properties and insurance; and limitations on incurrence of indebtedness, liens, fundamental changes, international operations, asset sales, certain debt payments and amendments, restrictive agreements, investments, dividends and other restricted payments and hedging. It also requires the Company to maintain a ratio of Total Debt to EBITDAX (each as defined in the Revolving Credit Agreement) (the “Leverage Ratio”) of not more than 4.00 to 1.00 and a ratio of Current Assets to Current Liabilities (each as defined in the Revolving Credit Agreement) (the “Current Ratio”) of not less than 1.00 to 1.00 as of the last day of each fiscal quarter. Compliance with the Current Ratio and Leverage Ratio covenants in future periods depends on our ability to keep wells online and consistently flowing to sales, commodity prices, our ability to control costs, and if necessary, our ability to complete sales of non-core assets or access other sources of capital to reduce indebtedness. However, our future cash flows, and consequently our EBITDAX, are subject to a number of variables, including uncertainty in forecasted production volumes and commodity prices, and we may not be able to complete sales of non-core assets or access other sources of capital on acceptable terms or at all. As of December 31, 2019, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants. Pursuant to the Twelfth Amendment, the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants as of December 31, 2019. As of March 31, 2020, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants. Pursuant to the Fourteenth Amendment (as defined in Note 11 - Long-Term Debt ), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants as of March 31, 2020. As the Company is not expecting to be able to meet future covenants without obtaining additional sources of liquidity, the outstanding amount on our Revolving Credit Agreement as of December 31, 2019 has been classified as current. See Note 2 - Liquidity and Going Concern , for additional information. The Revolving Credit Agreement also provides for events of default, including failure to pay any principal, interest or other amounts when due, failure to perform or observe covenants, cross-default on certain outstanding debt obligations, inaccuracy of representations and warranties, certain Employee Retirement Income Security Act or “ERISA” events, change of control, the security documents or guaranty ceasing to be effective, and bankruptcy or insolvency events, subject to customary cure periods. Amounts owed by the Company under the Revolving Credit Agreement could be accelerated and become immediately due and payable following the occurrence of an event of default. The Revolving Credit Agreement also provides for the Company to have and maintain Swap Agreements (as defined in the Revolving Credit Agreement) in respect of crude oil and natural gas, on not less than 75% of the projected production from proved reserves classified as “Developed Producing Reserves” attributable to the oil and natural gas properties of the Company, as reflected in the most recently delivered reserves report, for a period through at least 24 months after the end of each applicable quarter. For further information on our hedges, see Note 9 - Derivatives . Pursuant to the Twelfth Amendment, the Company obtained a waiver from the requisite lenders of the requirement to comply with certain hedging obligations set forth in the Credit Agreement until the quarter ending June 30, 2020. First Amendment and Waiver to Revolving Credit Agreement On March 1, 2019, the Company entered into a First Amendment and Waiver (the “First Amendment”) to the Revolving Credit Agreement. Among other matters, the First Amendment provided for the acceleration of the scheduled May 2019 redetermination of the borrowing base described above, which became effective on March 5, 2019 upon closing of the transactions contemplated by the 2019 Transaction Agreement (as defined below), including the satisfaction in full, as described below, of the Second Lien Term Loan under the Second Lien Credit Agreement (as defined below). The First Amendment also provides for the July 2019 scheduled redetermination of the borrowing base described above. In addition, the First Amendment provided for a limited waiver of compliance by the Company with the Leverage Ratio covenant in the Revolving Credit Agreement as of December 31, 2018. Further, in connection with the satisfaction in full of the Second Lien Term Loan and the termination of the Second Lien Credit Agreement, the First Amendment amended the maturity date provisions of the Revolving Credit Agreement to eliminate any springing maturity under the Revolving Credit Agreement tied to the maturity of the Second Lien Credit Agreement, resulting in a fixed maturity date under the Revolving Credit Agreement of October 10, 2023. The First Amendment also effected certain other ministerial and conforming amendments to the Revolving Credit Agreement related to the transactions contemplated by the 2019 Transaction Agreement and required payment by the Company to the lenders of customary fees. Second Amendment and Waiver to Revolving Credit Agreement On May 6, 2019, the Company entered into a Second Amendment and Waiver (the “Second Amendment”) to the Revolving Credit Agreement, pursuant to which the requisite lenders under the Revolving Credit Agreement waived compliance by the Company with the Current Ratio covenant as of March 31, 2019 in exchange for a customary consent fee. Additionally, the Second Amendment provided for a 25-basis point increase in the interest rate margin applicable to loans under the Revolving Credit Agreement if the Company’s Leverage Ratio is equal to or greater than 3.00 to 1.00. The Second Amendment also provides that if the Company has available cash and cash equivalents (subject to certain carveouts) in excess of $10 million for a period of at least five consecutive business days, then it must prepay the loans under the Revolving Credit Agreement in the amount of such excess. Third Amendment and Waiver to Revolving Credit Agreement On July 26, 2019, the Company entered into a Third Amendment (the “Third Amendment”) to the Revolving Credit Agreement, pursuant to which the requisite required lenders under the Revolving Credit Agreement agreed to reduce the borrowing base to $115 million from $125 million as a part of the scheduled July 1, 2019 redetermination and as a result of the Asset Sales; to give pro forma effect to the Asset Sales for the calculation of EBITDAX, Total Debt, and Current Liabilities at June 30, 2019; and, subject to the consummation of the Asset Sales completed on July 31, 2019 and the required use of the proceeds, to amend the Current Ratio to be not less than 0.85 to 1.00 on September 30, 2019, rather than the minimum Current Ratio of 1.00 to 1.00 required otherwise. Additionally, the Third Amendment provides for, among other things, an increase in the required amount hedged to 75% of projected production from proved reserves classified as “Developed Producing Reserves”. The Third Amendment also effected certain other ministerial changes to the Revolving Credit Agreement and required payment by the Company to the lenders of customary fees. Fourth Amendment and Waiver to Revolving Credit Agreement On November 5, 2019, the Company entered into a Fourth Amendment and Waiver (the “Fourth Amendment”) to the Revolving Credit Agreement, pursuant to which, among other matters, the requisite lenders under the Revolving Credit Agreement waived compliance by the Company with the Leverage Ratio covenant as of September 30, 2019 in exchange for a customary consent fee. Additionally, the Fourth Amendment modified the Leverage Ratio for future periods by modifying the manner in which EBITDAX is calculated for the periods ending December 31, 2019, March 31, 2020 and June 30, 2020 such that EBITDAX is calculated on an annualized basis for those periods, excluding quarterly periods ended prior to December 31, 2019. The Fourth Amendment also (1) requires the Company to use 100% of net cash proceeds from dispositions to repay borrowings until completion of the scheduled November 1, 2019 redetermination or during a borrowing base deficiency, (2) added completion of the scheduled November 1, 2019 redetermination as a condition precedent to future borrowings and (3) limits certain exceptions to certain of the negative covenants under the Revolving Credit Agreement during the period from the date of the Fourth Amendment to the date on which annual financial statements for the fiscal year ending December 31, 2019 are delivered. Fifth Amendment and Waiver to Revolving Credit Agreement On November 27, 2019, the Company entered into a Fifth Amendment (the “Fifth Amendment”) to the Revolving Credit Agreement dated as of October 10, 2018 which provides that the semi-annual redetermination of the borrowing base under the Revolving Credit Agreement previously scheduled to occur on or about November 1, 2019 (the “Fall 2019 Scheduled Redetermination”) will instead occur on December 16, 2019. Additionally, among other matters, the Fifth Amendment shortened the period over which the Company may repay in installments any borrowing base deficiency that may exist as a result of the Fall 2019 Scheduled Redetermination, as described below. Under the Revolving Credit Agreement, a borrowing base deficiency will occur if the amounts outstanding under the Revolving Credit Agreement exceed the borrowing base then in effect. If a borrowing base deficiency occurs, the Company is required to repay borrowings in excess of the borrowing base or eliminate the borrowing base deficiency by pledging additional oil and natural gas properties to secure its obligations under the Revolving Credit Agreement. The Company has the option to effect such repayment either (1) in full within 30 days after the redetermination or (2) in monthly installments over a period of, except as amended by the Fifth Amendment, six months , commencing 30 days after the redetermination. The Fifth Amendment provides that, for a borrowing base deficiency that exists as a result of the Fall 2019 Scheduled Redetermination only, the period over which the Company may repay the amount of the deficiency in installments will be four months , rather than six months , commencing 30 days after the redetermination. Sixth Amendment and Waiver to Revolving Credit Agreement On December 16, 2019, the Company entered into a Sixth Amendment (the “Sixth Amendment”) to the Revolving Credit Agreement which provides that the semi-annual redetermination of the borrowing base under the Revolving Credit Agreement previously scheduled to occur on or about December 16, 2019 (the “Fall 2019 Scheduled Redetermination”) will instead occur on or about January 14, 2020. Additionally, among other matters, the Sixth Amendment provides that, if any borrowing base deficiency exists as a result of the Fall 2019 Scheduled Redetermination, the date on which the initial payment is due to cure such deficiency is the first business day after such deficiency, rather than 30 days after such deficiency. Seventh Amendment to Revolving Credit Agreement On January 17, 2020 , the Company entered into a Seventh Amendment (the “ Seventh Amendment”) to the Revolving Credit Agreement. The Seventh Amendment provided for the January 14, 2020 redetermination of the borrowing base under the Revolving Credit Agreement (the “Scheduled Redetermination”). As so redetermined, the borrowing base has been set at $90 million . As a result of the Scheduled Redetermination, a borrowing base deficiency in the amount of $25 million existed under the Revolving Credit Agreement (the “Borrowing Base Deficiency”). The Seventh Amendment required repayment of the Borrowing Base Deficiency in four equal monthly installments, with the first payment of $6.25 million scheduled to occur on January 24, 2020. Eighth Amendment to Revolving Credit Agreement On January 23, 2020 , the Company entered into an Eighth Amendment (the “ Eighth Amendment”) to the Revolving Credit Agreement. The Eighth Amendment, among other things, amended the Revolving Credit Agreement to provide that the due date for the first Installment Payment was extended from January 24, 2020 to February 7, 2020 and that the due dates for the subsequent Installment Payments are February 14, 2020, March 16, 2020 and April 14, 2020. Ninth Amendment to Revolving Credit Agreement On February 6, 2020 , the Company entered into an Ninth Amendment (the “ Ninth Amendment”) to the Revolving Credit Agreement. The Ninth Amendment amended the Revolving Credit Agreement to provide that the due date for the first Installment Payment is extended from February 7, 2020 to February 18, 2020 and the due date for the second Installment Payment is extended from February 14, 2020 to February 18, 2020 . The due dates for the two subsequent Installment Payments remain March 16, 2020 and April 14, 2020 . Tenth Amendment to Revolving Credit Agreement On February 14, 2020, the Company entered into an Tenth Amendment (the “Tenth Amendment”) to the Revolving Credit Agreement. The Tenth Amendment amended the Revolving Credit Agreement to provide that the due date for the first two Installment Payments is extended from February 18, 2020 to February 28, 2020 and the due dates for the two subsequent Installment Payments remain March 16, 2020 and April 14, 2020. Eleventh Amendment to Revolving Credit Agreement On March 13, 2020, the Company entered into an Eleventh Amendment (the “Eleventh Amendment”) to the Revolving Credit Agreement. The Eleventh Amendment amended the Revolving Credit Agreement to extend the due date for the $1.50 million installment of the Borrowing Base Deficiency from March 16, 2020 to March 30, 2020. The due date for the final installment of the Borrowing Base Deficiency remains April 14, 2020. Twelfth Amendment to Revolving Credit Agreement On March 30, 2020, the Company entered into a Twelfth Amendment (the “Twelfth Amendment”) to the Revolving Credit Agreement. The Twelfth Amendment amended the Revolving Credit Agreement to, among other things extend the due date for the $1.50 million installment of the Borrowing Base Deficiency from March 30, 2020 to April 14, 2020. The due date for the final installment of the Borrowing Base Deficiency remains April 14, 2020. The lenders under the Revolving Credit Agreement also waived the requirement under the Revolving Credit Agreement that the Company comply with a leverage ratio and a current ratio, in each case, as of December 31, 2019, and granted certain other waivers, including the requirement to comply with certain hedging obligations set forth in the Revolving Credit Agreement until June 30, 2020. Additionally, the lenders consented to an extension of an additional 45 days for the Company to provide its audited annual financial statements for the fiscal year ended December 31, 2019, and waived the requirement that such financial statements be delivered without a “going concern” or like qualification or exception. Thirteenth Amendment to Revolving Credit Agreement On April 14, 2020, the Company entered into a Thirteenth Amendment (the “Thirteenth Amendment”) to the Revolving Credit Agreement. The Thirteenth Amendment amended the Revolving Credit Agreement to extend the due date for the final $7.75 million installment of the Borrowing Base Deficiency from April 14, 2020 to April 21, 2020. Fourteenth Amendment to Revolving Credit Agreement On April 21, 2020, the Company entered into a Fourteenth Amendment (the “Fourteenth Amendment”) to the Revolving Credit Agreement. The Fourteenth Amendment, among other things, amended the Revolving Credit Agreement to extend the due date for the final $7.75 million installment of the Borrowing Base Deficiency from April 21, 2020 to June 5, 2020. The lenders under the Revolving Credit Agreement also waived the requirement under the Revolving Credit Agreement that the Company comply with a leverage ratio and a current ratio, in each case, as of March 31, 2020. Additionally, the lenders consented to defer the timing of the scheduled spring redetermination of the borrowing base under the Revolving Credit Agreement from on or about May 1, 2020 to on or about June 5, 2020. Second Lien Credit Agreement On April 26, 2017, the Company entered into a second lien credit agreement (the “Second Lien Credit Agreement”), by and among the Company, certain subsidiaries of the Company, as guarantors, Wilmington Trust, National Association, as administrative agent, and the lenders party thereto, consisting of certain private funds affiliated with Värde Partners, Inc. (“Värde”). The Second Lien Credit Agreement provided for convertible loans in an aggregate initial principal amount of up to $125 million in two tranches (together, the “Second Lien Term Loan”). The first tranche consisted of an $80 million term loan, which was fully drawn and funded on April 26, 2017. The second tranche consisted of up to $45 million in delayed-draw term loans, which was fully drawn and funded in October 2017. In November 2017, the Second Lien Credit Agreement was amended to increase the amount available for borrowing under the second tranche of the Second Lien Term Loan by $25 million , and the additional $25 million was fully drawn and funded in November 2017. Prior to the satisfaction in full of the Second Lien Term Loan and the termination of the Second Lien Credit Agreement on March 5, 2019, as described below, the Second Lien Term Loan bore interest at a rate per annum of 8.25% , compounded quarterly in arrears and payable only in-kind by increasing the principal amount of the loan by the amount of the interest due on each interest payment date, and had a maturity date of April 26, 2021. Each tranche of the Second Lien Term Loan was separately convertible at any time, in full and not in part, at the option of Värde, as lead lender, as follows: (i) 70% of the principal amount, together with accrued and unpaid interest and the make-whole premium on such principal amount, would convert into a number of shares of the Company’s common stock determined by dividing the total of such principal amount, accrued and unpaid interest and make-whole premium by $5.50 (subject to certain customary adjustments, the “Conversion Price”); and (ii) 30% of the principal amount, together with accrued and unpaid interest and the make-whole premium on such principal amount, would convert on a dollar for dollar basis into a new term loan. Additionally, if the closing price of the Company’s common stock on the principal exchange on which it was traded had been at least 150% of the Conversion Price then in effect for at least 20 of the 30 immediately preceding trading days, the Company had the option to convert the Second Lien Term Loan, in whole or in part, into a number of shares of its common stock determined by dividing the principal amount to be converted, together with accrued and unpaid interest on such principal amount, by the Conversion Price. On October 10, 2018, the Company entered into a transaction agreement (the “2018 Transaction Agreement”) by and among the Company and certain private funds affiliated with Värde that were lenders under the Second Lien Credit Agreement (collectively, the “Värde Parties”), pursuant to which, among other matters, the Company issued to the Värde Parties (i) an aggregate of 5,952,763 shares of its common stock and (ii) 39,254 shares of a newly created series of preferred stock of the Company, designated as “Series D 8.25% Convertible Participating Preferred Stock”, as consideration for the reduction by approximately $56.3 million of the outstanding principal amount of the Second Lien Term Loan under the Second Lien Credit Agreement, together with accrued and unpaid interest and the make-whole amount thereon totaling approximately $11.9 million . On March 5, 2019, the Company entered into a transaction agreement (the “2019 Transaction Agreement”) by and among the Company and the Värde Parties pursuant to which, among other matters, the Company issued to the Värde Parties shares of two new series of its preferred stock and shares of its common stock, as consideration for the termination of the Second Lien Credit Agreement and the satisfaction in full, in lieu of repayment in cash, of the Second Lien Term Loan. Specifically, in exchange for satisfaction of the outstanding principal amount of the Second Lien Term Loan, accrued and unpaid interest thereon and the make-whole amount totaling approximately $133.6 million (the “Second Lien Exchange Amount”), the Company issued to the Värde Parties: • an aggregate of 55,000 shares of a newly created series of preferred stock of the Company, designated as “Series F 9.00% Participating Preferred Stock” (the “Series F Preferred Stock”), corresponding to $55 million of the Second Lien Exchange Amount based on the aggregate initial Stated Value (as defined in Note 15 - Preferred Stock ) of the shares of Series F Preferred Stock; • an aggregate of 60,000 shares of a newly created series of preferred stock of the Company, designated as “Series E 8.25% Convertible Participating Preferred Stock” (the “Series E Preferred Stock”), corresponding to $60 million of the Second Lien Exchange Amount based on the aggregate initial Stated Value (as defined in Note 15 - Preferred Stock ) of the shares of Series E Preferred Stock; and • 9,891,638 shares of common stock, corresponding to approximately $18.6 million of the Second Lien Exchange Amount, based on the closing price of the Company’s common stock on the NYSE American on March 4, 2019 of $1.88 . Subsequent to this transaction, the Company’s long-term debt consists solely of borrowings under the Revolving Credit Agreement. As a result of the satisfaction in full of the Second Lien Term Loan pursuant to the 2019 Transaction Agreement, the Company recorded a gain on extinguishment of debt of $7.1 million , which was recorded as an increase in additional paid in capital due to the Värde Parties, being existing shareholders of the Company. Interest Expense The components of interest expense are as follows (in thousands) for the year ended December 31, 2019 and 2018 : Year Ended December 31, 2019 2018 Interest on debt $ 6,488 $ 2,975 Net revenue payments on financing arrangement 888 — Paid-in-kind interest on term loans 1,590 12,213 Amortization of debt financing costs 803 3,241 Amortization of discount on term loans 1,657 14,398 Total $ 11,426 $ 32,827

LONG-TERM DEFERRED REVENUE LIAB

LONG-TERM DEFERRED REVENUE LIABILITIES AND OTHER LONG-TERM LIABILITIES	12 Months Ended
	Dec. 31, 2019
Long-term Deferred Revenue Liabilities and Other Long-term Liabilities [Abstract]
LONG-TERM DEFERRED REVENUE LIABILITIES AND OTHER LONG-TERM LIABILITIES	NOTE 12 - LONG-TERM DEFERRED REVENUE LIABILITIES AND OTHER LONG-TERM LIABILITIES December 31, 2019 2018 (in thousands) Long-term deferred revenue liabilities $ 36,920 $ 52,500 Long-term deferred proceeds, WLR agreement 13,061 — Long-term deferred proceeds, WLWI agreement 23,768 — Other — 13 Total long-term deferred revenue liabilities and other long-term liabilities $ 73,749 $ 52,513 SCM Water LLC’s Option to Exercise Purchase of Salt Water Disposal Assets In July 2018, the Company entered into a water gathering and disposal agreement and a contract operating and right of first refusal agreement with SCM Water, LLC (“SCM Water”), a subsidiary of Salt Creek Midstream, LLC (“SCM”). The water gathering agreement complements the Company’s existing water disposal infrastructure, and the Company has reserved the right to recycle its produced water. SCM Water will commence, upon receipt of regulatory approval, to build out new gathering and disposal infrastructure to all of the Company’s current and future well locations in Lea County, New Mexico, and Winkler County, Texas. All future capital expenditures to construct, maintain and operate the water gathering system will be fully funded by SCM Water and will be designed to accommodate all water produced by the Company’s operations. Pursuant to the contract operating agreement, the Company will act as contract operator of SCM Water’s salt water disposal wells. Additionally, the Company sold to SCM Water an option to acquire the Company’s existing water infrastructure, a system which is comprised of approximately 14 miles of pipeline and one SWD well, for cash consideration upon closing, with additional payments based on reaching certain milestones. On March 7, 2019, SCM Water exercised its option to purchase the Company’s existing water infrastructure. The Company determined that approximately $11.7 million of the upfront payments were attributable to the sale of the water infrastructure and right-of-way/easement, and recorded the exercise of the option as a reduction of deferred liabilities and a reduction of oil and natural gas properties. The Company is actively working on permitting additional SWD well locations. The Company anticipates that the majority of its water will eventually be disposed of through the future SCM Water system at a competitive gathering rate under the agreement. Total cash consideration for the water gathering and disposal infrastructure is $20.0 million . On July 25, 2018, the Company received an upfront non-refundable payment of $10.0 million for the option to acquire its existing water infrastructure and $5.0 million for a prefunded drilling bonus. Additionally, the Company received $2.5 million on October 1, 2018 as a bonus for the grant of an area right-of-way/easement, and the water gathering agreement provided that the Company would receive an additional $2.5 million bonus upon hitting the target of 40,000 barrels per day of produced water. The Company completed its drilling obligation and recognized the prefunded drilling bonus of $5.0 million as a reduction of deferred liabilities and a reduction of oil and natural gas properties as the deferred payment was attributable to the sale of the water infrastructure. On March 11, 2019, the Company, SCM Water, and ARM Energy Management, LLC (“ARM”), a related company to SCM Water, agreed to amend the terms of the previously negotiated water gathering and disposal agreement and entered into a new crude oil sales contract (See Note 7 - Revenue and Note 21 - Commitments and Contingencies ). Under the terms of such agreements, the Company agreed to an increase in salt water disposal rates in exchange for more favorable pricing differentials on the crude oil sales contract, modification on the minimum quantities of crude oil required under the crude oil sales contract, an upfront payment of $2.5 million and the elimination of the potential bonus for hitting a target of 40,000 barrels of produced water per day. The Company determined that the upfront $2.5 million payment was primarily attributable to the crude oil sales contract, and the Company recorded the $2.5 million payment as deferred revenues and will recognize it in income ratably as the crude oil is sold. Crude Oil Gathering Agreement and Option Agreement On May 21, 2018, the Company entered into a crude oil gathering agreement and option agreement with SCM. The crude oil gathering agreement (the “Gathering Agreement”) enables SCM to (i) design, engineer, and construct a gathering system which will provide gathering services for the Company’s crude oil under a tariff arrangement and (ii) gather the Company’s crude oil on the gathering system in certain production areas located in Winkler and Loving Counties, Texas and Lea County, New Mexico. Construction of the gathering system has commenced. The Gathering Agreement has a term of 12 years that automatically renews on a year to year basis until terminated by either party. SCM and the Company also entered into an option agreement (the “Option Agreement”) whereby the Company granted an option to SCM to provide certain midstream services related to natural gas in Winkler and Loving Counties, Texas and Lea County, New Mexico, subject to the expiration and terms of the Company’s existing gas agreement. The Option Agreement has a term commencing May 21, 2018 and terminating January 1, 2027, pursuant to its one-time option. As consideration for this option, the Company received a one-time payment of $35.0 million , which was recorded in long-term deferred revenue. Asset Disposition Accounted for as a Financing Arrangement As a result of certain repurchase rights, as discussed more fully in Note 5 - Acquisitions and Divestitures , the agreements with WLR and WLWI do not meet the criteria for a sale and are accounted for as a financing arrangement under ASC 470. The net proceeds of the transaction of $39.0 million are included in long-term deferred revenue and other long-term liabilities on the Company’s consolidated balance sheet as of December 31, 2019 . As a result of the transaction, the net revenue payments of $0.9 million for the year ended December 31, 2019 are included in interest expense on the Company’s consolidated statements of operations (see Note 5 - Acquisitions and Divestitures ).

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2019
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	NOTE 13 - RELATED PARTY TRANSACTIONS During the year ended December 31, 2019 and 2018 , the Company was engaged in the following transactions with certain related parties: As of December 31, Related Party Transactions 2019 2018 (In thousands) Directors and Officers: Värde Partners, Inc. (1) The Company acquired oil and natural gas interests from VPD, an affiliate of Värde $ — $ 10,705 Receivable balance outstanding for operating costs associated with VPD's producing wells — 1,843 ImPetro Operating, LLC, a wholly-owned subsidiary of the Company is the operator for two of VPD's producing wells and VPD reimbursed the Company for operating charges — 44 Revenue payable balance due as of December 31, 2019 for revenue associated with VPD's producing wells (157 ) — Payable to WLR for net proportionate share of production (161 ) — Payable to WLWI for net proportionate share of production (526 ) Asset disposition accounted for as a financing arrangement (36,833 ) — Total: $ (37,677 ) $ 12,592 (1) Värde was the lead lender in the Company’s Second Lien Term Loan (see Note 11 - Long-Term Debt ), is a major stockholder of the Company, and also participated in various transactions in 2018 and 2019 (which such transactions included the issuance of preferred stock to Värde Parties) (see Note 15 - Preferred Stock ). Additionally, on March 5, 2019, pursuant to the 2019 Transaction Agreement and the related payoff letter, the Company agreed to issue to the Värde Parties shares of two new series of its preferred stock and shares of its common stock, as consideration for the termination of the Second Lien Credit Agreement with the Värde Parties and the satisfaction in full, in lieu of repayment in cash, of the Second Lien Term Loan under the Second Lien Credit Agreement. See Note 11 - Long-Term Debt and Note 15 - Preferred Stock for additional information. On July 31, 2019, the Company entered into two agreements with affiliates of Värde for the sale of an overriding royalty interest and a non-operated working interest in undeveloped assets. WLR’s proportionate share of production of $0.4 million and WLWI’s proportionate share of production, net of production costs, of $0.5 million for the year ended December 31, 2019 is included in interest expense on the Company’s consolidated statements of operations. None of the properties included in the WI Agreement were producing as of December 31, 2019 . See Note 5 - Acquisitions and Divestitures for additional information. On August 16, 2019, the company entered into an agreement with an affiliate of Värde to repurchase the overriding royalty interest for the New Mexico acreage sold. See Note 5 - Acquisitions and Divestitures for additional information. On April 21, 2020, Värde Investment Partners, L.P., an affiliate of Värde Partners, Inc., became a lender under our Revolving Credit Agreement by acquiring, from a prior lender, loans and commitments under the Revolving Credit Agreement in the principal amount of approximately $25.7 million . The loans and commitments acquired by Värde Investment Partners, L.P. are subject to certain subordination provisions set forth in the Revolving Credit Agreement, as amended by the Fourteenth Amendment thereto dated April 21, 2020. For additional information regarding our Revolving Credit Agreement, as amended, see Note 11 - Long-Term Debt .

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
INCOME TAXES	NOTE 14 - INCOME TAXES The income tax provision (benefit) for the years ended December 31, 2019 and 2018 consisted of the following: December 31, 2019 2018 (in thousands) U.S. Federal: Current $ — $ — Deferred (55,366 ) (7,496 ) State and local: Current — — Deferred (4,220 ) 509 (59,586 ) (6,987 ) Change in valuation allowance 59,586 6,987 Income tax provision $ — $ — The tax effects of temporary differences that give rise to the Company’s deferred tax asset as of December 31, 2019 and 2018 consisted of the following: December 31, 2019 2018 (In thousands) Deferred tax assets: Net operating loss carry-forward $ 31,992 $ 27,568 Share based compensation 531 808 Abandonment obligation 761 541 Derivative instruments 1,526 — Deferred revenue 15,863 11,630 Interest expense 4,540 3,804 Lease Liability 386 — Property Basis 27,837 — Accrued liabilities and other 144 85 Total deferred tax asset 83,580 44,436 Valuation allowance (83,197 ) (23,611 ) Deferred tax asset, net of valuation allowance 383 20,825 Deferred tax liabilities: Derivative instruments — 249 Oil and natural gas properties and equipment — 20,576 Right of use asset 383 — Total deferred tax liability 383 20,825 Net deferred tax asset (liability) $ — $ — Reconciliation of the Company’s effective tax rate to the expected U.S. federal tax rate is: Year Ended December 31, 2019 2018 Effective federal tax rate 21 % 21 % State tax rate, net of federal benefit 1 % 2 % Change in fair value derivative liability — % 296 % Debt discount amortization — % (73 )% Change in rate — % (6 )% Other permanent differences — % (6 )% NOL true-up - §382 limitation — % (6 )% Loss from early debt extinguishment — % (59 )% Other — % (1 )% Valuation allowance (22 )% (169 )% Net — % — % As of December 31, 2019 and 2018 , the Company had net operating loss carry-forwards for federal income tax purposes of approximately $142.2 million and $127.5 million respectively, available to offset future taxable income. To the extent not utilized, federal net operating loss carry-forwards incurred prior to January, 1 2018 of $69.9 million will expire beginning in 2028 through 2037. Federal net operating loss carryforwards incurred after December 31, 2017 of $77.1 million have no expiration and can only be used to offset 80% of taxable income when utilized. A portion of the net operating loss of $142.2 million is subject to Section 382 limitations of utilization due to ownership changes of more than 50% which occurred in the prior tax years. In assessing the need for a valuation allowance on the Company’s deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon whether future book income is sufficient to reverse existing temporary differences that give rise to deferred tax assets, as well as whether future taxable income is sufficient to utilize net operating loss and credit carryforwards. Assessing the need for, or the sufficiency of, a valuation allowance requires the evaluation of all available evidence, both positive and negative. Negative evidence considered by management includes cumulative book and tax losses in recent years, no taxable income in available carryback years, and no tax planning strategies contemplated to realize the valued deferred tax assets. As of December 31, 2019, and 2018, management assessed the available positive and negative evidence to estimate if sufficient future taxable income would be generated to use the Company’s deferred tax assets and determined that it is not more-likely-than-not that the deferred tax assets would be realized in the near future. Therefore, the Company recorded a full valuation allowance of approximately $83.2 million and $23.6 million on its deferred tax assets as of December 31, 2019 and 2018, respectively.

PREFERRED STOCK

PREFERRED STOCK	12 Months Ended
	Dec. 31, 2019
Temporary Equity Disclosure [Abstract]
PREFERRED STOCK	NOTE 15 - PREFERRED STOCK Preferred Stock Issuances On January 30, 2018, the Company entered into a Securities Purchase Agreement by and among the Company and the Värde Parties, pursuant to which, on January 31, 2018, the Company issued and sold to the Värde Parties 100,000 shares of a newly created series of preferred stock of the Company, designated as “Series C 9.75% Convertible Participating Preferred Stock” for a purchase price of $1,000 per share, or an aggregate of $100.0 million . The Series C 9.75% Convertible Participating Preferred Stock was subsequently re-designated as “Series C-1 9.75% Convertible Participating Preferred Stock” in connection with the transactions contemplated by the 2018 Transaction Agreement (as defined in Note 11 - Long-Term Debt ) and as “Series C-1 9.75% Participating Preferred Stock” in connection with the transactions contemplated by the 2019 Transaction Agreement (as defined in Note 11 - Long-Term Debt ) (as re-designated, the “Series C-1 Preferred Stock”). Pursuant to the 2018 Transaction Agreement, on October 10, 2018, the Company issued and sold to the Värde Parties 25,000 shares of a newly created series of the Company’s preferred stock designated as “Series C-2 9.75% Convertible Participating Preferred Stock” for a purchase price of $1,000 per share, or an aggregate of $25.0 million . The Series C-2 9.75% Convertible Participating Preferred Stock was subsequently re-designated as “Series C-2 9.75% Participating Preferred Stock” in connection with the transactions contemplated by the 2019 Transaction Agreement (as re-designated, the “Series C-2 Preferred Stock” and, together with the Series C-1 Preferred Stock, the “Series C Preferred Stock”). Also pursuant to the 2018 Transaction Agreement, on October 10, 2018, the Company issued to the Värde Parties 39,254 shares of its Series D 8.25% Convertible Participating Preferred Stock. The Series D 8.25% Convertible Participating Preferred Stock was subsequently re-designated as “Series D 8.25% Participating Preferred Stock” in connection with the transactions contemplated by the 2019 Transaction Agreement (as re-designated, the “Series D Preferred Stock”). Pursuant to the 2019 Transaction Agreement, on March 5, 2019, the Company issued to the Värde Parties (i) 60,000 shares of its Series E Preferred Stock and (ii) 55,000 shares of its Series F Preferred Stock. Additionally, pursuant to the 2019 Transaction Agreement, on March 5, 2019, the Company issued to the Värde Parties an aggregate of 7,750,000 shares of its common stock, as consideration for the Värde Parties’ consent to the amendment of the terms of the Series C Preferred Stock and the Series D Preferred Stock to, among other things, eliminate the convertibility and voting rights of the Series C Preferred Stock and the Series D Preferred Stock. As a result of the transactions effected under the 2019 Transaction Agreement, the potential dilution of the Company’s common stockholders resulting from the conversion of convertible debt and convertible preferred stock was reduced from approximately 53.5 million shares of common stock (related to the Second Lien Term Loan, the Series C Preferred Stock and the Series D Preferred Stock) to approximately 24.0 million shares of common stock (related to the Series E Preferred Stock). Other than the Series E Preferred Stock, the Company has no convertible debt or convertible preferred stock outstanding following the closing of the transactions contemplated by the 2019 Transaction Agreement. The amendments to the terms of the Series C Preferred Stock also fixed the redemption price payable by the Company in connection with a redemption of the Series C Preferred Stock at price per share equal to (i) the Stated Value (as defined in the certificate of designation for the Series C Preferred Stock) multiplied by 125.0% plus (ii) accrued and unpaid dividends thereon and any other amounts payable by the Company in respect thereof. Prior to the amendments, the percentage specified in clause (i) above would have increased to 130.0% for a redemption of the Series C Preferred Stock effected after December 31, 2019. As of December 31, 2019 , the Company accounted for the Series C, D, E and F Preferred Stock at its initial fair value at closing of the 2019 Transaction Agreement, plus cumulative paid-in-kind dividends accrued subsequent to the closing of the transactions contemplated by the 2019 Transaction Agreement, under mezzanine equity in the consolidated balance sheet. The components of each series of preferred stock are summarized in the table below: Series C Preferred Stock Series D Preferred Stock Series E Preferred Stock Series F Preferred Stock Number of Shares Amount Number of Shares Amount Number of Shares Amount Number of Shares Amount (In thousands, except shares) Balance, January 1, 2019 125,000 $ 132,296 39,254 $ 40,729 — $ — — $ — Change in carrying value due to modification — (46,632 ) — (15,056 ) — — — — Issuance of Preferred Stock in extinguishment of debt — — — — 60,000 62,115 55,000 46,682 Paid-in-kind dividends — 13,639 — 3,409 — 4,170 — 4,179 Balance, December 31, 2019 125,000 $ 99,303 39,254 $ 29,082 60,000 $ 66,285 55,000 $ 50,861 Material Terms of the Series C Preferred Stock and Series D Preferred Stock Ranking. The Series D Preferred Stock ranks senior to the Series C Preferred Stock, and the Series C Preferred Stock ranks senior to the Common Stock with respect to dividends and rights on the liquidation, dissolution or winding up of the Company. Stated Value. Each series of the Preferred Stock has a per share stated value of $1,000 , subject to increase in connection with the payment of dividends in kind (the “Stated Value”). Dividends. Holders of shares of Preferred Stock are entitled to receive cumulative preferential dividends, payable and compounded quarterly in arrears on January 1, April 1, July 1 and October 1 of each year, commencing April 1, 2018, at an annual rate of 9.75% of the Stated Value for the Series C Preferred Stock and 8.25% of the Stated Value for the Series D Preferred stock until April 26, 2021, after which the annual dividend rate will increase to 12.00% if paid in full in cash or 15.00% if not paid in full in cash. Dividends are payable, at the Company’s option, (i) in cash, (ii) in kind by increasing the Stated Value by the amount per share of the dividend, or (iii) in a combination thereof. In addition to these preferential dividends, holders of the Preferred Stock will be entitled to participate in any dividends paid on the Common Stock on an as-converted basis. Optional Redemption . The Company has the right to redeem the Series C Preferred Stock, in whole or in part, at any time (subject to certain limitations on partial redemptions), at a price per share equal to (i) the Stated Value then in effect multiplied by (a) 120% if redeemed during 2018, (b) 125% if redeemed during 2019 or (c) 130% if redeemed after 2019, plus (ii) accrued and unpaid dividends thereon and any other amounts payable by the Company in respect thereof (the “Series C Optional Redemption Amount”). The Company has the right to redeem the Series D Preferred Stock, in whole or in part at any time (subject to certain limitations on partial redemptions), at a price per share equal to (i) the Stated Value then in effect multiplied by 117.5% , plus (ii) accrued and unpaid dividends thereon and any other amounts payable by the Company in respect thereof (the “Series D optional Redemption Amount”). Each Series of the Preferred Stock is perpetual and is not mandatorily redeemable at the option of the holders, except upon the occurrence of a Change of Control (as defined in the Certificates of Designation) as described below. Change of Control. Upon the occurrence of a Change of Control (as defined in the Certificates of Designation), each holder of shares of Preferred Stock will have the option to: • cause the Company to redeem all of such holder’s shares of Preferred Stock for cash in an amount per share equal to (i) the applicable Optional Redemption Amount plus (ii) 2.5% of the Stated Value, in each case as in effect immediately prior to the Change of Control; • convert all of such holder’s shares of Preferred Stock into the number of shares of Common Stock into which such shares are convertible immediately prior to the Change of Control; or • continue to hold such holder’s shares of Preferred Stock, subject to any adjustments to the applicable Conversion Price or the number and kind of securities or other property issuable upon conversion resulting from the Change of Control and to the Company’s or its successor’s optional redemption rights described above. Liquidation Preference . Upon any liquidation, dissolution or winding up of the Company: • holders of shares of Series D Preferred Stock will be entitled to receive, prior to any distributions on the Series C Preferred Stock, the Common Stock or other capital stock of the Company ranking junior to the Series D Preferred Stock, an amount per share of Series D Preferred Stock equal to the greater of (i) the Series D Optional Redemption Amount then in effect and (ii) the amount such holder would receive in respect of the number of shares of Common Stock into which such shares of Series D Preferred Stock is then convertible; and • holders of shares of Series C Preferred Stock will be entitled to receive, prior to any distributions on the Common Stock or other capital stock of the Company ranking junior to the Series C Preferred Stock, an amount per share of Series C Preferred Stock equal to the greater of (i) the applicable Series C Optional Redemption Amount then in effect and (ii) the amount such holder would receive in respect to the number of shares of common stock into which a share of Series C Preferred Stock is then convertible. Voting Rights . In addition to the Board designation rights described in the Certificate of Designation, holders of shares of Preferred Stock will be entitled to vote with the holders of shares of Common Stock, as a single class, on all matters submitted for a vote of holders of shares of Common Stock. When voting together with the Common Stock, each share of Preferred Stock will entitle the holder to a number of votes equal to (i) the applicable Stated Value as of the applicable record date or other determination date divided by (ii) (a) in the case of Series C-1 Preferred Stock, $4.42 (the closing price of the Common Stock on the NYSE American on January 30, 2018), and (b) in the case of Series C-2 Preferred Stock and Series D Preferred Stock, $4.41 (the closing price of the Common Stock on the NYSE American on October 9, 2018). Description of the Series E Preferred Stock and Series F Preferred Stock Ranking . The Series F Preferred Stock ranks senior to all of the other series of preferred stock of the Company, and the Series E Preferred Stock ranks senior to the Series D Preferred Stock and the Series C Preferred Stock, in each case with respect to dividends and rights on the liquidation, dissolution or winding up of the Company. Stated Value . The Series E Preferred Stock and the Series F Preferred Stock have an initial per share stated value of $1,000 , subject to increase in connection with the payment of dividends in kind as described below (the “Stated Value”). Dividends . Holders of the Series E Preferred Stock and Series F Preferred Stock are entitled to receive cumulative preferential dividends, payable and compounded quarterly in arrears on January 1, April 1, July 1 and October 1 of each year, commencing April 1, 2019, at an annual rate of 8.25% of the Stated Value for the Series E Preferred Stock and at an annual rate of 9.00% of the Stated Value for the Series F Preferred Stock. However, if, on any dividend payment date occurring after April 26, 2021, dividends due on such dividend payment date on the Series E Preferred Stock or the Series F Preferred Stock are not paid in full in cash, the annual dividend rate for the dividends due on such dividend payment date (but not for any future dividend payment date on which dividends are paid in full in cash) will be 9.25% on the Series E Preferred Stock and 10.00% on the Series F Preferred Stock. Dividends are payable, at the Company’s option, (i) in cash, (ii) in kind by increasing the Stated Value by the amount per share of the dividend or (iii) in a combination thereof. In addition to these cumulative preferential dividends, holders of the Series E Preferred Stock and Series F Preferred Stock are entitled to participate in dividends paid on the Company’s common stock. For holders of the Series E Preferred Stock, such participation will be based on the number of shares of common stock such holders would have owned if all shares of Series E Preferred Stock had been converted to common stock at the Conversion Rate (as defined below) then in effect. For holders of the Series F Preferred Stock, such participation will be based on the dividends such holders would have received if, immediately prior to the applicable record date, each outstanding share of Series F Preferred Stock had been converted into a number of shares of common stock equal to the Series F Optional Redemption Price (as defined below) divided by $7.00 , subject to proportionate adjustment in connection with stock splits and combinations, dividends paid in stock and similar events affecting the outstanding common stock (regardless of the fact that shares of the Series F Preferred Stock are not convertible into common stock). Optional Redemption . Subject to the limitations described below and certain additional limitations on partial redemptions, the Company has the right to redeem the Series E Preferred Stock, in whole or in part, at a price per share equal to (i) the Stated Value then in effect multiplied by (A) 110% if the optional redemption date occurs on or prior to March 5, 2020, (B) 105% if the optional redemption date occurs after March 5, 2020 and on or prior to March 5, 2021 and (C) 100% if the optional redemption date occurs after March 5, 2021, plus (ii) accrued and unpaid dividends thereon and any other amounts payable by the Company in respect thereof (the “Series E Optional Redemption Price”). However, for any optional redemption effected in connection with or following a Change of Control (as defined in the Series E Certificate of Designation) or any mandatory redemption in connection with a Change of Control as described below, the Series E Optional Redemption Price will be calculated under clause (C) above, regardless of when the redemption or Change of Control occurs. Except in the case of a Change of Control Redemption (as defined in the Series E Certificate of Designation), the Company may not effect an optional redemption of the Series E Preferred Stock unless: • either (i) as of the optional redemption date, there are no shares of the Series F Preferred Stock outstanding or (ii) all outstanding shares of the Series F Preferred Stock are redeemed on such optional redemption date concurrently with such optional redemption of the Series E Preferred Stock in accordance with the terms of the Series F Certificate of Designation; • the aggregate Series E Optional Redemption Price for all shares of the Series E Preferred Stock to be redeemed pursuant to such optional redemption shall not exceed the aggregate amount of net cash proceeds received by the Company from a contemporaneous issuance of common stock issued for the purpose of redeeming such shares of Series E Preferred Stock; and • if the optional redemption date occurs prior to March 5, 2022, then (i) the VWAP for at least 20 trading days during the 30 trading day period immediately preceding the notice of the optional redemption has been at least 150% of the Conversion Price (as defined below) then in effect, and (ii) such optional redemption shall be for all (but not less than all) then-outstanding shares of Series E Preferred Stock. The Series E Preferred Stock is not redeemable at the option of the holders except in connection with a Change of Control as described below and is perpetual unless converted or redeemed in accordance with the Series E Certificate of Designation. The Company has the right to redeem the Series F Preferred Stock, in whole or in part (subject to certain limitations on partial redemptions), at a price per share equal to (i) the Stated Value then in effect, multiplied by 115.0% , plus (ii) accrued and unpaid dividends thereon and any other amounts payable by the Company in respect thereof (the “Series F Optional Redemption Price”). The Series F Preferred Stock is not redeemable at the option of the holders except in connection with a Change of Control as described below and is perpetual unless converted or redeemed in accordance with the Series F Certificate of Designation. Conversion . Each share of the Series E Preferred Stock is convertible at any time at the option of the holder into the number of shares of common stock equal to (i) the applicable Series E Optional Redemption Price that would have been received by the holder upon the redemption of the applicable shares of Series E Preferred Stock as of the Conversion Date (as defined in the Series E Certificate of Designation) divided by (ii) the Conversion Price (as defined below) (the “Conversion Rate”). However, for purposes of determining the Conversion Rate, the Series E Optional Redemption Price will be calculated on the basis applicable to an optional redemption occurring after March 5, 2021 (i.e., multiplying the Stated Value by 100.0% ), regardless of the timing or circumstances of the conversion. The “Conversion Price” for the Series E Preferred Stock is $2.50 , subject to adjustment as described below. The Conversion Price will be subject to proportionate adjustment in connection with stock splits and combinations, dividends paid in stock and similar events affecting the outstanding common stock. Additionally, the Conversion Price will be adjusted, based on a broad-based weighted average formula, if the Company issues, or is deemed to issue, additional shares of common stock for consideration per share that is less than the Conversion Price then in effect, subject to certain exceptions and to the Share Cap (as defined below). To comply with the rules of the NYSE American, the Series E Certificate of Designation provides that the number of shares of common stock issuable on conversion of a share of Series E Preferred Stock may not exceed the Stated Value divided by $1.88 (which was the closing price of the common stock on the NYSE American on March 4, 2019) (the “Share Cap”), subject to proportionate adjustment in connection with stock splits and combinations, dividends paid in stock and similar events affecting the outstanding common stock (such price, as so adjusted, the “Initial Market Price”), prior to the receipt of stockholder approval of the issuance of shares of common stock in excess of the Share Cap upon conversion of shares of Series E Preferred Stock. The 2019 Transaction Agreement requires the Company to seek such shareholder approval at its next annual meeting of shareholders. Accordingly, the Company received shareholder approval at its 2019 annual meeting of shareholders held on May 20, 2019. The Company does not have the right to force the conversion of shares of the Series E Preferred Stock based on the trading price of the common stock or otherwise. The Series F Preferred Stock is not convertible into common stock. Change of Control . Upon the occurrence of a Change of Control (as defined in the Series E Certificate of Designation and the Series F Certificate of Designation), each holder of shares of the Series E Preferred Stock and Series F Preferred Stock will have the option to: (i) cause the Company to redeem all of such holder’s shares of Series E Preferred Stock or Series F Preferred Stock for cash in an amount per share equal to the applicable Optional Redemption Price; (ii) in the case of the Series E Preferred Stock, convert all of such holder’s shares of Series E Preferred Stock into common stock at the Conversion Rate; or (iii) continue to hold such holder’s shares of Series E Preferred Stock or Series F Preferred Stock, subject to the Company’s or its successor’s optional redemption rights described above and, in the case of the Series E Preferred Stock, subject to any adjustments to the Conversion Price or the number and kind of securities or other property issuable upon conversion resulting from the Change of Control. Liquidation Preference . Upon any liquidation, dissolution or winding up of the Company, holders of shares of Series F Preferred Stock will be entitled to receive, prior to any distributions on the Series E Preferred Stock, the Series D Preferred Stock, the Series C Preferred Stock, the common stock or other capital stock of the Company ranking junior to the Series F Preferred Stock, an amount per share equal to the greater of (i) the Series F Optional Redemption Price then in effect and (ii) the proceeds the holders of Series F Preferred Stock would be entitled to receive if, immediately prior to the payment of such amount, each then-outstanding share of the Series F Preferred Stock had been converted into a number of shares of common stock equal to the Series F Optional Redemption Price divided by the Participation Price (as defined in the certificate of designation for the Series F Preferred Stock), regardless of the fact that shares of the Series F Preferred Stock are not convertible into common stock. Upon any liquidation, dissolution or winding up of the Company, holders of shares of Series E Preferred Stock will be entitled to receive, after any distributions on the Series F Preferred Stock and prior to any distributions on the Series D Preferred Stock, the Series C Preferred Stock, the common stock or other capital stock of the Company ranking junior to the Series E Preferred Stock, an amount per share of Series E Preferred Stock equal to the greater of (i) the Series E Optional Redemption Price then in effect and (ii) the amount such holder would receive in respect of the number of shares of common stock into which such share of Series E Preferred Stock is then convertible. Board Designation Rights . The Series E Certificate of Designation provides that holders of the Series E Preferred Stock have the right, voting separately as a class, to designate one member of the Board for as long as the shares of common stock issuable on conversion of the outstanding shares of Series E Preferred Stock represent at least 5% of the outstanding shares of common stock (giving effect to conversion of all outstanding shares of the Series E Preferred Stock). The Series F Certificate of Designation provides that holders of the Series F Preferred Stock have the right, voting separately as a class, to designate one member of the Board for as long as the aggregate Stated Value of all outstanding shares of the Series F Preferred Stock is at least equal to $13.8 million . Voting Rights . In addition to the Board designation rights described above, holders of Series E Preferred Stock are entitled to vote with the holders of the common stock, as a single class, on all matters submitted for a vote of holders of the common stock. When voting together with the common stock, each share of Series E Preferred Stock will entitle the holder to a number of votes equal to the applicable Stated Value as of the applicable record date or other determination date divided by the greater of (i) the then-applicable Conversion Price and (ii) the then-applicable Initial Market Price. Holders of shares of Series F Preferred Stock are not entitled to vote with the holders of the common stock as a single class on any matter. Negative Covenants . The Series E Certificate of Designation and Series F Certificate of Designation contain customary negative covenants. Transfer Restrictions . Shares of Series E Preferred Stock and Series F Preferred Stock and shares of common stock issued on conversion of shares of Series E Preferred Stock may not be transferred by the holder of such shares, other than to an affiliate of such holder, prior to September 5, 2019. After September 5, 2019, such shares will be freely transferable, subject to applicable securities laws.

STOCKHOLDERS' EQUITY

STOCKHOLDERS' EQUITY	12 Months Ended
	Dec. 31, 2019
Equity [Abstract]
STOCKHOLDERS' EQUITY	NOTE 16 - STOCKHOLDERS' EQUITY Issuance of Common Stock On March 5, 2019 , pursuant to the 2019 Transaction Agreement, as (i) partial consideration for the satisfaction in full of the Second Lien Term Loan as discussed in Note 11 - Long-Term Debt and (ii) consideration for the amendment of the terms of the Series C Preferred Stock and the Series D Preferred Stock as discussed in Note 15 - Preferred Stock , the Company issued an aggregate of 17,641,638 shares of the Company’s common stock, par value 0.0001 per share. Warrants The following table provides a summary of warrant activity as of December 31, 2019 and 2018 : Warrants Weighted- Average Exercise Price Outstanding at Outstanding at January 1, 2018 11,882,800 $ 3.34 Exercised (3,975,957 ) 2.21 Forfeited or expired (2,889,514 ) 3.35 Outstanding at Outstanding at January 1, 2019 5,017,329 3.83 Forfeited or expired (2,263,267 ) 2.81 Outstanding at December 31, 2019 2,754,062 $ 4.67 The outstanding warrants at December 31, 2019 will expire as follows: Year Warrants 2020 174,642 2021 — 2022 2,579,420 2,754,062 Common Stock Repurchase In March 2018, the Company entered into a share-repurchase agreement (the “SRA”) with an investment brokerage company (“Broker”) to repurchase $1.0 million of the Company’s common stock as part of the Share Repurchase Plan (the “Plan”). Under the terms of the SRA, the Company paid cash directly to the Broker and received delivery of shares of the Company’s common stock. All of the shares acquired by the Company under the SRA are recorded as treasury stock. For the nine months ended December 31, 2018 the Company purchased 253,598 shares of the Company’s common stock for approximately $1.0 million .

SHARE BASED AND OTHER COMPENSAT

SHARE BASED AND OTHER COMPENSATION	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
SHARE BASED AND OTHER COMPENSATION	NOTE 17 - SHARE BASED AND OTHER COMPENSATION On April 20, 2016, the Company’s Board and the Compensation Committee of the Board approved the Company’s 2016 Omnibus Incentive Plan (the “2016 Plan”). As of December 31, 2019 , 5.4 million shares of the 18 million shares of the Company’s common stock authorized for awards under the 2016 Plan remained available for future issuances. The Company generally issues new shares to satisfy awards under employee stock based payment plans. The Company no longer grants any awards under the Lilis 2012 Omnibus Incentive Plan (the “2012 Plan”). The following table sets forth the stock based compensation expense recognized during the years ended December 31, 2019 and 2018 and the unamortized portion of the stock based compensation expense and weighted average amortization period of the remaining vesting period for the year ended December 31, 2019 and 2018 , the Company’s share-based compensation consisted of the following (dollars in thousands) : Year Ended December 31, 2019 2018 Stock Options Restricted Stock Total Stock Options Restricted Stock Total Share based compensation expensed $ 317 $ 6,189 $ 6,506 $ 2,158 $ 6,842 $ 9,000 Unrecognized share-based compensation costs $ 100 $ 1,228 $ 1,328 $ 487 $ 3,501 $ 3,988 Weighted average amortization period remaining (in years) 1.55 1.05 0.03 0.50 Restricted Stock Employees may be granted restricted stock in the form of restricted stock awards or restricted stock units. Restricted stock is subject to forfeiture restrictions and cannot be sold, transferred, or disposed of during the restriction period. The holders of restricted stock awards have the same rights as a stockholder of the Company with respect to such shares, including the right to vote and receive dividends or other distributions paid with respect to the shares. Restricted stock vests over service periods ranging from the date of grant generally up to two or three years. The company expenses the grant date fair value of restricted shares, determined to be share price on the date of grant, ratably over the service period. A summary of restricted stock grant activity pursuant to the 2012 Plan and the 2016 Plan for the year ended December 31, 2019 , is presented below: Number of Shares Weighted Average Grant Date Price Outstanding at January 1, 2018 2,475,266 $ 4.22 Granted 1,194,944 $ 4.59 Vested and issued (1,436,146 ) $ 2.38 Forfeited or canceled (1) (1,280,480 ) $ 4.44 Outstanding at December 31, 2018 953,584 $ 4.85 Granted 3,684,372 $ 1.46 Vested and issued (2,341,269 ) $ 2.39 Forfeited or canceled (1) (894,512 ) $ 2.94 Outstanding at December 31, 2019 1,402,175 $ 1.26 (1) Forfeitures are accounted for as and when incurred. Stock Options Employees may be granted incentive stock options to purchase shares of the Company’s common stock with an exercise price equal to, or greater than, the fair market value of the Company’s common stock on the date of grant. These stock options generally vest over two years from the date of grant and terminate at the earlier of the date of exercise or ten years from the date of grant. During the year ended December 31, 2018 , the Company received cash proceeds of approximately $2.6 million from the exercise of vested stock options. There were no stock options exercised during the year ended December 31, 2019. A summary of stock option activity pursuant to the 2016 Plan for the years ended December 31, 2019 and 2018, is presented below: Number of Options Weighted Average Exercise Price Number of Options Vested/ Exercisable Weighted Average Remaining Contractual Life (Years) Outstanding at January 1, 2018 7,305,000 $ 3.74 3,534,484 8.9 Granted 352,500 $ 4.07 Exercised (1,024,877 ) $ 2.67 Forfeited or canceled (1,601,045 ) $ 4.20 Outstanding at December 31, 2018 5,031,578 $ 3.81 5,035,317 7.9 Granted 135,000 $ 2.17 Exercised — $ — Forfeited or canceled (1) (1,578,228 ) $ 3.14 Outstanding at December 31, 2019 3,588,350 $ 4.05 4,125,842 7.2 (1) Forfeitures are accounted for as and when incurred. During the year ended December 31, 2019 , options to purchase 135,000 shares of the Company’s common stock were granted under the 2016 Plan. The weighted average fair value of these options was $1.47 utilizing the weighted average expected term of 10 years , expected volatility of 30% , no expected dividends, and risk-free interest rate of 2.67% . The Company estimates expected volatility based on an analysis of its historical stock prices since the initial public offering date in 2007. The Company estimates the expected term of its option awards based on the vesting period. The Company uses this method to provide a reasonable basis for estimating its expected term due to the lack of sufficient historical employee exercise data on stock option awards.

INCOME (LOSS) PER COMMON SHARE

INCOME (LOSS) PER COMMON SHARE	12 Months Ended
	Dec. 31, 2019
Earnings Per Share [Abstract]
INCOME (LOSS) PER COMMON SHARE	NOTE 18 - INCOME (LOSS) PER COMMON SHARE The following table shows the computation of basic and diluted net loss per share for the years ended December 31, 2019 and 2018 (in thousands): 2019 2018 Net loss $ (272,121 ) $ (4,143 ) Dividends on preferred stock (25,397 ) (10,687 ) Unallocated net loss $ (297,518 ) $ (14,830 ) Numerator for basic loss per share: Net loss attributable to common stockholders $ (297,518 ) $ (14,830 ) Denominator for basic loss per share: Basic weighted average common shares outstanding 87,912,362 62,854,214 Net loss per share: Basic attributable to common stockholders $ (3.38 ) $ (0.24 ) Numerator for diluted loss per share: Net loss attributable to common stockholders $ (297,518 ) $ (14,830 ) Add: interest expense on convertible Second Lien Term Loan — 13,429 Less: gain on fair value change of embedded derivatives associated with Second Lien Term Loan — (35,471 ) Net loss attributable to common stockholders $ (297,518 ) $ (36,872 ) Denominator for diluted net loss per share: Basic weighted average common shares outstanding 87,912,362 62,854,214 Dilution effect of if-converted Second Lien Term Loan — 15,597,127 Diluted weighted average common shares outstanding 87,912,362 78,451,341 Net loss per share - diluted: Common shares (diluted) $ (3.38 ) $ (0.47 ) The Company excluded the following shares from the diluted loss per share calculations above because they were anti-dilutive at December 31, 2019 and 2018 : December 31, 2019 2018 Stock Options 3,588,350 5,031,578 Series C Preferred Stock — 26,295,616 Series D Preferred Stock — 8,543,670 Stock Purchase Warrants 2,754,062 5,017,329 Series E Preferred Stock 25,667,871 — Conversion of term loans — — 32,010,283 44,888,193

SUPPLEMENTAL NON-CASH TRANSACTI

SUPPLEMENTAL NON-CASH TRANSACTIONS	12 Months Ended
	Dec. 31, 2019
Supplemental Cash Flow Elements [Abstract]
SUPPLEMENTAL NON-CASH TRANSACTIONS	NOTE 19 - SUPPLEMENTAL NON-CASH TRANSACTIONS The following table presents the supplemental disclosure of cash flow information for the years ended December 31, 2019 and 2018 : Year Ended December 31, 2019 2018 (in thousands) Non-cash investing and financing activities excluded from the statement of cash flows: Issued shares of common stock and preferred stock upon extinguishment of debt and modification of Series C Preferred Stock and Series D Preferred Stock $ 141,787 $ 64,504 Common stock issued for acquisition of oil and natural gas properties — 24,778 Cashless exercise of warrants — 359 Deferred revenue realized upon purchase option exercise 16,700 — Right of use assets obtained in exchange for operating lease obligations 7,500 — Change in capital expenditures for drilling costs in accrued liabilities 2,010 7,850 Accrued cumulative paid in kind dividends on preferred stock 25,397 10,687 Change in asset retirement obligations 546 1,495 Reduction of fair value for converted embedded derivatives — 12,406 Transfer of warrant derivative instruments to equity — 223

SEGMENT INFORMATION

SEGMENT INFORMATION	12 Months Ended
	Dec. 31, 2019
Segment Reporting [Abstract]
SEGMENT INFORMATION	NOTE 20 - SEGMENT INFORMATION Operating segments are defined as components of an entity that engage in activities from which it may earn revenues and incur expenses for which separate operational financial information is available and are regularly evaluated by the chief operating decision maker for the purposes of allocating resources and assessing performance. The Company currently has only one reportable operating segment, which is oil and natural gas development, exploration and production, for which the Company has a single management team that allocates capital resources to maximize profitability and measures financial performance as a single entity.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	NOTE 21 - COMMITMENTS AND CONTINGENCIES ARM Sales Agreement On August 2, 2018, the Company executed a five -year agreement with SCM Crude, LLC, an affiliate of SCM, to secure firm takeaway pipeline capacity and pricing on a long-haul pipeline to the Gulf Coast region commencing July 1, 2019. On March 11, 2019, the agreement was replaced with a five -year agreement between the Company and ARM, a related company to SCM. The new agreement accelerated the start date to March 2019 and guarantees firm takeaway capacity on a long-haul pipeline to Corpus Christi, Texas, once completed, at a specified price. Under the terms of the new contract, the Company received pricing differentials on the crude oil sales contract subject to minimum quantities of crude oil to be delivered as follows: Date Quantity (Barrels per Day) March 2019 - June 2019 5,000 July 2019 - December 2019 4,000 January 2020 - June 2020 5,000 July 2020 - June 2021 6,000 July 2021 - December 2024 (1) 7,500 (1) Extending to the later of December 2024 or 5 years from the EPIC Crude Oil pipeline in-service date (February 2025). Further, ARM has agreed to purchase crude from the Company based upon Magellan East Houston pricing with a fixed “differential basis”. As of December 31, 2019 , the agreement no longer meets the criteria for the “normal purchase normal sales” exception under ASC 815, “Derivatives and Hedging”, due to the Company not meeting the minimum quantities deliverable under the contract and the net settlement criteria being met. See Note 9 - Derivatives for information regarding the recognition of the net settlement mechanism as an embedded derivative over the remainder of the contract. Environmental and Governmental Regulation As of December 31, 2019 , there were no known environmental or regulatory matters which are reasonably expected to result in a material liability to the Company. Many aspects of the oil and natural gas industry are extensively regulated by federal, state, and local governments and regulatory agencies in all areas in which the Company has operations. Regulations govern such things as drilling permits, environmental protection and air emissions/pollution control, spacing of wells, the unitization and pooling of properties, reports concerning operations, land use, taxation, and various other matters. Oil and natural gas industry legislation and administrative regulations are periodically changed for a variety of political, economic, and other reasons. As of December 31, 2019 , the Company had not been fined or cited for any violations of governmental regulations that would have a material adverse effect on the financial condition of the Company. Legal Proceedings The Company may from time to time be involved in various legal actions arising in the ordinary course of business. In the opinion of management, the Company’s liability, if any, in these pending actions would not have a material adverse effect on the financial position of the Company. The Company’s general and administrative expenses would include amounts incurred to resolve claims made against the Company. The Company believes there is no litigation pending that could have, individually or in the aggregate, a material adverse effect on its results of operations or financial condition. Liens As of the most recent date available, statutory mechanic's and materialman’s liens which remain unpaid in the amount of $8.7 million have been filed against the related assets.

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	12 Months Ended
	Dec. 31, 2019
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	NOTE 22 - SUBSEQUENT EVENTS COVID-19 On January 30, 2020, the World Health Organization (“WHO”) announced a global health emergency due to the COVID-19 outbreak, which originated in Wuhan, China, 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 outbreak 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 has caused an increased supply and has led to a substantial decrease in oil prices and an increasingly volatile market. The oil price war ended with a deal to cut global petroleum output but did not go far enough to offset the impact of COVID-19 on demand. There has been an increase in supply which has pushed prices down further since March. If the depressed pricing continues for an extended period it will lead to i) additional reductions in the borrowing base under our credit facility which would require us to make additional borrowing base deficiency payments, ii) reductions in reserves, and iii) additional impairment of proved and unproved oil and gas properties. We also expect disclosures of supplemental oil and gas information to be impacted by price declines. In response to recent commodity prices and our efforts to strengthen our capital through reducing operating costs, during April 2020 the Company elected to shut-in 12 wells which were identified as uneconomic as a result of the continued decline in commodity prices in 2020 and 19 additional wells have been identified for short term shut-in through May and June. The 19 wells identified for short term shut-in are naturally flowing wells and could be turned back to sales quickly as market conditions dictate. The Company has also implemented an employee furlough program to further reduce general and administrative costs. The furloughed employees will not receive compensation from the Company during the furlough period; however, subject to local regulations, these employees will be eligible for unemployment benefits. The furlough period is uncertain at this time and will be reassessed as business conditions dictate. The full impact of the COVID-19 outbreak and the decline in oil prices continues to evolve as of the date of this Annual 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 on its financial condition, liquidity, operations, suppliers, industry, and workforce. Given the daily evolution of the COVID-19 outbreak and the global responses to curb its spread, the Company is not able to estimate the effects of the COVID-19 outbreak on its results of operations, financial condition, or liquidity for fiscal year 2020. These matters could have a continued material adverse impact on economic and market conditions and trigger a period of global economic slowdown, which may impair the Company’s asset values, including reserve estimates. Further, consumer demand has decreased since the spread of the outbreak and new travel restrictions placed by governments in an effort to curtail the spread of the coronavirus. Although the Company cannot estimate the length or gravity of the impacts of these events at this time, if the pandemic and/or decreased oil prices continue, they will have a material adverse effect on the Company’s results of future operations, financial position, and liquidity in fiscal year 2020. Coronavirus Aid, Relief, and Economic Security Act On March 27, 2020, President Trump signed into law the Coronavirus Aid, Relief, and Economic Security (the “CARES Act”). The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer side social security payments, net operating loss carryback periods, alternative minimum tax credit refunds, modifications to the net interest deduction limitations, increased limitations on qualified charitable contributions, and technical corrections to tax depreciation methods for qualified improvement property. It also appropriated funds for the SBA Paycheck Protection Program loans that are forgivable in certain situations to promote continued employment, as well as Economic Injury Disaster Loans to provide liquidity to small businesses harmed by COVID-19. There is no assurance we are eligible for these funds or will be able to obtain them. We continue to examine the impact that the CARES Act may have on our business. Currently, we are unable to determine the impact that the CARES Act will have on our financial condition, results of operations, or liquidity.

SUPPLEMENTARY INFORMATION ON OI

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT	12 Months Ended
	Dec. 31, 2019
Supplemental Oil And Gas Reserve Information [Abstract]
SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT	The Company’s oil and natural gas reserves are attributable solely to properties within the United States, which constitutes one cost center. Costs Incurred for Oil and Natural Gas Producing Activities The following table sets forth the costs incurred in the Company ’ s oil and natural gas acquisition, exploration and development activities and includes costs whether capitalized or expensed as well as revisions and additions to the estimated future asset retirement obligations : December 31, 2019 2018 (In thousands) Acquisition costs: Unproved properties $ 1,644 $ 93,926 Proved properties — 22,356 Exploration costs 40,284 89,351 Development costs 51,198 78,103 Total $ 93,126 $ 283,736 Results of Operations for Oil and Natural Gas Producing Activities The following table sets forth the results of operations for oil and natural gas producing activities: December 31, 2019 2018 (In thousands) Revenues $ 66,063 $ 70,216 Production costs (16,127 ) (13,843 ) Production taxes (3,302 ) (3,709 ) Accretion of asset retirement obligation (433 ) (85 ) Depletion, depreciation and amortization (33,071 ) (25,159 ) Full cost ceiling impairment (228,324 ) — Total $ (215,194 ) $ 27,420 Reserves Quantity Information The following table provides a roll forward of the total proved reserves for the years ended December 31, 2019 and 2018, as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year: Crude Oil (Bbls) Natural Gas (Mcf) NGLs (Bbls) January 1, 2018 7,171,339 16,059,926 1,604,570 Extensions and discoveries 15,881,727 38,957,588 4,565,994 Purchase of reserves 1,883,047 8,897,115 682,964 Revisions of previous estimates (2,641,353 ) 17,690,723 1,769,448 Production (1,089,724 ) (2,855,739 ) (246,425 ) December 31, 2018 21,205,036 78,749,613 8,376,551 Extensions and discoveries 856,838 2,477,061 190,203 Revisions of previous estimates (15,596,115 ) (48,718,235 ) (6,067,700 ) Production (1,130,855 ) (3,063,927 ) (220,832 ) December 31, 2019 5,334,904 29,444,512 2,278,222 Proved Developed Reserves, included above: Balance, January 1, 2018 2,531,397 6,594,446 644,102 Balance, December 31, 2018 6,278,036 27,046,195 2,653,908 Balance, December 31, 2019 5,334,904 29,444,512 2,278,222 Proved Undeveloped Reserves, included above: Balance, January 1, 2018 4,639,942 9,465,480 960,468 Balance, December 31, 2018 14,927,000 51,703,418 5,722,643 Balance, December 31, 2019 — — — Extensions and discoveries of 1.5 MBOE during the year ended December 31, 2019, resulted from the drilling of exploratory wells during the year that are included in proved reserves and productive wells as of December 31, 2019. Revisions of previous reserves estimates decreased 2019 proved reserves by 29.8 MBOE. Reserves decreased by approximately 8.3 MBOE as a result of lower SEC pricing and costs for 2019 compared to 2018, as well as operational factors. The remaining revisions of 21.5 MBOE were the result of reclassification of all PUD reserves to unproved because of the uncertainty regarding the availability of capital to us for development these reserves as of December 31, 2019. Standardized Measure of Discounted Future Net Cash Flows The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the properties. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties and consideration of expected future economic and operating conditions. The estimates of future cash flows and future production and development costs as of December 31, 2019 and 2018 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions which are held constant throughout the life of the properties. All wellhead prices are held flat over the forecast period for all reserves categories. The estimated future net cash flows are then discounted at a rate of 10%. The standardized measure of discounted future net cash flows relating to proved oil, natural gas and NGL reserves is as follows: December 31, 2019 2018 (In thousands) Future cash inflows $ 358,127 $ 1,500,263 Future production costs (176,498 ) (414,117 ) Future development costs (7,284 ) (346,225 ) Future income tax expense — (62,842 ) Future net cash flows 174,345 677,079 10% discount to reflect timing of cash flows (54,171 ) (384,345 ) Total $ 120,174 $ 292,734 In the foregoing determination of future cash inflows, sales prices used for oil, natural gas and NGLs for December 31, 2019 and 2018, were estimated using the average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-month price for each month. Prices were adjusted by lease for quality, transportation fees and regional price differentials. Future costs of developing and producing the proved natural gas and oil reserves reported at the end of each year shown were based on costs determined at each such year-end, assuming the continuation of existing economic conditions. At December 31, 2019, the tax basis of our oil and gas properties exceeded the pre-tax cash inflows; therefore, in the preparation of the Standardized Measure no future taxable income is expected to be generated from our oil and natural gas properties, primarily due to the reclassification of all PUD reserves to unproved because of the uncertainty regarding the availability of capital for developing those reserves. The Company cautions that the disclosures shown are based on estimates of proved reserves quantities and future production schedules which are inherently imprecise and subject to revision and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations and no value may be assigned to probable or possible reserves. Changes in the standardized measure of discounted future net cash flows relating to proved oil, natural gas and NGL reserves are as follows: Year Ended December 31, 2019 2018 (In thousands) Balance at beginning of period $ 292,734 $ 68,812 Net changes in prices and production costs (1) (275,539 ) 24,261 Sales of oil and natural gas produced during the year, net (42,442 ) (49,271 ) Changes in estimated future development costs (2) 272,579 (39,938 ) Net change due to extensions and discoveries 18,044 161,785 Net change due to purchases of minerals in place — 55,278 Previously estimated development costs incurred during the year 36,298 68,349 Net changes due to revision of previous quantity estimates (3) (255,125 ) 28,350 Accretion of discount 29,273 6,881 Other - unspecified (4) 9,327 3,252 Net change in income taxes 35,025 (35,025 ) Balance at end of period $ 120,174 $ 292,734 (1) Net changes from prices and production costs were primarily the result of a 19% decrease in oil and natural gas prices and 45% increase in production costs from December 31, 2018 to December 31, 2019. (2) Future development costs decreased $272.6 million from December 31, 2018 to December 31, 2019. Our December 31, 2019 proved reserves report reflects the reclassification of all PUD reserves to unproved because of the uncertainty regarding the availability of capital for developing those reserves. Our December 31, 2018 proved reserves report included future development costs of $329.5 million associated with PUD reserves not included in our December 31, 2019 proved reserves report. (3) Negative revisions for 2019 are primarily the result of the reclassification of proved undeveloped reserves to unproved as reflected in our December 31, 2019 reserves report. (4) Other changes are the result of significant changes to our proved reserves from December 31, 2018 to December 31, 2019 and include significant estimates of the effects of changes in the economic lives of producing wells and reclassification of proved undeveloped reserves to unproved as reflected in our December 31, 2019 reserves report.

BASIS OF PRESENTATION AND SUM_2

BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Principles of Consolidation and Presentation	Principles of Consolidation and Presentation The accompanying consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, Brushy Resources, Inc., ImPetro Operating, LLC, ImPetro Resources, LLC, Lilis Operating Company, LLC, and Hurricane Resources LLC. All significant intercompany accounts and transactions have been eliminated in consolidation.
Use of Estimates	Use of Estimates The accompanying consolidated financial statements are prepared in conformity with GAAP which requires the Company to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities; disclosure of contingent assets and liabilities at the date of the financial statements; the reported amounts of revenues and expenses during the reporting period; and the quantities and values of proved oil, natural gas and natural gas liquid (“NGL”) reserves used in calculating depletion and assessing impairment of its oil and natural gas properties. The most significant estimates pertain to the evaluation of unproved properties for impairment, proved oil and natural gas reserves and related cash flow estimates used in the depletion and impairment of oil and natural gas properties; the timing and amount of transfers of our unevaluated properties into our amortizable full cost pool; the fair value of embedded derivatives and commodity derivative contracts, accrued oil and natural gas revenues and expenses, valuation of options and warrants, and common stock; and the allocation of general and administrative expenses. Actual results could differ significantly from these estimates.
Reclassification	Reclassifications Certain reclassifications have been made to the prior year comparative financial statements to conform to the 2019 presentation. These reclassifications have no effect on the Company’s previously reported results of operations, stockholders’ equity or cash flows
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and cash equivalents include highly liquid instruments with an original maturity of three months or less are stated at cost, which approximates fair value.
Accounts Receivable	Accounts Receivable The Company has accounts receivable from joint interest owners of properties operated by the Company. The Company typically has the right to withhold future revenue disbursements to recover any non-payment of related joint interest billings. Management routinely assesses accounts receivable amounts to determine their collectability and accrues an allowance for uncollectible receivables when, based on the judgment of management, it is probable that a receivable will not be collected. The Company records actual and estimated oil and natural gas revenue receivable from third parties at its net revenue interest. In addition, the Company has receivables derived from sales of certain oil and natural gas production which are collateral under the Company’s credit agreements.
Fair Value of Financial Instruments	Fair Value of Financial Instruments As of December 31, 2019 , and 2018 , the carrying value of cash and cash equivalents, accounts receivable, accounts payable, accrued liabilities, revenue payable and advances from joint interest partners approximates fair value due to the short-term nature of such items. The carrying value of the Company’s secured debt is carried at cost which approximates the fair value of the debt as the related interest rates approximates interest rates currently available to the Company.
Oil and Natural Gas Properties	Oil and Natural Gas Properties The Company uses the full cost method of accounting for oil and natural gas operations. Under this method, costs related to the exploration, non-production related development and acquisition of oil and natural gas reserves are capitalized. Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling, developing and completing productive wells, and any other costs directly related to acquisition and exploration activities. Proceeds from property sales are generally applied as a credit against capitalized exploration and development costs, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of proved reserves. Depletion of exploration and development costs and depreciation of wells and tangible production assets is computed using the units-of-production method based upon estimated proved oil and natural gas reserves. Costs included in the depletion base to be amortized include (a) all proved capitalized costs including capitalized asset retirement costs net of estimated salvage values, less accumulated depletion, and (b) estimated future development cost to be incurred in developing proved reserves, that are not otherwise included in capitalized costs. Under the full cost method of accounting, capitalized oil and natural gas property costs less accumulated depletion (net of deferred income taxes) may not exceed an amount equal to the sum of the present value, discounted at 10% , of estimated future net revenues from proved oil and natural gas reserves and the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are not subject to amortization. Should capitalized costs exceed this ceiling, an impairment expense is recognized. The present value of estimated future net cash flows was computed by applying a flat oil price to forecast revenues from estimated future production of proved oil and natural gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves (assuming the continuation of existing economic conditions), less any applicable future taxes. For the year ended December 31, 2019 , the ceiling value of the Company’s reserves was calculated based upon SEC pricing of $55.69 per barrel for oil and $2.58 per MMBtu for natural gas. For the year ended December 31, 2018 , the ceiling value of the Company’s reserves was calculated based upon SEC pricing of $65.56 per barrel for oil and $3.10 per MMBtu for natural gas. Full-cost ceiling impairments totaling $228.3 million were recorded for the year ended December 31, 2019 and resulted primarily from decreased commodity prices and reduction in expected PUDs used in preparation of estimated future net revenues from proved oil and natural gas reserves as compared to the commodity prices used for the year ended December 31, 2018 , when no such impairments were recognized. The costs of unproved oil and natural gas properties are excluded from amortization until the properties are evaluated. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved oil and natural gas reserves are established or if impairment is determined. Unproved oil and natural gas properties are assessed periodically, at least annually, to determine whether impairment had occurred. The assessment considers the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, the economic viability of development if proved reserves were assigned and other current market conditions. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and were then subject to amortization.
Wells In Progress	Wells in Progress Wells in progress connotes wells that are currently in the process of being drilled or completed or otherwise under evaluation as to their potential to produce oil and natural gas reserves in commercial quantities. Such wells continue to be classified as wells in progress and withheld from the depletion calculation and the ceiling test until such time as either proved reserves can be assigned, or the wells are otherwise abandoned. Upon either the assignment of proved reserves or abandonment, the costs for these wells are then transferred to the full cost pool and become subject to both depletion and the ceiling test calculations in accordance with full cost accounting under Rule 4-10 of Regulation S-X of the Securities Exchange Act of 1934, as amended.
Capitalized Interest	Capitalized Interest For significant oil and natural gas investments in unproved properties, and significant exploration and development projects that have not commenced production, interest is capitalized as part of the historical cost of developing and constructing assets. Capitalized interest is determined by multiplying the Company’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depreciation or impairment.
Other Property and Equipment	Other Property and Equipment Property and equipment include vehicles, office equipment and furniture which are stated at cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets. The estimated useful lives of property and equipment range from 4 to 20 years.
Asset Retirement Obligations	Asset Retirement Obligation s The Company incurs retirement obligations for certain assets at the time they are placed in service. The fair values of these obligations are recorded as liabilities on a discounted basis. The costs associated with these liabilities are capitalized as part of the related assets and depreciated. Over time, the liabilities are accreted for the change in their present value. For purposes of depletion, the Company includes estimated dismantlement and abandonment cost, net of salvage values, associated with future development activities that have not yet been capitalized as asset retirement obligations. Asset retirement obligations incurred are classified as Level 3 (unobservable inputs) fair value measurements.
Revenue Recognition	Revenue Recognition Revenue is recognized when control passes to the purchaser which generally occurs when production is transferred to the purchaser. The Company measures revenue as the amount of consideration it expects to receive in exchange for the commodities transferred. All of the Company’s revenues from contracts with customers represent products transferred at a point in time as control is transferred to the customer. The Company records revenue based on consideration specified in its contracts with its customers. The amounts collected on behalf of third parties are recorded in revenue payable. The Company recognizes revenue in the amount that reflects the consideration it expects to receive in exchange for transferring control of those goods to the customer. The contract consideration in the Company’s variable price contracts is typically allocated to specific performance obligations in the contract according to the price stated in the contract. Payment is generally received one or two months after the sale has occurred.
Stock based Compensation	Stock based Compensation The Company applies a fair value method of accounting for stock based compensation, which requires recognition in the financial statements of the cost of services received in exchange for equity awards. For equity awards, compensation expense is based on the fair value on the grant date or modification date and is recognized in the Company’s financial statements over the vesting period. The Company utilizes the Black-Scholes Merton option-pricing model to measure the fair value of stock options based on several criteria, including but not limited to, the valuation model used and associated input factors, such as expected term of the award, stock price volatility, risk free interest rate, dividend rate. These inputs are subjective and are determined using management’s judgment. If differences arise between the assumptions used in determining stock based compensation expense and the actual factors, which become known over time, the Company may change the input factors used in determining future stock based compensation expense. The fair value of restricted stock awards is identified as the closing stock price on the day the award was granted. The Company recognizes forfeitures as and when the stock awards are forfeited. The Company accounts for warrant grants to nonemployees whereby the fair values of such warrants are determined using the option pricing model at the earlier of the date at which the nonemployee’s performance is complete or a performance commitment is reached.
Income Taxes	Income Taxes The Company uses the asset and liability method in accounting for income taxes. Deferred tax assets and liabilities are recognized for temporary differences between financial statement carrying amounts and the tax bases of assets and liabilities and are measured using the tax rates expected to be in effect when the differences reverse. Deferred tax assets are also recognized for operating loss and tax credit carry forwards. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the results of operations in the period that includes the enactment date. A valuation allowance is used to reduce deferred tax assets when uncertainty exists regarding their realization. The Company recognizes its tax benefits only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely to be realized upon settlement. A liability for “unrecognized tax benefits” is recorded for any tax benefits claimed that do not meet these recognition and measurement standards. As of December 31, 2019 and 2018 , the Company has determined that no liability is required to be recognized. The Company’s policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense.
Concentration of Credit Risk	Concentration of Credit Risk The Company operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payment for costs associated with the property and seeks reimbursement from the other joint interest owners in the property for their portion of those costs. When warranted, prepayments are required from joint interest owners for drilling and completion projects. Joint interest owners consist primarily of independent oil and natural gas producers whose ability to reimburse the Company could be negatively impacted by adverse market conditions. The purchasers of the Company’s oil, natural gas and NGL production consist primarily of independent marketers, major oil and natural gas companies, refiners and natural gas pipeline companies. Credit evaluations are performed on the Company’s purchasers of its production and their financial condition is monitored on an ongoing basis. Based on those evaluations and monitoring, the Company may obtain letters of credit or parental guarantees from some purchasers. All of the Company’s oil and natural gas derivative transactions are carried out in the over-the-counter market and are not typically subject to margin-deposit requirements. The use of derivative transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. The Company monitors the credit ratings of its derivative counterparties on an ongoing basis. If a counterparty were to default on its obligations to the Company under the derivative contracts or seek bankruptcy protection, it could have a material adverse effect on its ability to fund planned activities and could result in a larger percentage of our future production being subject to commodity price volatility. In addition, in poor economic environments and tight financial markets, the risk of a counterparty default is heightened and fewer counterparties may participate in derivative transactions, which could result in greater concentration of exposure to any one counterparty or a larger percentage of the Company’s future production being subject to commodity price changes.
Derivative Instruments	Derivative Instruments All derivative instruments are recorded on the consolidated balance sheet at fair value as either an asset or a liability with changes in fair value recognized currently in earnings. Although derivative instruments are used by the Company to manage the price risk attributable to its expected oil and natural gas production, those derivative instruments have not been designated as accounting hedges under the accounting guidance. All of our derivatives are accounted for as mark-to-market activities. Under ASC Topic 815, “Derivatives and Hedging,” these instruments are recorded on the consolidated balance sheets at fair value as either short term or long-term assets or liabilities based on their anticipated settlement date. The Company nets derivative assets and liabilities by commodity for counterparties where a legal right to such offset exists. Changes in the derivatives’ fair values are recognized in current earnings since the Company has elected not to designate its current derivative contracts as cash flow hedges for accounting purposes. The Company has recognized certain conversion features within its Second Lien Term Loan as embedded derivatives that have been bifurcated from the Second Lien Term Loan, as defined in Note 9 - Derivatives , and accounted for separately from the debt. The Company has recognized that our crude oil sales agreement with ARM no longer meets the criteria for the “normal purchase normal sales” exception under ASC 815, “Derivatives and Hedging,” due to the Company not meeting the minimum quantities deliverable under the contract and the net settlement criteria being met. As a result, an embedded derivative exists as it is no longer probable the contract will only result in physical deliveries of crude oil and may net settle. See Note 9 - Derivatives for additional information.
Recently Adopted Accounting Standards and Accounting Standards Not Yet Adopted	Recently Adopted Accounting Standards In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (ASU) No. 2016-02, Leases (Topic 842), a standard on lease accounting requiring a lessee to recognize assets and liabilities on the balance sheet for leases with lease terms greater than 12 months. This standard was effective for annual and interim periods beginning after December 15, 2018. We adopted this standard effective January 1, 2019, utilizing a modified retrospective transition approach. We chose to use the effective date as our date of initial application. Consequently, financial information was not updated and the disclosures required under the new standard were not provided for dates and periods before January 1, 2019. The standard includes optional transition practical expedients intended to simplify its adoption. We elected to adopt the package of practical expedients, which allowed us to retain the historical lease classification, including treatment for land easements, determined under legacy GAAP as well as a relief from reviewing expired or existing contracts to determine if they contain leases. This standard does not apply to the Company’s leases that provide the right to explore for minerals, oil, or natural gas resources. Upon adoption, we recognized operating lease liabilities totaling approximately $7.5 million, with corresponding right of use assets totaling $7.4 million. The liabilities were calculated as the present value of the remaining minimum rental payments for existing operating leases. This standard did not materially impact our consolidated net earnings and had no impact on our cash flows (see Note 10 - Leases ). Accounting Standards Not Yet Adopted In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments , which replaces the currently required incurred loss methodology with an expected loss methodology. This new methodology requires that a financial asset measured at amortized cost be presented at the net amount expected to be collected. The update is intended to provide financial statement users with more useful information about expected credit losses on financial instruments. The amended standard is effective for the Company on January 1, 2023, with early adoption permitted, and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Company is evaluating the impact the adoption of ASU 2016-13 will have on its consolidated financial statements. In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement , which modifies the fair value disclosure requirements based on application of the disclosure framework. The provisions removed or amended certain disclosures and in some cases, the ASU requires additional disclosures. The standard is effective for the Company for fiscal years, and interim periods within those years, beginning after December 15, 2019. The Company is evaluating the impact the adoption of ASU 2018-13 will have on its consolidated financial statements.

BASIS OF PRESENTATION AND SUM_3

BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Schedule of accrued liabilities	At December 31, 2019 and 2018 , the Company’s accrued liabilities consisted of the following: 2019 2018 (In thousands) Accrued personnel costs $ — $ 2,300 Accrued drilling and completion costs 5,021 2,849 Drilling advances 1,328 5,001 Accrued production expenses 3,326 2,926 Other accrued liabilities 3,885 1,718 Short-term operating lease liabilities 412 — $ 13,972 $ 14,794

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES (Tables)	12 Months Ended
	Dec. 31, 2019
Extractive Industries [Abstract]
Schedule of capitalized costs of unproved properties excluded from amortization	The following table sets forth a summary of oil and natural gas property costs (net of divestitures) at December 31, 2019 and 2018 : December 31, 2019 2018 (In thousands) Oil and natural gas properties: Proved $ 478,569 $ 358,858 Unproved 109,590 169,863 Total oil and natural gas properties 588,159 528,721 Accumulated depletion, depreciation, amortization and impairment (359,304 ) (98,342 ) Oil and natural gas properties, net $ 228,855 $ 430,379 The following table sets forth a summary of costs withheld from amortization as of December 31, 2019: Year of Acquisition Total 2019 2018 2017 (In thousands) Unamortized costs: Unproved leasehold costs $ 109,590 $ 1,643 $ 85,598 $ 22,349 Total $ 109,590 $ 1,643 $ 85,598 $ 22,349

ACQUISITIONS AND DIVESTITURES (

ACQUISITIONS AND DIVESTITURES (Tables)	12 Months Ended
	Dec. 31, 2019
Business Combinations and Divestitures [Abstract]
Schedule of allocation of the purchase price to the assets acquired and liabilities assumed	The following table presents the final allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date: As of October 16, 2018 (In thousands) Fair value of net assets: Proved oil and natural gas properties $ 12,562 Unproved oil and natural gas properties 4,542 Total assets acquired 17,104 Asset retirement obligations assumed (65 ) Fair value of net assets acquired $ 17,039

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Schedule of asset retirement obligations	The following table summarizes the changes in the Company’s ARO for the years ended December 31, 2019 and 2018 : For the Year Ended December 31, 2019 2018 (In thousands) ARO, beginning of period $ 2,444 $ 952 Additional liabilities incurred 186 374 Accretion expense 433 85 Liabilities settled (78 ) (87 ) Revision in estimates 438 1,120 ARO, end of period 3,423 2,444 Less: current portion of ARO (1) — (11 ) ARO, non-current $ 3,423 $ 2,433 (1) The current portion of ARO is included in accrued liabilities in the consolidated balance sheets.

REVENUE (Tables)

REVENUE (Tables)	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Disaggregation of revenue	The following table disaggregates the Company’s revenue by contract type ( in thousands ) for the year ended December 31, 2019 : Year Ended December 31, 2019 Short-term contracts Long-term contracts Total Crude oil $ 9,711 $ 49,304 $ 59,015 Natural gas 220 2,960 3,180 NGLs 188 3,680 3,868
Company's major customers as a percentage of total revenue	During the year ended December 31, 2019 , the Company’s major customers as a percentage of total revenue consisted of the following: Year ended December 31, 2019 2018 ARM Energy Management, LLC 68 % — % Texican Crude & Hydrocarbon, LLC 19 % 87 % Lucid Energy Delaware, LLC 12 % 10 % Other below 10% 1 % 3 % 100 % 100 %

FAIR VALUE OF FINANCIAL INSTR_2

FAIR VALUE OF FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Summary of recurring fair values of assets and liabilities measured at fair value	Recurring Fair Value Measurements Fair Value Measurement Classification Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total (In thousands) As of December 31, 2019 Oil and natural gas derivative instruments: Oil and natural gas derivative swap contracts $ — $ (3,932 ) $ — $ (3,932 ) Oil and natural gas derivative collar contracts — 301 — 301 Embedded derivative instruments: Net settlement provisions under ARM sales agreement — — (3,238 ) (3,238 ) Total $ — $ (3,631 ) $ (3,238 ) $ (6,869 ) As of December 31, 2018 Oil and natural gas derivative instruments: Oil and natural gas derivative swap contracts $ — $ (2,923 ) $ — $ (2,923 ) Oil and natural gas derivative collar contracts — 4,047 — 4,047 Embedded derivative instruments: Second Lien Term Loan conversion features — — (1,965 ) (1,965 ) Total $ — $ 1,124 $ (1,965 ) $ (841 )
Changes in fair value of level three assets and liabilities recurring basis	The following table sets forth a reconciliation of changes in the fair value of the Company’s financial assets and liabilities classified as Level 3 in the fair value hierarchy, except for the commodity derivatives classified as Level 2, as disclosed in Note 9 , as of December 31, 2019 and 2018 : Firm Takeaway and Pricing Agreement Net Settlement Provisions Second Lien Term Loan Conversion Features Total (in thousands) Balance at January 1, 2019 $ — $ (1,965 ) $ (1,965 ) Fair value of the converted portion of the embedded derivatives associated with the Second Lien Term Loan — 2,300 2,300 Fair value of the embedded derivatives in ARM Sales Agreement (3,238 ) (335 ) (3,573 ) Balance at December 31, 2019 $ (3,238 ) $ — $ (3,238 ) Second Lien Term Loan Conversion Features Warrant Liabilities Total (in thousands) Balance at January 1, 2018 $ (72,714 ) $ (223 ) $ (72,937 ) Transferred to equity — 223 223 Fair value of the converted portion of the embedded derivatives associated with the Second Lien Term Loan 12,406 — 12,406 Change in fair value of derivative liabilities 58,343 — 58,343 Balance at December 31, 2018 $ (1,965 ) $ — $ (1,965 )

DERIVATIVES (Tables)

DERIVATIVES (Tables)	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of derivative instruments	The following table presents the Company’s derivative position for the production periods indicated as of December 31, 2019 : Description Notional Volume (Bbls/d) Production Period Weighted Average Price ($/Bbl) Oil Positions Oil Swaps 1,028 January 2020 - December 2020 $ 56.28 Oil Swaps 370 January 2021 - December 2021 $ 53.07 Basis Swaps (1) 1,500 January 2020 - December 2020 $ (5.62 ) 3 Way Collar Floor sold price (put) 228 January 2020 - December 2020 $ 40.00 3 Way Collar Floor purchase price (put) 228 January 2020 - December 2020 $ 50.00 3 Way Collar Ceiling sold price (call) 228 January 2020 - December 2020 $ 59.60 3 Way Collar Floor sold price (put) 80 January 2021 - December 2021 $ 37.50 3 Way Collar Floor purchase price (put) 80 January 2021 - December 2021 $ 47.50 3 Way Collar Ceiling sold price (call) 80 January 2021 - December 2021 $ 59.30 Oil Collar Floor purchase price (put) 512 January 2020 - December 2020 $ 49.50 Oil Collar Ceiling sold price (call) 512 January 2020 - December 2020 $ 63.87 Oil Collar Floor purchase price (put) 742 January 2021 - December 2021 $ 50.00 Oil Collar Ceiling sold price (call) 742 January 2021 - December 2021 $ 59.70 Description Notional Volume (MMBtus/d) Production Period Weighted Average Price ($/MMBtu) Natural Gas Positions Gas Swaps 4,557 January 2020 - December 2020 $ 2.57 Gas Swaps 4,184 January 2021 - March 2021 $ 2.77 3 Way Collar Floor sold price (put) 563 January 2020 - December 2020 $ 1.60 3 Way Collar Floor purchase price (put) 563 January 2020 - December 2020 $ 2.10 3 Way Collar Ceiling sold price (call) 563 January 2020 - December 2020 $ 3.00 3 Way Collar Floor sold price (put) 133 January 2021 - December 2021 $ 1.65 3 Way Collar Floor purchase price (put) 133 January 2021 - December 2021 $ 2.15 3 Way Collar Ceiling sold price (call) 133 January 2021 - December 2021 $ 3.05 Gas Collar Floor purchase price (put) 2,748 January 2020 - December 2020 $ 2.55 Gas Collar Ceiling sold price (call) 2,748 January 2020 - December 2020 $ 3.07 Gas Collar Floor purchase price (put) 4,464 January 2021 - December 2021 $ 2.20 Gas Collar Ceiling sold price (call) 4,464 January 2021 - December 2021 $ 2.97 (1) The weighted average price under these basis swaps is the fixed price differential between the index prices of the Midland WTI and the Cushing WTI. The table below summarizes the Company’s net gain (loss) on commodity derivatives for the year ended December 31, 2019 and 2018 : Year Ended December 31, 2019 2018 (in thousands) Unrealized gain (loss) on unsettled derivatives $ (5,575 ) $ 1,977 Net settlements paid on derivative contracts (3,214 ) (2,742 ) Net settlements receivable (payable) on derivative contracts (196 ) 820 Net gain (loss) on commodity derivatives $ (8,985 ) $ 55 The following information summarizes the gross fair values of derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Company’s consolidated balance sheets as of December 31, 2019 and as of December 31, 2018 : As of December 31, 2019 Gross Amount of Recognized Assets and Liabilities Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets (In thousands) Offsetting Derivative Assets: Current assets $ 1,009 $ (582 ) $ 427 Long-term assets 359 (172 ) 187 Total assets $ 1,368 $ (754 ) $ 614 Offsetting Derivative Liabilities: Current liabilities $ (4,827 ) $ 582 $ (4,245 ) Current embedded derivative liabilities (799 ) — (799 ) Long-term commodity derivative liabilities (172 ) 172 — Long-term embedded derivative liabilities (2,439 ) — (2,439 ) Total liabilities $ (8,237 ) $ 754 $ (7,483 ) As of December 31, 2018 Gross Amount of Recognized Assets and Liabilities Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets (In thousands) Offsetting Derivative Assets: Current assets $ 4,122 $ (1,571 ) $ 2,551 Long-term assets 1,854 (32 ) 1,822 Total assets $ 5,976 $ (1,603 ) $ 4,373 Offsetting Derivative Liabilities: Current liabilities $ (2,086 ) $ 1,571 $ (515 ) Long-term commodity derivative liabilities (2,766 ) 32 (2,734 ) Long-term embedded derivative liabilities (1,965 ) — (1,965 ) Total liabilities $ (6,817 ) $ 1,603 $ (5,214 ) The Company’s derivative instruments as of December 31, 2019 and 2018 , include the following: December 31, 2019 2018 (In thousands) Derivative assets (liabilities): Derivative assets - current $ 427 $ 2,551 Derivative assets - non-current (1) 187 1,822 Derivative liabilities - current (3) (5,044 ) (515 ) Derivative liabilities - non-current (2) (3) (4) (2,439 ) (4,699 ) Total derivative liabilities, net $ (6,869 ) $ (841 ) (1) The non-current derivative assets are included in other assets in the consolidated balance sheets. (2) The non-current derivative liabilities are included in long-term derivative instruments and other non-current liabilities in the consolidation balance sheets. (3) The ARM sales agreement includes an embedded derivative. As of December 31, 2019 , the embedded derivative is included as current liabilities and non-current liabilities of $0.8 million and $2.4 million, respectively. (4) Includes $2.0 million embedded derivative associated with Second Lien Term Loan and $2.7 million in commodity derivatives as of December 31, 2018 .

LEASES (Tables)

LEASES (Tables)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Right of use assets and lease liabilities	The Company’s ROU assets and operating lease liabilities were included in the consolidated balance sheets as follows (in thousands): December 31, 2019 Right of use assets: Right of use assets - long-term (1) $ 1,722 Lease liabilities: Lease liabilities - current (2) $ 412 Lease liabilities - long-term (3) 1,323 Total lease liabilities $ 1,735 (1) Right of use assets - long-term are included in other assets on the consolidated balance sheets. (2) Lease liabilities - current are included in accrued liabilities and other on the consolidated balance sheets. (3) Lease liabilities - long-term are included in long-term derivatives instruments and other non-current liabilities on the consolidated balance sheets.
Components of lease costs and other information	The components of lease cost were classified as follows (in thousands): Year Ended December 31, 2019 Fixed lease costs $ 5,084 Short-term lease costs 1,096 Variable lease costs 575 Total lease costs $ 6,755 Lease Cost included in the Consolidated Financial Statements Year Ended December 31, 2019 Oil and natural gas properties, full cost method of accounting, net (1) Total lease costs capitalized $ 5,688 Production costs 593 General and administrative 474 Total lease costs expensed 1,067 Total lease costs $ 6,755 (1) Represents short-term lease capital expenditures related to drilling rigs for the year ended December 31, 2019 . During the year ended December 31, 2019 , the following cash activities were associated with the Company’s leases as follows (in thousands): Cash paid for amounts included in the measurement of operating lease liabilities: Operating cash flows from operating leases $ 222 Investing cash flows from operating leases $ 4,768 As of December 31, 2019 , the weighted average lease term and discount rate related to the Company’s remaining leases were as follows: Lease term and discount rate Weighted-average remaining lease term (years) 4.45 Weighted-average discount rate 5.3 %
Minimum future payments for long-term operating leases under scope of ASC 842	As of December 31, 2019 , minimum future payments, including imputed interest, for long-term operating leases under the scope of ASC Topic 842, “Leases”, were as follows (in thousands): Year Amount 2020 $ 477 2021 425 2022 353 2023 379 2024 315 After 2024 — Less: the effects of discounting (214 ) Present value of lease liabilities $ 1,735
Minimum future payments for long-term operating leases under scope of ASC 840	As of December 31, 2018 , minimum future payments, including imputed interest, for long-term operating leases under the scope of ASC Topic 840, “Leases”, were as follows (in thousands): Year Amount 2019 $ 7,586 2020 66 2021 — 2022 — 2023 — After 2023 — Total lease commitment $ 7,652

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Schedule of long-term debt instruments	December 31, 2019 2018 (In thousands) 8.25% Second Lien Term Loan, due 2021, net of debt issuance costs and debt discount $ — $ 82,804 Revolving Credit Agreement, due October 2023 115,000 75,000 Total long-term debt $ 115,000 $ 157,804 Less: current portion (115,000 ) — Total long-term debt, net of current portion $ — $ 157,804
Schedule of interest expense	The components of interest expense are as follows (in thousands) for the year ended December 31, 2019 and 2018 : Year Ended December 31, 2019 2018 Interest on debt $ 6,488 $ 2,975 Net revenue payments on financing arrangement 888 — Paid-in-kind interest on term loans 1,590 12,213 Amortization of debt financing costs 803 3,241 Amortization of discount on term loans 1,657 14,398 Total $ 11,426 $ 32,827

LONG-TERM DEFERRED REVENUE LI_2

LONG-TERM DEFERRED REVENUE LIABILITIES AND OTHER LONG-TERM LIABILITIES (Tables)	12 Months Ended
	Dec. 31, 2019
Long-term Deferred Revenue Liabilities and Other Long-term Liabilities [Abstract]
Schedule of long-term deferred revenue liabilities and other long-term liabilities	December 31, 2019 2018 (in thousands) Long-term deferred revenue liabilities $ 36,920 $ 52,500 Long-term deferred proceeds, WLR agreement 13,061 — Long-term deferred proceeds, WLWI agreement 23,768 — Other — 13 Total long-term deferred revenue liabilities and other long-term liabilities $ 73,749 $ 52,513

RELATED PARTY TRANSACTIONS (Tab

RELATED PARTY TRANSACTIONS (Tables)	12 Months Ended
	Dec. 31, 2019
Related Party Transactions [Abstract]
Schedule of related party transactions	During the year ended December 31, 2019 and 2018 , the Company was engaged in the following transactions with certain related parties: As of December 31, Related Party Transactions 2019 2018 (In thousands) Directors and Officers: Värde Partners, Inc. (1) The Company acquired oil and natural gas interests from VPD, an affiliate of Värde $ — $ 10,705 Receivable balance outstanding for operating costs associated with VPD's producing wells — 1,843 ImPetro Operating, LLC, a wholly-owned subsidiary of the Company is the operator for two of VPD's producing wells and VPD reimbursed the Company for operating charges — 44 Revenue payable balance due as of December 31, 2019 for revenue associated with VPD's producing wells (157 ) — Payable to WLR for net proportionate share of production (161 ) — Payable to WLWI for net proportionate share of production (526 ) Asset disposition accounted for as a financing arrangement (36,833 ) — Total: $ (37,677 ) $ 12,592 (1) Värde was the lead lender in the Company’s Second Lien Term Loan (see Note 11 - Long-Term Debt ), is a major stockholder of the Company, and also participated in various transactions in 2018 and 2019 (which such transactions included the issuance of preferred stock to Värde Parties) (see Note 15 - Preferred Stock ).

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Schedule of components of income tax provision (benefit)	The income tax provision (benefit) for the years ended December 31, 2019 and 2018 consisted of the following: December 31, 2019 2018 (in thousands) U.S. Federal: Current $ — $ — Deferred (55,366 ) (7,496 ) State and local: Current — — Deferred (4,220 ) 509 (59,586 ) (6,987 ) Change in valuation allowance 59,586 6,987 Income tax provision $ — $ —
Schedule of deferred tax assets and liabilities	The tax effects of temporary differences that give rise to the Company’s deferred tax asset as of December 31, 2019 and 2018 consisted of the following: December 31, 2019 2018 (In thousands) Deferred tax assets: Net operating loss carry-forward $ 31,992 $ 27,568 Share based compensation 531 808 Abandonment obligation 761 541 Derivative instruments 1,526 — Deferred revenue 15,863 11,630 Interest expense 4,540 3,804 Lease Liability 386 — Property Basis 27,837 — Accrued liabilities and other 144 85 Total deferred tax asset 83,580 44,436 Valuation allowance (83,197 ) (23,611 ) Deferred tax asset, net of valuation allowance 383 20,825 Deferred tax liabilities: Derivative instruments — 249 Oil and natural gas properties and equipment — 20,576 Right of use asset 383 — Total deferred tax liability 383 20,825 Net deferred tax asset (liability) $ — $ —
Schedule of effective income tax rate reconciliation	Reconciliation of the Company’s effective tax rate to the expected U.S. federal tax rate is: Year Ended December 31, 2019 2018 Effective federal tax rate 21 % 21 % State tax rate, net of federal benefit 1 % 2 % Change in fair value derivative liability — % 296 % Debt discount amortization — % (73 )% Change in rate — % (6 )% Other permanent differences — % (6 )% NOL true-up - §382 limitation — % (6 )% Loss from early debt extinguishment — % (59 )% Other — % (1 )% Valuation allowance (22 )% (169 )% Net — % — %

PREFERRED STOCK (Tables)

PREFERRED STOCK (Tables)	12 Months Ended
	Dec. 31, 2019
Temporary Equity Disclosure [Abstract]
Schedule of preferred stock	The components of each series of preferred stock are summarized in the table below: Series C Preferred Stock Series D Preferred Stock Series E Preferred Stock Series F Preferred Stock Number of Shares Amount Number of Shares Amount Number of Shares Amount Number of Shares Amount (In thousands, except shares) Balance, January 1, 2019 125,000 $ 132,296 39,254 $ 40,729 — $ — — $ — Change in carrying value due to modification — (46,632 ) — (15,056 ) — — — — Issuance of Preferred Stock in extinguishment of debt — — — — 60,000 62,115 55,000 46,682 Paid-in-kind dividends — 13,639 — 3,409 — 4,170 — 4,179 Balance, December 31, 2019 125,000 $ 99,303 39,254 $ 29,082 60,000 $ 66,285 55,000 $ 50,861

STOCKHOLDERS' EQUITY (Tables)

STOCKHOLDERS' EQUITY (Tables)	12 Months Ended
	Dec. 31, 2019
Equity [Abstract]
Summary of warrant activity	The following table provides a summary of warrant activity as of December 31, 2019 and 2018 : Warrants Weighted- Average Exercise Price Outstanding at Outstanding at January 1, 2018 11,882,800 $ 3.34 Exercised (3,975,957 ) 2.21 Forfeited or expired (2,889,514 ) 3.35 Outstanding at Outstanding at January 1, 2019 5,017,329 3.83 Forfeited or expired (2,263,267 ) 2.81 Outstanding at December 31, 2019 2,754,062 $ 4.67 The outstanding warrants at December 31, 2019 will expire as follows: Year Warrants 2020 174,642 2021 — 2022 2,579,420 2,754,062

SHARE BASED AND OTHER COMPENS_2

SHARE BASED AND OTHER COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Schedule of share-based compensation, activity	The following table sets forth the stock based compensation expense recognized during the years ended December 31, 2019 and 2018 and the unamortized portion of the stock based compensation expense and weighted average amortization period of the remaining vesting period for the year ended December 31, 2019 and 2018 , the Company’s share-based compensation consisted of the following (dollars in thousands) : Year Ended December 31, 2019 2018 Stock Options Restricted Stock Total Stock Options Restricted Stock Total Share based compensation expensed $ 317 $ 6,189 $ 6,506 $ 2,158 $ 6,842 $ 9,000 Unrecognized share-based compensation costs $ 100 $ 1,228 $ 1,328 $ 487 $ 3,501 $ 3,988 Weighted average amortization period remaining (in years) 1.55 1.05 0.03 0.50
Schedule of share-based compensation, restricted stock units award activity	A summary of restricted stock grant activity pursuant to the 2012 Plan and the 2016 Plan for the year ended December 31, 2019 , is presented below: Number of Shares Weighted Average Grant Date Price Outstanding at January 1, 2018 2,475,266 $ 4.22 Granted 1,194,944 $ 4.59 Vested and issued (1,436,146 ) $ 2.38 Forfeited or canceled (1) (1,280,480 ) $ 4.44 Outstanding at December 31, 2018 953,584 $ 4.85 Granted 3,684,372 $ 1.46 Vested and issued (2,341,269 ) $ 2.39 Forfeited or canceled (1) (894,512 ) $ 2.94 Outstanding at December 31, 2019 1,402,175 $ 1.26 (1) Forfeitures are accounted for as and when incurred.
Schedule of share-based compensation, stock options, activity	A summary of stock option activity pursuant to the 2016 Plan for the years ended December 31, 2019 and 2018, is presented below: Number of Options Weighted Average Exercise Price Number of Options Vested/ Exercisable Weighted Average Remaining Contractual Life (Years) Outstanding at January 1, 2018 7,305,000 $ 3.74 3,534,484 8.9 Granted 352,500 $ 4.07 Exercised (1,024,877 ) $ 2.67 Forfeited or canceled (1,601,045 ) $ 4.20 Outstanding at December 31, 2018 5,031,578 $ 3.81 5,035,317 7.9 Granted 135,000 $ 2.17 Exercised — $ — Forfeited or canceled (1) (1,578,228 ) $ 3.14 Outstanding at December 31, 2019 3,588,350 $ 4.05 4,125,842 7.2 (1) Forfeitures are accounted for as and when incurred.

INCOME (LOSS) PER COMMON SHARE

INCOME (LOSS) PER COMMON SHARE (Tables)	12 Months Ended
	Dec. 31, 2019
Earnings Per Share [Abstract]
Schedule of basic and diluted net loss per share	The following table shows the computation of basic and diluted net loss per share for the years ended December 31, 2019 and 2018 (in thousands): 2019 2018 Net loss $ (272,121 ) $ (4,143 ) Dividends on preferred stock (25,397 ) (10,687 ) Unallocated net loss $ (297,518 ) $ (14,830 ) Numerator for basic loss per share: Net loss attributable to common stockholders $ (297,518 ) $ (14,830 ) Denominator for basic loss per share: Basic weighted average common shares outstanding 87,912,362 62,854,214 Net loss per share: Basic attributable to common stockholders $ (3.38 ) $ (0.24 ) Numerator for diluted loss per share: Net loss attributable to common stockholders $ (297,518 ) $ (14,830 ) Add: interest expense on convertible Second Lien Term Loan — 13,429 Less: gain on fair value change of embedded derivatives associated with Second Lien Term Loan — (35,471 ) Net loss attributable to common stockholders $ (297,518 ) $ (36,872 ) Denominator for diluted net loss per share: Basic weighted average common shares outstanding 87,912,362 62,854,214 Dilution effect of if-converted Second Lien Term Loan — 15,597,127 Diluted weighted average common shares outstanding 87,912,362 78,451,341 Net loss per share - diluted: Common shares (diluted) $ (3.38 ) $ (0.47 )
Schedule of antidilutive securities excluded from computation of diluted loss per share	The Company excluded the following shares from the diluted loss per share calculations above because they were anti-dilutive at December 31, 2019 and 2018 : December 31, 2019 2018 Stock Options 3,588,350 5,031,578 Series C Preferred Stock — 26,295,616 Series D Preferred Stock — 8,543,670 Stock Purchase Warrants 2,754,062 5,017,329 Series E Preferred Stock 25,667,871 — Conversion of term loans — — 32,010,283 44,888,193

SUPPLEMENTAL NON-CASH TRANSAC_2

SUPPLEMENTAL NON-CASH TRANSACTIONS (Tables)	12 Months Ended
	Dec. 31, 2019
Supplemental Cash Flow Elements [Abstract]
Schedule of cash flow, supplemental disclosures	The following table presents the supplemental disclosure of cash flow information for the years ended December 31, 2019 and 2018 : Year Ended December 31, 2019 2018 (in thousands) Non-cash investing and financing activities excluded from the statement of cash flows: Issued shares of common stock and preferred stock upon extinguishment of debt and modification of Series C Preferred Stock and Series D Preferred Stock $ 141,787 $ 64,504 Common stock issued for acquisition of oil and natural gas properties — 24,778 Cashless exercise of warrants — 359 Deferred revenue realized upon purchase option exercise 16,700 — Right of use assets obtained in exchange for operating lease obligations 7,500 — Change in capital expenditures for drilling costs in accrued liabilities 2,010 7,850 Accrued cumulative paid in kind dividends on preferred stock 25,397 10,687 Change in asset retirement obligations 546 1,495 Reduction of fair value for converted embedded derivatives — 12,406 Transfer of warrant derivative instruments to equity — 223

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Schedule of required daily production	Under the terms of the new contract, the Company received pricing differentials on the crude oil sales contract subject to minimum quantities of crude oil to be delivered as follows: Date Quantity (Barrels per Day) March 2019 - June 2019 5,000 July 2019 - December 2019 4,000 January 2020 - June 2020 5,000 July 2020 - June 2021 6,000 July 2021 - December 2024 (1) 7,500 (1) Extending to the later of December 2024 or 5 years from the EPIC Crude Oil pipeline in-service date (February 2025).

SUPPLEMENTARY INFORMATION ON _2

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT (Tables)	12 Months Ended
	Dec. 31, 2019
Supplemental Oil And Gas Reserve Information [Abstract]
Costs incurred for and results of operations for oil and gas producing activities disclosure	The following table sets forth the costs incurred in the Company ’ s oil and natural gas acquisition, exploration and development activities and includes costs whether capitalized or expensed as well as revisions and additions to the estimated future asset retirement obligations : December 31, 2019 2018 (In thousands) Acquisition costs: Unproved properties $ 1,644 $ 93,926 Proved properties — 22,356 Exploration costs 40,284 89,351 Development costs 51,198 78,103 Total $ 93,126 $ 283,736 The following table sets forth the results of operations for oil and natural gas producing activities: December 31, 2019 2018 (In thousands) Revenues $ 66,063 $ 70,216 Production costs (16,127 ) (13,843 ) Production taxes (3,302 ) (3,709 ) Accretion of asset retirement obligation (433 ) (85 ) Depletion, depreciation and amortization (33,071 ) (25,159 ) Full cost ceiling impairment (228,324 ) — Total $ (215,194 ) $ 27,420
Schedule of proved developed and undeveloped oil and gas reserve quantities	The following table provides a roll forward of the total proved reserves for the years ended December 31, 2019 and 2018, as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year: Crude Oil (Bbls) Natural Gas (Mcf) NGLs (Bbls) January 1, 2018 7,171,339 16,059,926 1,604,570 Extensions and discoveries 15,881,727 38,957,588 4,565,994 Purchase of reserves 1,883,047 8,897,115 682,964 Revisions of previous estimates (2,641,353 ) 17,690,723 1,769,448 Production (1,089,724 ) (2,855,739 ) (246,425 ) December 31, 2018 21,205,036 78,749,613 8,376,551 Extensions and discoveries 856,838 2,477,061 190,203 Revisions of previous estimates (15,596,115 ) (48,718,235 ) (6,067,700 ) Production (1,130,855 ) (3,063,927 ) (220,832 ) December 31, 2019 5,334,904 29,444,512 2,278,222 Proved Developed Reserves, included above: Balance, January 1, 2018 2,531,397 6,594,446 644,102 Balance, December 31, 2018 6,278,036 27,046,195 2,653,908 Balance, December 31, 2019 5,334,904 29,444,512 2,278,222 Proved Undeveloped Reserves, included above: Balance, January 1, 2018 4,639,942 9,465,480 960,468 Balance, December 31, 2018 14,927,000 51,703,418 5,722,643 Balance, December 31, 2019 — — —
Standardized measure of discounted future cash flows relating to proved reserves disclosure	The standardized measure of discounted future net cash flows relating to proved oil, natural gas and NGL reserves is as follows: December 31, 2019 2018 (In thousands) Future cash inflows $ 358,127 $ 1,500,263 Future production costs (176,498 ) (414,117 ) Future development costs (7,284 ) (346,225 ) Future income tax expense — (62,842 ) Future net cash flows 174,345 677,079 10% discount to reflect timing of cash flows (54,171 ) (384,345 ) Total $ 120,174 $ 292,734
Schedule of changes in standardized measure of discounted future net cash flows	Changes in the standardized measure of discounted future net cash flows relating to proved oil, natural gas and NGL reserves are as follows: Year Ended December 31, 2019 2018 (In thousands) Balance at beginning of period $ 292,734 $ 68,812 Net changes in prices and production costs (1) (275,539 ) 24,261 Sales of oil and natural gas produced during the year, net (42,442 ) (49,271 ) Changes in estimated future development costs (2) 272,579 (39,938 ) Net change due to extensions and discoveries 18,044 161,785 Net change due to purchases of minerals in place — 55,278 Previously estimated development costs incurred during the year 36,298 68,349 Net changes due to revision of previous quantity estimates (3) (255,125 ) 28,350 Accretion of discount 29,273 6,881 Other - unspecified (4) 9,327 3,252 Net change in income taxes 35,025 (35,025 ) Balance at end of period $ 120,174 $ 292,734 (1) Net changes from prices and production costs were primarily the result of a 19% decrease in oil and natural gas prices and 45% increase in production costs from December 31, 2018 to December 31, 2019. (2) Future development costs decreased $272.6 million from December 31, 2018 to December 31, 2019. Our December 31, 2019 proved reserves report reflects the reclassification of all PUD reserves to unproved because of the uncertainty regarding the availability of capital for developing those reserves. Our December 31, 2018 proved reserves report included future development costs of $329.5 million associated with PUD reserves not included in our December 31, 2019 proved reserves report. (3) Negative revisions for 2019 are primarily the result of the reclassification of proved undeveloped reserves to unproved as reflected in our December 31, 2019 reserves report. (4) Other changes are the result of significant changes to our proved reserves from December 31, 2018 to December 31, 2019 and include significant estimates of the effects of changes in the economic lives of producing wells and reclassification of proved undeveloped reserves to unproved as reflected in our December 31, 2019 reserves report.

LIQUIDITY AND GOING CONCERN (De

LIQUIDITY AND GOING CONCERN (Details)

Jun. 05, 2020USD ($)

Apr. 21, 2020USD ($)

Feb. 28, 2020USD ($)

Feb. 24, 2020USD ($)

Sep. 30, 2019

May 06, 2019

Oct. 10, 2018USD ($)

Feb. 14, 2020installment

Jan. 17, 2020USD ($)installment

Dec. 31, 2019USD ($)

Oct. 31, 2019USD ($)

Jul. 31, 2019USD ($)

Jul. 26, 2019USD ($)

Mar. 05, 2019USD ($)

Mar. 04, 2019USD ($)

Dec. 31, 2018USD ($)

Line of Credit Facility [Line Items]

Long-term debt

$ 115,000,000

$ 157,804,000

Ratio of total debt to EBITDAX (not more than)

400.00%

Ratio of current assets to current liabilities (not less than)

100.00%

Revolving Credit Agreement, due October 2023

Line of Credit Facility [Line Items]

Line of credit facility, borrowing base

$ 95,000,000

$ 115,000,000

$ 115,000,000

$ 125,000,000

$ 108,000,000

108,000,000

Ratio of current assets to current liabilities (not less than)

85.00%

100.00%

Line of Credit | Revolving Credit Agreement, due October 2023

Line of Credit Facility [Line Items]

Long-term debt

$ 115,000,000

$ 115,000,000

$ 75,000,000

Option to effect repayment, in full, period after redetermination

30 days

Option to effect repayment, monthly installments, period after redetermination

6 months

Ratio of total debt to EBITDAX (not more than)

300.00%

400.00%

Ratio of current assets to current liabilities (not less than)

100.00%

Subsequent Event | Revolving Credit Agreement, due October 2023

Line of Credit Facility [Line Items]

Line of credit facility, borrowing base

$ 90,000,000

Borrowing base deficiency

$ 25,000,000

Covenant, borrowing base deficiency, number of equal monthly installments (in installments) | installment

2

4

Covenant, borrowing base deficiency, equal monthly installment, amount

$ 6,250,000

Subsequent Event | Line of Credit | Revolving Credit Agreement, due October 2023

Line of Credit Facility [Line Items]

Line of credit facility, borrowing base

$ 90,000,000

Borrowing base deficiency

$ 25,000,000

Installment payment

$ 7,750,000

$ 17,300,000

Forecast | Line of Credit | Revolving Credit Agreement, due October 2023

Line of Credit Facility [Line Items]

Borrowing base deficiency

$ 7,800,000

Installment payment

$ 7,750,000

BASIS OF PRESENTATION AND SUM_4

BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Narrative (Details)	12 Months Ended
	Dec. 31, 2019USD ($)$ / MMBTU$ / bbl	Dec. 31, 2018USD ($)$ / MMBTU$ / bbl	Jan. 01, 2019USD ($)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Allowance related to accounts receivable	$ 448,000	$ 25,000
Percentage of amortization expense	10.00%
Reserved ceiling value for oil (in dollars per barrel) | $ / bbl	55.69	65.56
Reserved ceiling value for natural gas (in dollars per MMBtu) | $ / MMBTU	2.58	3.10
Results of operations, impairment of oil and gas properties	$ 228,324,000	$ 0
Depreciation	200,000	100,000
Total lease liabilities	1,735,000
Right-of-use assets	$ 1,722,000	$ 0
Accounting Standards Update 2016-02
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Total lease liabilities			$ 7,500,000
Right-of-use assets			$ 7,400,000
Minimum
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Property, plant and equipment, useful life	4 years
Maximum
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Property, plant and equipment, useful life	20 years

BASIS OF PRESENTATION AND SUM_5

BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Summary of accrued liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Accounting Policies [Abstract]
Accrued personnel costs	$ 0	$ 2,300
Accrued drilling and completion costs	5,021	2,849
Drilling advances	1,328	5,001
Accrued production expenses	3,326	2,926
Other accrued liabilities	3,885	1,718
Short-term operating lease liabilities	412
Total accrued liabilities	$ 13,972	$ 14,794

OIL AND NATURAL GAS PROPERTIE_2

OIL AND NATURAL GAS PROPERTIES - Summary of oil and natural gas property costs (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Oil and natural gas properties:
Proved	$ 478,569	$ 358,858
Unproved	109,590	169,863
Total oil and natural gas properties	588,159	528,721
Accumulated depletion, depreciation, amortization and impairment	(359,304)	(98,342)
Oil and natural gas properties, net	228,855	$ 430,379
Unproved leasehold costs	109,590
Aging of Capitalized Exploratory Well Costs, Period One
Oil and natural gas properties:
Unproved	1,643
Unproved leasehold costs	1,643
Aging of Capitalized Exploratory Well Costs, Period Two
Oil and natural gas properties:
Unproved	85,598
Unproved leasehold costs	85,598
Aging of Capitalized Exploratory Well Costs, Period Three
Oil and natural gas properties:
Unproved	22,349
Unproved leasehold costs	$ 22,349

OIL AND NATURAL GAS PROPERTIE_3

OIL AND NATURAL GAS PROPERTIES - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Extractive Industries [Abstract]
Unproved oil and gas property transferred to prove undeveloped	$ 56,200,000	$ 11,100,000
Depreciation, depletion, amortization and accretion	32,600,000	25,200,000
Results of operations, impairment of oil and gas properties	$ 228,324,000	$ 0

ACQUISITIONS AND DIVESTITURES -

ACQUISITIONS AND DIVESTITURES - Narrative (Details)	Feb. 28, 2020USD ($)a	Aug. 16, 2019USD ($)a	Jul. 31, 2019USD ($)awellagreement	Dec. 31, 2019USD ($)wellproperty	Dec. 31, 2018USD ($)shares
Business Acquisition [Line Items]
Number of noncontiguous net acres sold (in acres) | a		513
Proceeds from sale of land held-for-investment		$ 16,700,000
Loss on early extinguishment of debt				$ 1,299,000	$ 20,370,000
OneEnergy Partners Operating, LLC
Business Acquisition [Line Items]
Payments for asset acquisition					$ 40,000,000
Equity interest issued or issuable (in shares) | shares					6,940,722
Consideration transferred, equity interests issued and issuable					$ 24,900,000
Purchase price before acquisition costs					64,900,000
Transaction costs and purchase price adjustments					1,100,000
VPD Texas, L.P.
Business Acquisition [Line Items]
Payments for asset acquisition					11,100,000
Transaction costs and purchase price adjustments					500,000
Anadarko
Business Acquisition [Line Items]
Payments for asset acquisition					7,100,000
Ameradev II, LLC
Business Acquisition [Line Items]
Payments for asset acquisition					7,200,000
Felix Energy Holdings II, LLC
Business Acquisition [Line Items]
Payments for asset acquisition					400,000
Southwest Royalties, LLC
Business Acquisition [Line Items]
Payments for asset acquisition					$ 17,000,000
Winkler Lea Transactions
Business Acquisition [Line Items]
Number of agreements | agreement			2
Proceeds from sale of overriding royalty interests and non-operated working interests			$ 39,000,000
WLR
Business Acquisition [Line Items]
Area of land (in acres) | a			1,446
Percentage of net revenue interests			25.00%
Period of option to repurchase overriding royalty interests			3 years
Period of limitations on ability to transfer overriding royalty interests			3 years
Purchase and sale agreement, proportionate share of production included in interest expense				$ 400,000
Purchase and sale agreement, payments for repurchase of overriding revenue interest		2,600,000
Loss on early extinguishment of debt		$ 1,300,000
WLWI
Business Acquisition [Line Items]
Area of land (in acres) | a			749
Purchase and sale agreement, repurchase price multiple			1.5
Percent of non-operating working interests			49.00%
Number of wells (in wells) | well			5	5
Purchase and sale agreement, covenant, liquidated damages			$ 150,000
Purchase and sale agreement, covenant, additional daily liquidated damages			$ 1,500
Purchase and sale agreement, covenant, additional daily liquidated damages, period after commitment date			60 days
Number of producing commitment wells (in wells) | well				3
Period of option to repurchase non-operating working interests			3 years
Period of limitations on ability to transfer non-operating working interests			3 years
Purchase and sale agreement, proportionate share of production included in interest expense				$ 500,000
Purchase and sale agreement, number of producing properties (in properties) | property				0
Purchase and Sale Agreement, Repurchase Period One | Winkler Lea Transactions
Business Acquisition [Line Items]
Period of option to repurchase overriding royalty interests			2 years
Purchase and sale agreement, repurchase price multiple			1.5
Purchase and Sale Agreement, Repurchase Period Two | Winkler Lea Transactions
Business Acquisition [Line Items]
Purchase and sale agreement, repurchase price multiple			1.75
Subsequent Event
Business Acquisition [Line Items]
Proceeds from sale of land held-for-investment	$ 24,100,000
Purchase and sale agreement, number of undeveloped net acres sold (in acres) | a	1,185

ACQUISITIONS AND DIVESTITURES_2

ACQUISITIONS AND DIVESTITURES - Summary of purchase price and the value of assets acquired (Details) - Southwest Royalties, LLC $ in Thousands	Oct. 16, 2018USD ($)
Business Acquisition [Line Items]
Value of assets acquired	$ 17,104
Asset retirement obligations assumed	(65)
Fair value of net assets acquired	17,039
Proved Properties
Business Acquisition [Line Items]
Value of assets acquired	12,562
Unproved Properties
Business Acquisition [Line Items]
Value of assets acquired	$ 4,542

ASSET RETIREMENT OBLIGATIONS -

ASSET RETIREMENT OBLIGATIONS - Summary of changes in Company's ARO (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO, beginning of period	$ 2,444	$ 952
Additional liabilities incurred	186	374
Accretion expense	433	85
Liabilities settled	(78)	(87)
Revision in estimates	438	1,120
ARO, end of period	3,423	2,444
Less: current portion of ARO	0	(11)
ARO, non-current	$ 3,423	$ 2,433

REVENUE - Narrative (Details)

REVENUE - Narrative (Details) $ in Millions	2 Months Ended	4 Months Ended	12 Months Ended		54 Months Ended
	Feb. 28, 2019$ / bbl	Jun. 30, 2019$ / bbl	Jun. 30, 2020$ / bbl	Dec. 31, 2019USD ($)$ / bbl	Dec. 31, 2024$ / bbl	Dec. 31, 2018USD ($)
Disaggregation of Revenue [Line Items]
Revenue, performance obligation, description of timing				Revenue is recognized when control passes to the purchaser, which generally occurs when production is transferred to the purchaser. The Company measures revenue as the amount of consideration it expects to receive in exchange for the commodities transferred. All the Company’s revenues from contracts with customers represent products transferred at a point in time as control is transferred to the customer. The Company records revenue based on consideration specified in its contracts with its customers. The amounts collected on behalf of third parties are recorded in revenue payable. The Company recognizes revenue in the amount that reflects the consideration it expects to receive in exchange for transferring control of those goods to the customer. The contract consideration in the Company’s variable price contracts is typically allocated to specific performance obligations in the contract according to the price stated in the contract. Payment is generally received one or two months after the sale has occurred.
Crude oil price differential (in dollars per barrel)	5.15	9.25
Tariff fee (in dollars per barrel)				0.75
Receivables from customers | $				$ 9.1		$ 8.2
Receivables from joint interest partners | $				$ 9.5		$ 11.4
Forecast
Disaggregation of Revenue [Line Items]
Crude oil price differential (in dollars per barrel)			6.50		4.95
Crude oil
Disaggregation of Revenue [Line Items]
Revenue, performance obligation, description of timing				The Company recognizes crude oil revenue when control passes to the purchaser.
Natural Gas and NGLs
Disaggregation of Revenue [Line Items]
Revenue, performance obligation, description of timing				The Company recognizes revenue for natural gas and NGLs when control passes at the tailgate of the processing plant.
Minimum
Disaggregation of Revenue [Line Items]
Revenue, performance obligation, settlement statement delivery period				30 days
Maximum
Disaggregation of Revenue [Line Items]
Revenue, performance obligation, settlement statement delivery period				60 days

REVENUE - Summary of disaggrega

REVENUE - Summary of disaggregation of revenue (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disaggregation of Revenue [Line Items]
Revenues	$ 66,063	$ 70,216
Crude oil
Disaggregation of Revenue [Line Items]
Revenues	59,015
Crude oil | Short-term contracts
Disaggregation of Revenue [Line Items]
Revenues	9,711
Crude oil | Long-term contracts
Disaggregation of Revenue [Line Items]
Revenues	49,304
Natural gas
Disaggregation of Revenue [Line Items]
Revenues	3,180	5,246
Natural gas | Short-term contracts
Disaggregation of Revenue [Line Items]
Revenues	220
Natural gas | Long-term contracts
Disaggregation of Revenue [Line Items]
Revenues	2,960
NGLs
Disaggregation of Revenue [Line Items]
Revenues	3,868	$ 6,928
NGLs | Short-term contracts
Disaggregation of Revenue [Line Items]
Revenues	188
NGLs | Long-term contracts
Disaggregation of Revenue [Line Items]
Revenues	$ 3,680

REVENUE - Summary of Company's

REVENUE - Summary of Company's major customers as a percentage of total revenue (Details) - Revenue Benchmark - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Concentration Risk [Line Items]
Percentage of concentration risk	100.00%	100.00%
ARM Energy Management, LLC
Concentration Risk [Line Items]
Percentage of concentration risk	68.00%	0.00%
Texican Crude & Hydrocarbon, LLC
Concentration Risk [Line Items]
Percentage of concentration risk	19.00%	87.00%
Lucid Energy Delaware, LLC
Concentration Risk [Line Items]
Percentage of concentration risk	12.00%	10.00%
Other below 10%
Concentration Risk [Line Items]
Percentage of concentration risk	1.00%	3.00%

FAIR VALUE OF FINANCIAL INSTR_3

FAIR VALUE OF FINANCIAL INSTRUMENTS - Summary of recurring fair value measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total recurring fair value measurements	$ (6,869)	$ (841)
Oil and natural gas derivative swap contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements	(3,932)	(2,923)
Oil and natural gas derivative collar contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements	301	4,047
Net settlement provisions under ARM sales agreement
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements	3,238
Second Lien Term Loan conversion features
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements		(1,965)
Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total recurring fair value measurements	0	0
Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) | Oil and natural gas derivative swap contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements	0	0
Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) | Oil and natural gas derivative collar contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements	0	0
Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) | Net settlement provisions under ARM sales agreement
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements	0
Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) | Second Lien Term Loan conversion features
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements		0
Significant Other Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total recurring fair value measurements	(3,631)	1,124
Significant Other Observable Inputs (Level 2) | Oil and natural gas derivative swap contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements	(3,932)	(2,923)
Significant Other Observable Inputs (Level 2) | Oil and natural gas derivative collar contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements	301	4,047
Significant Other Observable Inputs (Level 2) | Net settlement provisions under ARM sales agreement
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements	0
Significant Other Observable Inputs (Level 2) | Second Lien Term Loan conversion features
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements		0
Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total recurring fair value measurements	(3,238)	(1,965)
Significant Unobservable Inputs (Level 3) | Oil and natural gas derivative swap contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements	0	0
Significant Unobservable Inputs (Level 3) | Oil and natural gas derivative collar contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements	0	0
Significant Unobservable Inputs (Level 3) | Net settlement provisions under ARM sales agreement
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements	$ 3,238
Significant Unobservable Inputs (Level 3) | Second Lien Term Loan conversion features
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements		$ (1,965)

FAIR VALUE OF FINANCIAL INSTR_4

FAIR VALUE OF FINANCIAL INSTRUMENTS - Narrative (Details) - Embedded Derivative Financial Instruments - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unrealized loss on derivatives	$ 0.3	$ 58.3
ARM Sales Agreement
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unrealized loss on derivatives	3.2
Derivative liability, impact of 10 percent favorable change in discount rate	$ (2.5)

FAIR VALUE OF FINANCIAL INSTR_5

FAIR VALUE OF FINANCIAL INSTRUMENTS - Reconciliation of changes in the fair value of the Company's Level 3 financial assets and liabilities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance, beginning	$ (1,965)	$ (72,937)
Transferred to equity		223
Fair value of the converted portion of the embedded derivatives associated with the Second Lien Term Loan	2,300	12,406
Change in fair value of embedded derivatives and derivative liabilities	(3,573)	58,343
Balance, ending	(3,238)	(1,965)
Warrant Liability
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance, beginning	0	(223)
Transferred to equity		223
Fair value of the converted portion of the embedded derivatives associated with the Second Lien Term Loan		0
Change in fair value of embedded derivatives and derivative liabilities		0
Balance, ending		0
Firm Takeaway and Pricing Agreement Net Settlement Provisions
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance, beginning	0
Fair value of the converted portion of the embedded derivatives associated with the Second Lien Term Loan	0
Change in fair value of embedded derivatives and derivative liabilities	(3,238)
Balance, ending	(3,238)	0
Second Lien Term Loan conversion features
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance, beginning	(1,965)	(72,714)
Transferred to equity		0
Fair value of the converted portion of the embedded derivatives associated with the Second Lien Term Loan	2,300	12,406
Change in fair value of embedded derivatives and derivative liabilities	(335)	58,343
Balance, ending	$ 0	$ (1,965)

DERIVATIVES - Summary of Compan

DERIVATIVES - Summary of Company's derivatives (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Derivative [Line Items]
Derivative assets - current	$ 427	$ 2,551
Derivative liabilities - current	(5,044)	(515)
Total derivative liabilities, net	(7,483)	(5,214)
Fair Value, Recurring
Derivative [Line Items]
Derivative assets - current	427	2,551
Derivative assets - non-current	187	1,822
Derivative liabilities - current	(5,044)	(515)
Derivative liabilities - non-current	(2,439)	(4,699)
Total derivative liabilities, net	(6,869)	(841)
Fair Value, Recurring | Embedded Derivative Financial Instruments
Derivative [Line Items]
Derivative liabilities - non-current		(2,000)
Fair Value, Recurring | Commodity Contract
Derivative [Line Items]
Derivative liabilities - non-current		$ (2,700)
ARM Sales Agreement | Fair Value, Recurring | Embedded Derivative Financial Instruments
Derivative [Line Items]
Derivative liabilities - current	(800)
Derivative liabilities - non-current	$ (2,400)

DERIVATIVES - Narrative (Detail

DERIVATIVES - Narrative (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Derivative [Line Items]
Derivative liability	$ 7,483	$ 5,214
Derivative liability, current	5,044	515
Second Lien Term Loan | Term Loan
Derivative [Line Items]
Derivative liability		$ 2,000
ARM Sales Agreement
Derivative [Line Items]
Derivative liability	3,200
Derivative liability, current	800
Derivative liability, noncurrent	$ 2,400

DERIVATIVES - Summary of Comp_2

DERIVATIVES - Summary of Company's derivative position (Details)	12 Months Ended
	Dec. 31, 2019bblMMBTU$ / MMBTU$ / bbl
Oil Swaps One
Derivative [Line Items]
Notional Volume (in barrels per day) | bbl	1,028
Weighted Average Price (in dollars per barrel) | $ / bbl	56.28
Oil Swaps Two
Derivative [Line Items]
Notional Volume (in barrels per day) | bbl	370
Weighted Average Price (in dollars per barrel) | $ / bbl	53.07
Basis Swaps
Derivative [Line Items]
Notional Volume (in barrels per day) | bbl	1,500
Weighted Average Price (in dollars per barrel) | $ / bbl	5.62
Three Way Collar - Floor Sold Price One
Derivative [Line Items]
Notional Volume (in barrels per day) | bbl	228
Weighted Average Price (in dollars per barrel) | $ / bbl	40
Three Way Collar - Floor Purchase Price One
Derivative [Line Items]
Notional Volume (in barrels per day) | bbl	228
Weighted Average Price (in dollars per barrel) | $ / bbl	50
Three Way Collar - Ceiling Sold Price One
Derivative [Line Items]
Notional Volume (in barrels per day) | bbl	228
Weighted Average Price (in dollars per barrel) | $ / bbl	59.60
Three Way Collar - Floor Sold Price Two
Derivative [Line Items]
Notional Volume (in barrels per day) | bbl	80
Weighted Average Price (in dollars per barrel) | $ / bbl	37.50
Three Way Collar - Floor Purchase Price Two
Derivative [Line Items]
Notional Volume (in barrels per day) | bbl	80
Weighted Average Price (in dollars per barrel) | $ / bbl	47.50
Three Way Collar - Ceiling Sold Price Two
Derivative [Line Items]
Notional Volume (in barrels per day) | bbl	80
Weighted Average Price (in dollars per barrel) | $ / bbl	59.30
Oil Collar - Floor Purchase Price One
Derivative [Line Items]
Notional Volume (in barrels per day) | bbl	512
Weighted Average Price (in dollars per barrel) | $ / bbl	49.50
Oil Collar - Ceiling Sold Price One
Derivative [Line Items]
Notional Volume (in barrels per day) | bbl	512
Weighted Average Price (in dollars per barrel) | $ / bbl	63.87
Oil Collar - Floor Purchase Price Two
Derivative [Line Items]
Notional Volume (in barrels per day) | bbl	742
Weighted Average Price (in dollars per barrel) | $ / bbl	50
Oil Callar - Ceiling Sold Price Two
Derivative [Line Items]
Notional Volume (in barrels per day) | bbl	742
Weighted Average Price (in dollars per barrel) | $ / bbl	59.70
Gas Swaps One
Derivative [Line Items]
Notional Volume (in barrels per day) | MMBTU	4,557
Weighted Average Price (in dollars per barrel) | $ / MMBTU	2.57
Gas Swaps Two
Derivative [Line Items]
Notional Volume (in barrels per day) | MMBTU	4,184
Weighted Average Price (in dollars per barrel) | $ / MMBTU	2.77
Three Way Collar - Floor Sold Price One
Derivative [Line Items]
Notional Volume (in barrels per day) | MMBTU	563
Weighted Average Price (in dollars per barrel) | $ / MMBTU	1.60
Three Way Collar - Floor Purchase Price One
Derivative [Line Items]
Notional Volume (in barrels per day) | MMBTU	563
Weighted Average Price (in dollars per barrel) | $ / MMBTU	2.10
Three Way Collar - Ceiling Sold Price One
Derivative [Line Items]
Notional Volume (in barrels per day) | MMBTU	563
Weighted Average Price (in dollars per barrel) | $ / MMBTU	3
Three Way Collar - Floor Sold Price Two
Derivative [Line Items]
Notional Volume (in barrels per day) | MMBTU	133
Weighted Average Price (in dollars per barrel) | $ / MMBTU	1.65
Three Way Collar - Floor Purchase Price Two
Derivative [Line Items]
Notional Volume (in barrels per day) | MMBTU	133
Weighted Average Price (in dollars per barrel) | $ / MMBTU	2.15
Three Way Collar - Ceiling Sold Price Two
Derivative [Line Items]
Notional Volume (in barrels per day) | MMBTU	133
Weighted Average Price (in dollars per barrel) | $ / MMBTU	3.05
Gas Collar - Floor Purchase Price One
Derivative [Line Items]
Notional Volume (in barrels per day) | MMBTU	2,748
Weighted Average Price (in dollars per barrel) | $ / MMBTU	2.55
Gas Collar - Ceiling Sold Price One
Derivative [Line Items]
Notional Volume (in barrels per day) | MMBTU	2,748
Weighted Average Price (in dollars per barrel) | $ / MMBTU	3.07
Gas Collar - Floor Purchase Price Two
Derivative [Line Items]
Notional Volume (in barrels per day) | MMBTU	4,464
Weighted Average Price (in dollars per barrel) | $ / MMBTU	2.20
Gas Collar - Ceiling Sold Price Two
Derivative [Line Items]
Notional Volume (in barrels per day) | MMBTU	4,464
Weighted Average Price (in dollars per barrel) | $ / MMBTU	2.97

DERIVATIVES - Summary of commod

DERIVATIVES - Summary of commodity derivatives (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Unrealized gain (loss) on unsettled derivatives	$ (5,575)	$ 1,977
Net settlements paid on derivative contracts	(3,214)	(2,742)
Net settlements receivable (payable) on derivative contracts	(196)	820
Net gain (loss) on commodity derivatives	$ (8,985)	$ 55

DERIVATIVES - Summary of gross

DERIVATIVES - Summary of gross fair values of derivative instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Derivatives, Fair Value [Line Items]
Gross amount of recognized offsetting derivative assets	$ 1,368	$ 5,976
Gross amounts of offsetting derivative assets in the condensed consolidated balance sheets	(754)	(1,603)
Net amounts of offsetting derivative assets presented in the condensed consolidated balance sheets	614	4,373
Gross amount of recognized offsetting derivative liabilities	(8,237)	(6,817)
Gross amounts of offsetting derivative liabilities in the condensed consolidated balance sheets	754	1,603
Total derivative liabilities, net	(7,483)	(5,214)
Current liabilities
Derivatives, Fair Value [Line Items]
Gross amount of recognized offsetting derivative liabilities	(4,827)	(2,086)
Gross amounts of offsetting derivative liabilities in the condensed consolidated balance sheets	582	1,571
Total derivative liabilities, net	(4,245)	(515)
Current assets
Derivatives, Fair Value [Line Items]
Gross amount of recognized offsetting derivative assets	1,009	4,122
Gross amounts of offsetting derivative assets in the condensed consolidated balance sheets	(582)	(1,571)
Net amounts of offsetting derivative assets presented in the condensed consolidated balance sheets	427	2,551
Long-term assets
Derivatives, Fair Value [Line Items]
Gross amount of recognized offsetting derivative assets	359	1,854
Gross amounts of offsetting derivative assets in the condensed consolidated balance sheets	(172)	(32)
Net amounts of offsetting derivative assets presented in the condensed consolidated balance sheets	187	1,822
Commodity Contract | Long-term liabilities
Derivatives, Fair Value [Line Items]
Gross amount of recognized offsetting derivative liabilities	(172)	(2,766)
Gross amounts of offsetting derivative liabilities in the condensed consolidated balance sheets	172	32
Total derivative liabilities, net	0	(2,734)
Embedded Derivative Financial Instruments | Current liabilities
Derivatives, Fair Value [Line Items]
Gross amount of recognized offsetting derivative liabilities	(799)
Gross amounts of offsetting derivative liabilities in the condensed consolidated balance sheets	0
Total derivative liabilities, net	(799)
Embedded Derivative Financial Instruments | Long-term liabilities
Derivatives, Fair Value [Line Items]
Gross amount of recognized offsetting derivative liabilities	(2,439)	(1,965)
Gross amounts of offsetting derivative liabilities in the condensed consolidated balance sheets	0	0
Total derivative liabilities, net	$ (2,439)	$ (1,965)

LEASES - Right of use assets an

LEASES - Right of use assets and lease liabilities (Details) - USD ($) $ in Thousands	3 Months Ended
	Dec. 31, 2019	Jun. 30, 2019	Sep. 30, 2019	Dec. 31, 2018
Lessee, Lease, Description [Line Items]
Right of use assets - long-term	$ 1,722			$ 0
Lease liabilities - current	412
Lease liabilities - long-term	1,323
Total lease liabilities	$ 1,735
Operating lease, liability, current, statement of financial position [Extensible List]	us-gaap:AccruedLiabilitiesCurrent
Operating lease, liability, noncurrent, statement of financial position [Extensible List]	llex:DerivativeLiabilityAndOtherLiabilitiesNoncurrent
Drilling Rig Lease
Lessee, Lease, Description [Line Items]
Right of use assets - long-term			$ 10,800
Total lease liabilities			$ 10,800
Write off of operating lease liability	$ 10,400	$ 5,400
Write off of operating lease, right-of-use asset	$ 10,400	$ 5,400

LEASES - Components of lease co

LEASES - Components of lease costs and other information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Lease, Cost [Abstract]
Fixed lease costs	$ 5,084
Short-term lease costs	1,096
Variable lease costs	575
Total lease costs	6,755
Lessee, Lease, Description [Line Items]
Lease cost	6,755
Cash paid for amounts included in the measurement of operating lease liabilities:
Operating cash flows from operating leases	222
Investing cash flows from operating leases	$ 4,768
Lease term and discount rate
Weighted-average remaining lease term (years)	4 years 5 months 12 days
Weighted-average discount rate	5.30%
General and administrative
Lease, Cost [Abstract]
Total lease costs	$ 474
Lessee, Lease, Description [Line Items]
Lease cost	474
Total lease costs expensed
Lease, Cost [Abstract]
Total lease costs	1,067
Lessee, Lease, Description [Line Items]
Lease cost	1,067
Oil sales | Production costs
Lease, Cost [Abstract]
Total lease costs	593
Lessee, Lease, Description [Line Items]
Lease cost	593
Oil and Gas Properties
Lease, Cost [Abstract]
Total lease costs	5,688
Lessee, Lease, Description [Line Items]
Lease cost	$ 5,688

LEASES - Minimum future payment

LEASES - Minimum future payments for long-term operating leases under scope of ASC 842 (Details) $ in Thousands	Dec. 31, 2019USD ($)
Lessee, Operating Lease, Liability, Payment, Due [Abstract]
2020	$ 477
2021	425
2022	353
2023	379
2024	315
After 2024	0
Less: the effects of discounting	(214)
Present value of lease liabilities	$ 1,735

LEASES - Minimum future payme_2

LEASES - Minimum future payments for long-term operating leases under scope of ASC 840 (Details) $ in Thousands	Dec. 31, 2018USD ($)
Leases [Abstract]
2019	$ 7,586
2020	66
2021	0
2022	0
2023	0
After 2023	0
Total lease commitment	$ 7,652

LONG-TERM DEBT - Summary of lon

LONG-TERM DEBT - Summary of long-term debt instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Oct. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Total long-term debt	$ 115,000		$ 157,804
Less: current portion	(115,000)		0
Total long-term debt, net of current portion	0		157,804
8.25% Second Lien Term Loan, due 2021, net of debt issuance costs and debt discount | Second Lien Term Loan
Debt Instrument [Line Items]
Total long-term debt	$ 0		$ 82,804
Debt instrument, interest rate, stated percentage	8.25%		8.25%
Revolving Credit Agreement, due October 2023 | Line of Credit
Debt Instrument [Line Items]
Total long-term debt	$ 115,000	$ 115,000	$ 75,000

LONG-TERM DEBT - Revolving cred

LONG-TERM DEBT - Revolving credit agreement (Details)

Jun. 05, 2020USD ($)

Apr. 21, 2020USD ($)

Apr. 14, 2020USD ($)

Mar. 30, 2020USD ($)

Feb. 28, 2020USD ($)

Feb. 24, 2020USD ($)

Nov. 27, 2019

Sep. 30, 2019USD ($)

May 06, 2019USD ($)day

Oct. 10, 2018USD ($)

Dec. 31, 2019USD ($)

Dec. 31, 2018USD ($)

Feb. 28, 2020USD ($)

Feb. 14, 2020installment

Feb. 06, 2020installment

Jan. 17, 2020USD ($)installment

Nov. 05, 2019

Oct. 31, 2019USD ($)

Jul. 31, 2019USD ($)

Jul. 26, 2019USD ($)

Mar. 05, 2019USD ($)

Mar. 04, 2019USD ($)

Debt Instrument [Line Items]

Long-term debt

$ 115,000,000

$ 157,804,000

Amortization of debt financing costs

$ 803,000

3,241,000

Ratio of total debt to EBITDAX (not more than)

400.00%

Ratio of current assets to current liabilities (not less than)

100.00%

Percentage of production required to be maintained (not less than)

75.00%

Minimum period of swap agreements maintained

24 months

Cash and cash equivalents

$ 3,753,000

21,137,000

Repayments of lines of credit

18,000,000

0

Revolving Credit Facility

Debt Instrument [Line Items]

Agreement term

5 years

Line of credit facility, maximum borrowing capacity

$ 500,000,000

Line of credit facility, borrowing base

$ 95,000,000

108,000,000

$ 115,000,000

$ 115,000,000

$ 125,000,000

$ 108,000,000

Line of credit facility, commitment fee percentage

0.50%

Ratio of current assets to current liabilities (not less than)

85.00%

100.00%

Percentage of production required to be maintained (not less than)

75.00%

Percentage of net cash proceeds from dispositions used to repay borrowings

100.00%

Covenant, borrowing base deficiency, repayment in full, period after redetermination

30 days

Covenant, borrowing base deficiency, monthly installment repayment period

4 months

6 months

Covenant, borrowing base deficiency, monthly installment repayment, period after redetermination

30 days

30 days

Letter of Credit

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

5,000,000

Line of Credit | Revolving Credit Facility

Debt Instrument [Line Items]

Long-term debt

115,000,000

75,000,000

$ 115,000,000

Amortization of debt financing costs

$ 800,000

2,200,000

Option to effect repayment, in full, period after redetermination

30 days

Option to effect repayment, monthly installments, period after redetermination

6 months

Ratio of total debt to EBITDAX (not more than)

300.00%

400.00%

Ratio of current assets to current liabilities (not less than)

100.00%

Basis spread

0.25%

Period of consecutive business days (at least) | day

5

Line of Credit | Minimum | Revolving Credit Facility

Debt Instrument [Line Items]

Cash and cash equivalents

$ 10,000,000

Other Current Assets | Line of Credit | Revolving Credit Facility

Debt Instrument [Line Items]

Unamortized debt issuance costs

$ 2,600,000

500,000

Other Noncurrent Assets | Line of Credit | Revolving Credit Facility

Debt Instrument [Line Items]

Unamortized debt issuance costs

$ 1,700,000

Subsequent Event

Debt Instrument [Line Items]

Repayments of lines of credit

$ 17,300,000

Subsequent Event | Revolving Credit Facility

Debt Instrument [Line Items]

Line of credit facility, borrowing base

$ 90,000,000

Borrowing base deficiency

$ 25,000,000

Covenant, borrowing base deficiency, number of equal monthly installments (in installments) | installment

2

4

Covenant, borrowing base deficiency, equal monthly installment, amount

$ 6,250,000

Covenant, borrowing base deficiency, number of subsequent monthly installments (in installments) | installment

2

2

Repayments of lines of credit

$ 1,500,000

$ 1,500,000

Extension term

45 days

Subsequent Event | Line of Credit | Revolving Credit Facility

Debt Instrument [Line Items]

Line of credit facility, borrowing base

$ 90,000,000

Borrowing base deficiency

$ 25,000,000

Installment payment

$ 7,750,000

$ 17,300,000

Forecast

Debt Instrument [Line Items]

Repayments of lines of credit

$ 7,800,000

Forecast | Line of Credit | Revolving Credit Facility

Debt Instrument [Line Items]

Borrowing base deficiency

7,800,000

Installment payment

$ 7,750,000

LONG-TERM DEBT - Second lien cr

LONG-TERM DEBT - Second lien credit agreement (Details)	Apr. 01, 2019	Mar. 05, 2019USD ($)seriesday$ / sharesshares	Oct. 10, 2018USD ($)shares	Apr. 26, 2017USD ($)daytranche$ / shares	Nov. 30, 2017USD ($)	Dec. 31, 2019USD ($)$ / sharesshares	Dec. 31, 2018USD ($)$ / sharesshares	Mar. 04, 2019$ / shares
Line of Credit Facility [Line Items]
Long-term debt						$ 115,000,000	$ 157,804,000
Gain on extinguishment of debt						$ 7,078,000
Second Lien Credit Agreement
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity				$ 125,000,000
Line of credit facility, number of tranches | tranche				2
Increase in borrowing capacity					$ 25,000,000
Additional borrowing capacity					$ 25,000,000
Debt instrument, interest rate, stated percentage								8.25%
Second Lien Term Loan
Line of Credit Facility [Line Items]
Debt instrument, convertible, threshold percentage of stock price trigger (at least)				150.00%
Second Lien Term Loan | Second Lien Credit Agreement
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity				$ 80,000,000
Delayed Draw Loans | Second Lien Credit Agreement
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity				$ 45,000,000
Conversion To Newly Issued Shares | Second Lien Term Loan
Line of Credit Facility [Line Items]
Conversion percentage of principal amount				70.00%
Conversion price (in dollars per share) | $ / shares				$ 5.50
Conversion To New Term Loan | Second Lien Term Loan
Line of Credit Facility [Line Items]
Conversion percentage of principal amount				30.00%
Minimum | Second Lien Term Loan
Line of Credit Facility [Line Items]
Threshold trading days | day				20
Maximum | Second Lien Term Loan
Line of Credit Facility [Line Items]
Threshold trading days | day				30
Private Placement
Line of Credit Facility [Line Items]
Mezzanine equity, stated value (in dollars per share) | $ / shares		$ 7
Varde Partners, Inc. | Private Placement
Line of Credit Facility [Line Items]
Mezzanine equity, shares issued (in shares) | shares		9,891,638	5,952,763
Number of new series of preferred stock | series		2
Amount canceled in exchange for equity issuance		$ 133,600,000
Mezzanine equity, new issues of stock		$ 18,600,000
Series D Preferred Stock
Line of Credit Facility [Line Items]
Mezzanine equity, shares issued (in shares) | shares						39,254	39,254
Redeemable preferred stock, dividend rate, percentage						8.25%	8.25%
Mezzanine equity, new issues of stock						$ 0
Mezzanine equity, stated value (in dollars per share) | $ / shares						$ 1,107	$ 1,021
Series D Preferred Stock | Private Placement | Maximum
Line of Credit Facility [Line Items]
Redeemable preferred stock, dividend rate, percentage	8.25%
Series D Preferred Stock | Varde Partners, Inc. | Private Placement
Line of Credit Facility [Line Items]
Mezzanine equity, shares issued (in shares) | shares			39,254
Redeemable preferred stock, dividend rate, percentage			8.25%
Series F Preferred Stock
Line of Credit Facility [Line Items]
Mezzanine equity, shares issued (in shares) | shares						55,000
Redeemable preferred stock, dividend rate, percentage						9.00%
Mezzanine equity, new issues of stock						$ 46,682,000
Mezzanine equity, stated value (in dollars per share) | $ / shares						$ 1,076
Series F Preferred Stock | Private Placement | Maximum
Line of Credit Facility [Line Items]
Redeemable preferred stock, dividend rate, percentage	9.00%
Series F Preferred Stock | Varde Partners, Inc. | Private Placement
Line of Credit Facility [Line Items]
Mezzanine equity, shares issued (in shares) | shares		55,000
Redeemable preferred stock, dividend rate, percentage		9.00%
Mezzanine equity, new issues of stock		$ 55,000,000
Series E Preferred Stock
Line of Credit Facility [Line Items]
Mezzanine equity, shares issued (in shares) | shares						60,000
Redeemable preferred stock, dividend rate, percentage						8.25%
Mezzanine equity, new issues of stock						$ 62,115,000
Mezzanine equity, stated value (in dollars per share) | $ / shares						$ 1,069
Series E Preferred Stock | Private Placement
Line of Credit Facility [Line Items]
Mezzanine equity, stated value (in dollars per share) | $ / shares		$ 1,000						$ 1.88
Series E Preferred Stock | Private Placement | Maximum
Line of Credit Facility [Line Items]
Redeemable preferred stock, dividend rate, percentage	8.25%
Series E Preferred Stock | Varde Partners, Inc. | Private Placement
Line of Credit Facility [Line Items]
Mezzanine equity, shares issued (in shares) | shares		60,000
Redeemable preferred stock, dividend rate, percentage		8.25%
Mezzanine equity, new issues of stock		$ 60,000,000
Second Lien Term Loan | 8.25% Second Lien Term Loan, due 2021, net of debt issuance costs and debt discount
Line of Credit Facility [Line Items]
Debt instrument, interest rate, stated percentage						8.25%	8.25%
Long-term debt						$ 0	$ 82,804,000
Second Lien Term Loan | 8.25% Second Lien Term Loan, due 2021, net of debt issuance costs and debt discount | Private Placement | Minimum
Line of Credit Facility [Line Items]
Threshold trading days | day		20
Second Lien Term Loan | 8.25% Second Lien Term Loan, due 2021, net of debt issuance costs and debt discount | Private Placement | Maximum
Line of Credit Facility [Line Items]
Threshold trading days | day		30
Second Lien Term Loan | 8.25% Second Lien Term Loan, due 2021, net of debt issuance costs and debt discount | Varde Partners, Inc.
Line of Credit Facility [Line Items]
Repayment of debt			$ 56,300,000
Long-term debt			$ 11,900,000
Additional Paid-In Capital
Line of Credit Facility [Line Items]
Gain on extinguishment of debt						$ 7,078,000

LONG-TERM DEBT - Summary of int

LONG-TERM DEBT - Summary of interest expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Debt Disclosure [Abstract]
Interest on debt	$ 6,488	$ 2,975
Net revenue payments on financing arrangement	888	0
Paid-in-kind interest on term loans	1,590	12,213
Amortization of debt financing costs	803	3,241
Amortization of discount on term loans	1,657	14,398
Total	$ 11,426	$ 32,827

LONG-TERM DEFERRED REVENUE LI_3

LONG-TERM DEFERRED REVENUE LIABILITIES AND OTHER LONG-TERM LIABILITIES - Schedule of Deferred Revenue Liabilities and Other Long-Term Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Long-term Purchase Commitment [Line Items]
Long-term deferred revenue liabilities	$ 36,920	$ 52,500
Other	0	13
Total long-term deferred revenue liabilities and other long-term liabilities	73,749	52,513
WLR
Long-term Purchase Commitment [Line Items]
Long-term deferred revenue liabilities	13,061	0
WLWI
Long-term Purchase Commitment [Line Items]
Long-term deferred revenue liabilities	$ 23,768	$ 0

LONG-TERM DEFERRED REVENUE LI_4

LONG-TERM DEFERRED REVENUE LIABILITIES AND OTHER LONG-TERM LIABILITIES - Narrative (Details) $ in Millions	Jul. 31, 2019USD ($)	Mar. 07, 2019USD ($)	Jul. 25, 2018USD ($)	May 21, 2018USD ($)	Jul. 31, 2018USD ($)wellbblmi	Dec. 31, 2019USD ($)	Mar. 11, 2019USD ($)bbl	Oct. 01, 2018USD ($)
Long-term Purchase Commitment [Line Items]
Deferred revenue				$ 35
Contract with customer, term				12 years
Salt Creek Midstream Water, LLC
Long-term Purchase Commitment [Line Items]
Number of miles of pipeline (in miles) | mi					14
Number of wells (in wells) | well					1
Upfront non-refundable payment		$ 11.7	$ 10
Total purchase price					$ 20
Prefunded drilling bonus			$ 5		$ 2.5		$ 2.5	$ 2.5
Crude oil takeaway, target number of barrels per day (in barrels per day) | bbl					40,000		40,000
Deferred revenue							$ 2.5
Winkler Lea Transactions
Long-term Purchase Commitment [Line Items]
Proceeds from sale of overriding royalty interests and non-operated working interests	$ 39
Net revenue payments on financing arrangement						$ 0.9

RELATED PARTY TRANSACTIONS - Su

RELATED PARTY TRANSACTIONS - Summary of related party transactions (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)well	Dec. 31, 2018USD ($)
Related Party Transaction [Line Items]
Total	$ (37,677)	$ 12,592
Varde Partners, Inc.
Related Party Transaction [Line Items]
Number of wells operated (in wells) | well	2
The Company acquired oil and natural gas interests from VPD, an affiliate of Värde	$ 0	10,705
Receivable balance outstanding for operating costs associated with VPD's producing wells	0	1,843
ImPetro Operating, LLC, a wholly-owned subsidiary of the Company is the operator for two of VPD's producing wells and VPD reimbursed the Company for operating charges	0	44
Payable to WLR for net proportionate share of production	(157)	0
WLR
Related Party Transaction [Line Items]
Payable to WLR for net proportionate share of production	(161)	0
WLWI
Related Party Transaction [Line Items]
Payable to WLR for net proportionate share of production	(526)
Asset disposition accounted for as a financing arrangement | Varde Partners, Inc.
Related Party Transaction [Line Items]
Total	$ (36,833)	$ 0

RELATED PARTY TRANSACTIONS - Na

RELATED PARTY TRANSACTIONS - Narrative (Details) $ in Millions	Mar. 05, 2019series	Dec. 31, 2019USD ($)property	Apr. 21, 2020USD ($)	Jul. 31, 2019agreement
Winkler Lea Transactions
Related Party Transaction [Line Items]
Number of agreements | agreement				2
WLR
Related Party Transaction [Line Items]
Purchase and sale agreement, proportionate share of production included in interest expense		$ 0.4
WLWI
Related Party Transaction [Line Items]
Purchase and sale agreement, proportionate share of production included in interest expense		$ 0.5
Purchase and sale agreement, number of producing properties (in properties) | property		0
Varde Partners, Inc. | Private Placement
Related Party Transaction [Line Items]
Number of new series of preferred stock | series	2
Subsequent Event | Revolving Credit Facility | Varde Partners, Inc. | Värde Investment Partners, L.P.
Related Party Transaction [Line Items]
Principal amount counterparty became lender to			$ 25.7

INCOME TAXES - Schedule of Comp

INCOME TAXES - Schedule of Components of Income Tax Provision (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
U.S. Federal:
Current	$ 0	$ 0
Deferred	(55,366)	(7,496)
State and local:
Current	0	0
Deferred	(4,220)	509
Deferred income tax provision (benefit)	(59,586)	(6,987)
Change in valuation allowance	59,586	6,987
Income tax provision	$ 0	$ 0

INCOME TAXES - Summary of defer

INCOME TAXES - Summary of deferred tax assets and liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Deferred tax assets:
Net operating loss carry-forward	$ 31,992	$ 27,568
Share based compensation	531	808
Abandonment obligation	761	541
Derivative instruments	1,526	0
Deferred revenue	15,863	11,630
Interest expense	4,540	3,804
Lease Liability	386
Property Basis	27,837
Accrued liabilities and other	144	85
Total deferred tax asset	83,580	44,436
Valuation allowance	(83,197)	(23,611)
Deferred tax asset, net of valuation allowance	383	20,825
Deferred tax liabilities:
Derivative instruments	0	249
Oil and natural gas properties and equipment	0	20,576
Right of use asset	383
Total deferred tax liability	383	20,825
Net deferred tax asset (liability)	$ 0	$ 0

INCOME TAXES - Summary of effec

INCOME TAXES - Summary of effective tax rate (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Effective federal tax rate	21.00%	21.00%
State tax rate, net of federal benefit	1.00%	2.00%
Change in fair value derivative liability	0.00%	296.00%
Debt discount amortization	0.00%	(73.00%)
Change in rate	0.00%	(6.00%)
Other permanent differences	0.00%	(6.00%)
NOL true-up - §382 limitation	0.00%	(6.00%)
Loss from early debt extinguishment	0.00%	(59.00%)
Other	0.00%	(1.00%)
Valuation allowance	(22.00%)	(169.00%)
Net	0.00%	0.00%

INCOME TAXES - Narrative (Detai

INCOME TAXES - Narrative (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Income Tax Contingency [Line Items]
Operating loss carryforwards	$ 142,200	$ 127,500
Operating loss carryforwards future expiration amount	69,900
Deferred tax assets, valuation allowance	83,197	$ 23,611
Section 382 In Penal Code
Income Tax Contingency [Line Items]
Operating loss carryforwards	$ 77,100

PREFERRED STOCK - Narrative (De

PREFERRED STOCK - Narrative (Details)	Apr. 26, 2021	Dec. 31, 2019$ / sharesshares	Dec. 26, 2019	Apr. 01, 2019	Mar. 05, 2019USD ($)daymember$ / sharesshares	Mar. 04, 2019$ / sharesshares	Oct. 10, 2018USD ($)$ / sharesshares	Jan. 30, 2018USD ($)$ / sharesshares	Dec. 31, 2019USD ($)$ / sharesshares	Dec. 31, 2018$ / sharesshares	Mar. 06, 2019USD ($)
Temporary Equity [Line Items]
Convertible debt | $											$ 0
Temporary equity change of control percentage of stated value					2.50%
Series C Preferred Stock
Temporary Equity [Line Items]
Issuance of preferred stock in extinguishment of debt (in shares)								100,000	0
Redeemable preferred stock, dividend rate, percentage			9.75%		9.75%			9.75%
Shares issued (in dollars per share) | $ / shares								$ 1,000
Mezzanine equity, new issues of stock | $								$ 100,000,000	$ 0
Series C-1 Preferred Stock
Temporary Equity [Line Items]
Redeemable preferred stock, dividend rate, percentage									9.75%	9.75%
Mezzanine equity, shares issued (in shares)		100,000							100,000	100,000
Temporary equity, stated value (in dollars per share) | $ / shares		$ 1,203							$ 1,203	$ 1,093
Series C-2 Preferred Stock
Temporary Equity [Line Items]
Redeemable preferred stock, dividend rate, percentage									9.75%	9.75%
Mezzanine equity, shares issued (in shares)		25,000							25,000	25,000
Temporary equity, stated value (in dollars per share) | $ / shares		$ 1,128							$ 1,128	$ 1,024
Series D Preferred Stock
Temporary Equity [Line Items]
Issuance of preferred stock in extinguishment of debt (in shares)									0
Redeemable preferred stock, dividend rate, percentage									8.25%	8.25%
Mezzanine equity, new issues of stock | $									$ 0
Mezzanine equity, shares issued (in shares)		39,254							39,254	39,254
Temporary equity, stated value (in dollars per share) | $ / shares		$ 1,107							$ 1,107	$ 1,021
Series E Preferred Stock
Temporary Equity [Line Items]
Issuance of preferred stock in extinguishment of debt (in shares)									60,000
Redeemable preferred stock, dividend rate, percentage									8.25%
Mezzanine equity, new issues of stock | $									$ 62,115,000
Mezzanine equity, shares issued (in shares)		60,000							60,000
Temporary equity, stated value (in dollars per share) | $ / shares		$ 1,069							$ 1,069
Series F Preferred Stock
Temporary Equity [Line Items]
Issuance of preferred stock in extinguishment of debt (in shares)									55,000
Redeemable preferred stock, dividend rate, percentage									9.00%
Mezzanine equity, new issues of stock | $									$ 46,682,000
Mezzanine equity, shares issued (in shares)		55,000							55,000
Temporary equity, stated value (in dollars per share) | $ / shares		$ 1,076							$ 1,076
Private Placement
Temporary Equity [Line Items]
Temporary equity, stated value (in dollars per share) | $ / shares					$ 7
Private Placement | Series C Preferred Stock
Temporary Equity [Line Items]
Percentage of redeemable temporary equity		130.00%			125.00%
Private Placement | Series C-1 Preferred Stock
Temporary Equity [Line Items]
Redeemable preferred stock, dividend rate, percentage							9.75%
Share price (in dollars per share) | $ / shares								$ 4.42
Private Placement | Series C-2 Preferred Stock
Temporary Equity [Line Items]
Share price (in dollars per share) | $ / shares							$ 4.41
Private Placement | Series D Preferred Stock
Temporary Equity [Line Items]
Percentage of redeemable temporary equity					117.50%
Private Placement | Series E Preferred Stock
Temporary Equity [Line Items]
Temporary equity, stated value (in dollars per share) | $ / shares					$ 1,000	$ 1.88
Conversion price per share (in dollars per share) | $ / shares					$ 2.50
Temporary equity, right to designate, number of board members (in members) | member					1
Percentage of outstanding stock, minimum					5.00%
Private Placement | Series F Preferred Stock
Temporary Equity [Line Items]
Percentage of redeemable temporary equity					115.00%
Temporary equity, right to designate, number of board members (in members) | member					1
Amount of outstanding shares required to vote | $					$ 13,800,000
Maximum | Private Placement | Series C Preferred Stock
Temporary Equity [Line Items]
Redeemable preferred stock, dividend rate, percentage				9.75%
Maximum | Private Placement | Series D Preferred Stock
Temporary Equity [Line Items]
Redeemable preferred stock, dividend rate, percentage				8.25%
Maximum | Private Placement | Series E Preferred Stock
Temporary Equity [Line Items]
Redeemable preferred stock, dividend rate, percentage				8.25%
Maximum | Private Placement | Series F Preferred Stock
Temporary Equity [Line Items]
Redeemable preferred stock, dividend rate, percentage				9.00%
Maximum | Forecast | Private Placement
Temporary Equity [Line Items]
Redeemable preferred stock, dividend rate, percentage	15.00%
Maximum | Forecast | Private Placement | Series E Preferred Stock
Temporary Equity [Line Items]
Redeemable preferred stock, dividend rate, percentage	9.25%
Maximum | Forecast | Private Placement | Series F Preferred Stock
Temporary Equity [Line Items]
Redeemable preferred stock, dividend rate, percentage	10.00%
Minimum | Forecast | Private Placement
Temporary Equity [Line Items]
Redeemable preferred stock, dividend rate, percentage	12.00%
Preferred Stock, Redemption, Period One | Private Placement | Series C Preferred Stock
Temporary Equity [Line Items]
Percentage of redeemable temporary equity					120.00%
Preferred Stock, Redemption, Period One | Private Placement | Series E Preferred Stock
Temporary Equity [Line Items]
Percentage of redeemable temporary equity					110.00%
Preferred Stock, Redemption, Period Two | Private Placement | Series C Preferred Stock
Temporary Equity [Line Items]
Percentage of redeemable temporary equity					125.00%
Preferred Stock, Redemption, Period Two | Private Placement | Series E Preferred Stock
Temporary Equity [Line Items]
Percentage of redeemable temporary equity					105.00%
Preferred Stock, Redemption, Period Three | Private Placement | Series C Preferred Stock
Temporary Equity [Line Items]
Percentage of redeemable temporary equity					130.00%
Preferred Stock, Redemption, Period Three | Private Placement | Series E Preferred Stock
Temporary Equity [Line Items]
Percentage of redeemable temporary equity					100.00%
Term Loan | Second Lien Term Loan | Maximum | Private Placement
Temporary Equity [Line Items]
Threshold trading days | day					30
Term Loan | Second Lien Term Loan | Minimum | Private Placement
Temporary Equity [Line Items]
Threshold trading days | day					20
Percentage of conversion price					150.00%
Varde Partners, Inc. | Private Placement
Temporary Equity [Line Items]
Mezzanine equity, new issues of stock | $					$ 18,600,000
Mezzanine equity, shares issued (in shares)					9,891,638		5,952,763
Varde Partners, Inc. | Private Placement | Series C Preferred Stock
Temporary Equity [Line Items]
Mezzanine equity, shares issued (in shares)							25,000
Varde Partners, Inc. | Private Placement | Series C-2 Preferred Stock
Temporary Equity [Line Items]
Redeemable preferred stock, dividend rate, percentage							9.75%
Stock, stated value (in dollars per share) | $ / shares							$ 1,000
Temporary equity, value, issued | $							$ 25,000,000
Varde Partners, Inc. | Private Placement | Series D Preferred Stock
Temporary Equity [Line Items]
Redeemable preferred stock, dividend rate, percentage							8.25%
Mezzanine equity, shares issued (in shares)							39,254
Varde Partners, Inc. | Private Placement | Series E Preferred Stock
Temporary Equity [Line Items]
Redeemable preferred stock, dividend rate, percentage					8.25%
Mezzanine equity, new issues of stock | $					$ 60,000,000
Mezzanine equity, shares issued (in shares)					60,000
Varde Partners, Inc. | Private Placement | Series F Preferred Stock
Temporary Equity [Line Items]
Redeemable preferred stock, dividend rate, percentage					9.00%
Mezzanine equity, new issues of stock | $					$ 55,000,000
Mezzanine equity, shares issued (in shares)					55,000
Varde Partners, Inc. | Private Placement | Series C and D Preferred Stock
Temporary Equity [Line Items]
Mezzanine equity, shares issued (in shares)					7,750,000
Conversion of stock, decrease (in shares)					24,000,000	53,500,000

PREFERRED STOCK - Summary of Pr

PREFERRED STOCK - Summary of Preferred Stock (Details) - USD ($) $ in Thousands	Jan. 30, 2018	Dec. 31, 2019
Series C Preferred Stock
Increase (Decrease) in Temporary Equity [Roll Forward]
Beginning balance (in shares)		125,000
Beginning balance		$ 132,296
Change in carrying value due to modification		$ (46,632)
Issuance of Preferred Stock in extinguishment of debt (in shares)	100,000	0
Issuance of Preferred Stock in extinguishment of debt	$ 100,000	$ 0
Paid-in-kind dividends		$ 13,639
Ending balance (in shares)		125,000
Ending balance		$ 99,303
Series D Preferred Stock
Increase (Decrease) in Temporary Equity [Roll Forward]
Beginning balance (in shares)		39,254
Beginning balance		$ 40,729
Change in carrying value due to modification		$ (15,056)
Issuance of Preferred Stock in extinguishment of debt (in shares)		0
Issuance of Preferred Stock in extinguishment of debt		$ 0
Paid-in-kind dividends		$ 3,409
Ending balance (in shares)		39,254
Ending balance		$ 29,082
Series E Preferred Stock
Increase (Decrease) in Temporary Equity [Roll Forward]
Beginning balance (in shares)		0
Beginning balance		$ 0
Change in carrying value due to modification		$ 0
Issuance of Preferred Stock in extinguishment of debt (in shares)		60,000
Issuance of Preferred Stock in extinguishment of debt		$ 62,115
Paid-in-kind dividends		$ 4,170
Ending balance (in shares)		60,000
Ending balance		$ 66,285
Series F Preferred Stock
Increase (Decrease) in Temporary Equity [Roll Forward]
Beginning balance (in shares)		0
Beginning balance		$ 0
Change in carrying value due to modification		$ 0
Issuance of Preferred Stock in extinguishment of debt (in shares)		55,000
Issuance of Preferred Stock in extinguishment of debt		$ 46,682
Paid-in-kind dividends		$ 4,179
Ending balance (in shares)		55,000
Ending balance		$ 50,861

STOCKHOLDERS' EQUITY - Narrativ

STOCKHOLDERS' EQUITY - Narrative (Details) - USD ($)	Mar. 05, 2019	Dec. 31, 2019	Dec. 31, 2018	Mar. 31, 2018
Class of Stock [Line Items]
Common stock, par value (in dollars per share)		$ 0.0001	$ 0.0001
Repurchase of common stock		$ 0	$ 997,000
Common Shares
Class of Stock [Line Items]
Common stock issued for conversion of debt (in shares)		17,641,638	5,952,763
Private Placement | Varde Partners, Inc.
Class of Stock [Line Items]
Common stock, par value (in dollars per share)	$ 0.0001
Private Placement | Varde Partners, Inc. | Common Shares
Class of Stock [Line Items]
Common stock issued for conversion of debt (in shares)	17,641,638
Share Repurchase Plan
Class of Stock [Line Items]
Stock repurchase program, authorized amount				$ 1,000,000
Treasury stock, shares, acquired (in shares)			253,598
Repurchase of common stock			$ 1,000,000

STOCKHOLDERS' EQUITY - Summary

STOCKHOLDERS' EQUITY - Summary of warrant activity (Details) - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Warrants
Outstanding ending balance (in shares)	2,754,062
Weighted- Average Exercise Price
Outstanding beginning balance (in dollars per share)	$ 3.83	$ 3.34
Exercised (in dollars per share)		2.21
Forfeited or expired (in dollars per share)	2.81	3.35
Outstanding ending balance (in dollars per share)	$ 4.67	$ 3.83
Warrant
Warrants
Outstanding beginning balance (in shares)	5,017,329	11,882,800
Exercised (in shares)		(3,975,957)
Forfeited or expired (in shares)	(2,263,267)	(2,889,514)
Outstanding ending balance (in shares)	2,754,062	5,017,329

STOCKHOLDERS' EQUITY - Schedule

STOCKHOLDERS' EQUITY - Schedule of outstanding warrants (Details)	Dec. 31, 2019shares
Equity [Abstract]
2020 (in shares)	174,642
2021 (in shares)	0
2022 (in shares)	2,579,420
Outstanding warrants (in shares)	2,754,062

SHARE BASED AND OTHER COMPENS_3

SHARE BASED AND OTHER COMPENSATION - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Apr. 20, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Exercised (in shares)	0
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	2 years
Omnibus Incentive Plan 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for future issuance (in shares)	5,400,000
Number of shares authorized (in shares)			18,000,000
Granted (in shares)	135,000	352,500
Exercised (in shares)	0	1,024,877
Weighted average exercise price (in dollars per share)	$ 1.47
Omnibus Incentive Plan 2016 | Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected term	10 years
Expected volatility rate	30.00%
Expected dividends	$ 0
Risk free interest rate	2.67%
Executive Officer
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)		2,600,000
Maximum | Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expiration period	10 years

SHARE BASED AND OTHER COMPENS_4

SHARE BASED AND OTHER COMPENSATION - Summary of share-based compensation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share based compensation expensed	$ 6,506	$ 9,000
Unrecognized share-based compensation costs	1,328	3,988
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share based compensation expensed	317	2,158
Unrecognized share-based compensation costs	$ 100	$ 487
Weighted average amortization period remaining (in years)	1 year 6 months 18 days	11 days
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share based compensation expensed	$ 6,189	$ 6,842
Unrecognized share-based compensation costs	$ 1,228	$ 3,501
Weighted average amortization period remaining (in years)	1 year 18 days	6 months

SHARE BASED AND OTHER COMPENS_5

SHARE BASED AND OTHER COMPENSATION - Summary of restricted stock grant activity (Details) - Restricted Stock - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Number of Shares
Outstanding beginning balance (in shares)	953,584	2,475,266
Granted (in shares)	3,684,372	1,194,944
Vested and issued (in shares)	(2,341,269)	(1,436,146)
Forfeited or canceled (in shares)	(894,512)	(1,280,480)
Outstanding ending balance (in shares)	1,402,175	953,584
Weighted Average Grant Date Price
Outstanding beginning balance (in dollars per share)	$ 4.85	$ 4.22
Granted (in dollars per share)	1.46	4.59
Vested and issued (in dollars per share)	2.39	2.38
Forfeited or canceled (in dollars per share)	2.94	4.44
Outstanding ending balance (in dollars per share)	$ 1.26	$ 4.85

SHARE BASED AND OTHER COMPENS_6

SHARE BASED AND OTHER COMPENSATION - Summary of stock option activity (Details) - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Number of Options
Exercised (in shares)	0
Omnibus Incentive Plan 2016
Number of Options
Outstanding beginning balance (in shares)	5,031,578	7,305,000
Granted (in shares)	135,000	352,500
Exercised (in shares)	0	(1,024,877)
Forfeited or canceled (in shares)	(1,578,228)	(1,601,045)
Outstanding ending balance (in shares)	3,588,350	5,031,578	7,305,000
Weighted Average Exercise Price
Outstanding beginning (in dollars per share)	$ 3.81	$ 3.74
Granted (in dollars per share)	2.17	4.07
Exercised (in dollars per share)	0	2.67
Forfeited or canceled (in dollars per share)	3.14	4.20
Outstanding ending (in dollars per share)	$ 4.05	$ 3.81	$ 3.74
Stock Options Outstanding and Exercisable
Number of options vested/exercisable (in shares)	4,125,842	5,035,317	3,534,484
Weighted average remaining contractual life (Years)	7 years 2 months 12 days	7 years 10 months 24 days	8 years 10 months 24 days

INCOME (LOSS) PER COMMON SHAR_2

INCOME (LOSS) PER COMMON SHARE - Summary of computation of basic and diluted net loss per share (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Earnings Per Share [Abstract]
Net loss	$ (272,121)	$ (4,143)
Dividends on preferred stock	(25,397)	(10,687)
Unallocated net loss	(297,518)	(14,830)
Numerator for basic loss per share:
Net loss attributable to common stockholders	$ (297,518)	$ (14,830)
Denominator for basic loss per share:
Basic weighted average common shares outstanding (in shares)	87,912,362	62,854,214
Net loss per share:
Basic attributable to common stockholders (in dollars per share)	$ (3.38)	$ (0.24)
Numerator for diluted loss per share:
Net loss attributable to common stockholders	$ (297,518)	$ (14,830)
Add: interest expense on convertible Second Lien Term Loan	0	13,429
Less: gain on fair value change of embedded derivatives associated with Second Lien Term Loan	0	(35,471)
Net loss attributable to common stockholders	$ (297,518)	$ (36,872)
Denominator for diluted net loss per share:
Basic weighted average common shares outstanding (in shares)	87,912,362	62,854,214
Dilution effect of if-converted Second Lien Loans (in shares)	0	15,597,127
Diluted weighted average common shares outstanding (in shares)	87,912,362	78,451,341
Common shares (diluted) (in dollars per share)	$ (3.38)	$ (0.47)

INCOME (LOSS) PER COMMON SHAR_3

INCOME (LOSS) PER COMMON SHARE - Summary of antidilutive securities excluded from computation (Details) - shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)	32,010,283	44,888,193
Series C Preferred Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)	0	26,295,616
Series D Preferred Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)	0	8,543,670
Series E Preferred Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)	25,667,871	0
Stock Options
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)	3,588,350	5,031,578
Stock Purchase Warrants
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)	2,754,062	5,017,329
Conversion of term loans
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)	0	0

SUPPLEMENTAL NON-CASH TRANSAC_3

SUPPLEMENTAL NON-CASH TRANSACTIONS - Summary of supplemental disclosure of cash flow information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Non-cash investing and financing activities excluded from the statement of cash flows:
Issued shares of common stock and preferred stock upon extinguishment of debt and modification of Series C Preferred Stock and Series D Preferred Stock	$ 141,787	$ 64,504
Common stock issued for acquisition of oil and natural gas properties	0	24,778
Cashless exercise of warrants	0	359
Deferred revenue realized upon purchase option exercise	16,700	0
Right of use assets obtained in exchange for operating lease obligations	7,500	0
Change in capital expenditures for drilling costs in accrued liabilities	2,010	7,850
Accrued cumulative paid in kind dividends on preferred stock	25,397	10,687
Change in asset retirement obligations	546	1,495
Reduction of fair value for converted embedded derivatives	0	12,406
Transfer of warrant derivative instruments to equity	$ 0	$ 223

SEGMENT INFORMATION - Narrative

SEGMENT INFORMATION - Narrative (Details)	12 Months Ended
	Dec. 31, 2019segment
Segment Reporting [Abstract]
Number of reportable segments	1

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - Narrative (Details) - USD ($) $ in Millions	Mar. 11, 2019	Aug. 02, 2018	Apr. 30, 2020
Salt Creek Midstream, LLC
Long-term Purchase Commitment [Line Items]
Agreement period		5 years
ARM Energy Management, LLC
Long-term Purchase Commitment [Line Items]
Agreement period	5 years
Subsequent Event | Statutory Mechanic's And Materialman’s Liens
Long-term Purchase Commitment [Line Items]
Other commitment			$ 9

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES - Schedule of required daily production (Details) - ARM Energy Management, LLC	Dec. 31, 2019bbl
March 2019 - June 2019
Long-term Purchase Commitment [Line Items]
Crude oil takeaway, target number of barrels per day (in barrels per day)	5,000
July 2019 - December 2019
Long-term Purchase Commitment [Line Items]
Crude oil takeaway, target number of barrels per day (in barrels per day)	4,000
January 2020 - June 2020
Long-term Purchase Commitment [Line Items]
Crude oil takeaway, target number of barrels per day (in barrels per day)	5,000
July 2020 - June 2021
Long-term Purchase Commitment [Line Items]
Crude oil takeaway, target number of barrels per day (in barrels per day)	6,000
July 2021 - December 2024
Long-term Purchase Commitment [Line Items]
Crude oil takeaway, target number of barrels per day (in barrels per day)	7,500

SUBSEQUENT EVENTS - Narrative (

SUBSEQUENT EVENTS - Narrative (Details) - COVID-19 - well	1 Months Ended	2 Months Ended
	Apr. 30, 2020	Jun. 30, 2020
Subsequent Event
Subsequent Event [Line Items]
Number of wells shut-in	12
Forecast
Subsequent Event [Line Items]
Number of wells shut-in		19

SUPPLEMENTARY INFORMATION ON _3

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT - Costs Incurred for Oil and Natural Gas Producing Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Acquisition costs:
Unproved properties	$ 1,644	$ 93,926
Proved properties	0	22,356
Exploration costs	40,284	89,351
Development costs	51,198	78,103
Total	$ 93,126	$ 283,736

SUPPLEMENTARY INFORMATION ON _4

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT - Results of Operations for Oil and Natural Gas Producing Activities (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Supplemental Oil And Gas Reserve Information [Abstract]
Revenues	$ 66,063,000	$ 70,216,000
Production costs	(16,127,000)	(13,843,000)
Production taxes	(3,302,000)	(3,709,000)
Accretion of asset retirement obligation	(433,000)	(85,000)
Depletion, depreciation and amortization	(33,071,000)	(25,159,000)
Full cost ceiling impairment	(228,324,000)	0
Total	$ (215,194,000)	$ 27,420,000

SUPPLEMENTARY INFORMATION ON _5

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT - Reserve Quantity Information (Details)	12 Months Ended
	Dec. 31, 2019bblMBbls	Dec. 31, 2019bblMBbls	Dec. 31, 2018bblMBbls	Dec. 31, 2017bblMBbls
Oil
Reserve Quantities [Line Items]
Beginning balance	21,205,036		7,171,339
Extensions and discoveries	856,838	1,500,000	15,881,727
Purchase of reserves			1,883,047
Revisions of previous estimates	(15,596,115)	29,800,000	(2,641,353)
Production	(1,130,855)	(21,500,000)	(1,089,724)
Ending balance	5,334,904		21,205,036
Proved Developed Reserves	5,334,904	5,334,904	6,278,036	2,531,397
Proved Undeveloped Reserves	0	0	14,927,000	4,639,942
Natural Gas
Reserve Quantities [Line Items]
Beginning balance | MBbls		78,749,613	16,059,926
Extensions and discoveries | MBbls		2,477,061	38,957,588
Purchase of reserves | MBbls			8,897,115
Revisions of previous estimates | MBbls		(48,718,235)	17,690,723
Production | MBbls		(3,063,927)	(2,855,739)
Ending balance | MBbls		29,444,512	78,749,613
Proved Developed Reserves | MBbls	29,444,512	29,444,512	27,046,195	6,594,446
Proved Undeveloped Reserves | MBbls	0	0	51,703,418	9,465,480
Natural Gas Liquids
Reserve Quantities [Line Items]
Beginning balance	8,376,551		1,604,570
Extensions and discoveries	190,203		4,565,994
Purchase of reserves			682,964
Revisions of previous estimates	(6,067,700)		1,769,448
Production	(220,832)		(246,425)
Ending balance	2,278,222		8,376,551
Proved Developed Reserves	2,278,222	2,278,222	2,653,908	644,102
Proved Undeveloped Reserves	0	0	5,722,643	960,468

SUPPLEMENTARY INFORMATION ON _6

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT - Narrative (Details) - Oil MBbls in Millions	12 Months Ended
	Dec. 31, 2019bbl	Dec. 31, 2019MBbls	Dec. 31, 2018bbl
Reserve Quantities [Line Items]
Extensions and discoveries	856,838	1.5	15,881,727
Revisions of previous estimates	(15,596,115)	29.8	(2,641,353)
Sale of reserves		8.3
Production	1,130,855	21.5	1,089,724

SUPPLEMENTARY INFORMATION ON _7

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT - Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Supplemental Oil And Gas Reserve Information [Abstract]
Future cash inflows	$ 358,127	$ 1,500,263
Future production costs	(176,498)	(414,117)
Future development costs	(7,284)	(346,225)
Future income tax expense	0	62,842
Future income tax expense	174,345	677,079
10% discount to reflect timing of cash flows	(54,171)	(384,345)
Total	$ 120,174	$ 292,734	$ 68,812

SUPPLEMENTARY INFORMATION ON _8

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT - Changes in Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward]
Balance at beginning of period	$ 292,734	$ 68,812
Net changes in prices and production costs	(275,539)	24,261
Sales of oil and natural gas produced during the year, net	(42,442)	(49,271)
Changes in estimated future development costs	272,579	(39,938)
Net change due to extensions and discoveries	18,044	161,785
Net change due to purchases of minerals in place	0	55,278
Previously estimated development costs incurred during the year	36,298	68,349
Net changes due to revision of previous quantity estimates	(255,125)	28,350
Accretion of discount	29,273	6,881
Other - unspecified (4)	9,327	3,252
Net change in income taxes	35,025	(35,025)
Balance at end of period	$ 120,174	292,734
Percentage decrease in oil and natural gas prices	19.00%
Percentage increase in production costs	45.00%
Estimated future development costs		$ 329,500