Lilis Energy (LLEX) 10-Q 9 Aug 18 2018 Q2 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	6 Months Ended
	Jun. 30, 2018	Aug. 07, 2018
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q2
Entity Registrant Name	LILIS ENERGY, INC.
Entity Central Index Key	1,437,557
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Trading Symbol	LLEX
Entity Common Stock, Shares Outstanding		64,247,893

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 27,398	$ 17,462
Accounts receivables, net of allowance of $25 and $39, respectively	17,961	7,426
Derivative instruments	1,775	0
Prepaid expenses and other current assets	867	584
Total current assets	48,001	25,472
Oil and natural gas properties, full cost method of accounting
Unproved	168,359	101,771
Proved	251,928	141,717
Total oil and natural gas properties	420,287	243,488
Less: accumulated depreciation, depletion, amortization and impairment	(83,505)	(73,183)
Total oil and natural gas properties, net	336,782	170,305
Other assets	540	167
Total assets	385,323	195,944
Current liabilities:
Accounts payable	14,284	10,488
Accrued liabilities	14,088	7,634
Revenue payable	14,239	6,460
Dividends payable	4,117	0
Derivative instruments	2,987	853
Total current liabilities	49,715	25,435
Asset retirement obligations	1,099	726
Long-term debt, less current maturities	158,548	127,794
Derivative instruments	66,710	72,937
Long-term deferred revenue	34,650	0
Total liabilities	310,722	226,892
Commitments and contingencies
Stockholders’ deficit:
Series C convertible preferred stock, $0.0001 par value; stated value of $1,000; 100,000 shares authorized, 100,000 issued and outstanding with a liquidation preference of $124,923 at June 30, 2018	97,506	0
Common stock, $0.0001 par value per share; 150,000,000 shares authorized, 64,045,923 and 53,368,331 shares issued and outstanding as of June 30, 2018 and December 31, 2017, respectively, of which 253,598 shares are being held as treasury stock as of June 30, 2018	6	5
Additional paid-in capital	300,336	272,335
Accumulated deficit	(322,250)	(303,288)
Treasury stock (253,598 shares at cost)	(997)	0
Total stockholders’ deficit	(22,905)	(30,948)
Total liabilities and stockholders’ deficit	$ 385,323	$ 195,944

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets [Parenthetical] - USD ($)	Jun. 30, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Allowance related to accounts receivable	$ 25,000	$ 39,000
Series C convertible preferred stock, par value (in dollars per share)	$ 0.0001	$ 0.0001
Series C convertible preferred stock, stated value	$ 1,000	$ 1,000
Series C convertible preferred stock, shares authorized	100,000	100,000
Series C convertible preferred stock, shares issued	100,000	100,000
Series C convertible preferred stock, shares outstanding	100,000	100,000
Series C convertible preferred stock, liquidation preference	$ 124,923
Common stock, par value (in dollars per share)	$ 0.0001	$ 0.0001
Common stock, shares authorized	150,000,000	150,000,000
Common stock, shares issued	64,045,923	53,368,331
Common stock, shares outstanding	64,045,923	53,368,331
Treasury stock, shares	253,598

Condensed Consolidated Statemen

Condensed Consolidated Statements of Operations (Unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Revenues:
Revenues	$ 17,483	$ 5,305	$ 31,878	$ 8,387
Operating expenses:
Production taxes	1,135	278	2,158	420
General and administrative	7,380	16,169	17,844	25,329
Depreciation, depletion, amortization and accretion	5,759	1,358	10,400	2,504
Total operating expenses	17,816	19,240	37,496	30,617
Operating loss	(333)	(13,935)	(5,618)	(22,230)
Other income (expense):
Other income (expense)	0	(141)	1	(133)
Loss from commodity derivatives	(2,802)	0	(4,572)	0
Fair value change in other derivative liabilities	(19,501)	(2,418)	8,887	(2,114)
Interest expense	(8,572)	(6,654)	(17,660)	(7,427)
Total other expense	(30,875)	(9,213)	(13,344)	(9,674)
Net loss before income taxes	(31,208)	(23,148)	(18,962)	(31,904)
Income tax expense	0	0	0	0
Net loss	(31,208)	(23,148)	(18,962)	(31,904)
Less: dividends on redeemable 6% preferred stock	0	(92)	0	(122)
Less: dividends and deemed dividends on Series B convertible preferred stock	0	(4,422)	0	(4,635)
Less: dividends on Series C convertible preferred stock	(2,465)	0	(4,117)	0
Net loss attributable to common stockholders	$ (33,673)	$ (27,662)	$ (23,079)	$ (36,661)
Net loss per common share - basic and diluted (in dollars per share)	$ (0.53)	$ (0.62)	$ (0.40)	$ (1.07)
Weighted average common shares outstanding - basic and diluted (in shares)	64,098,309	44,332,270	57,801,098	34,282,784
Oil and Gas [Member]
Revenues:
Revenues	$ 14,254	$ 4,167	$ 26,843	$ 6,662
Operating expenses:
Costs of goods and services sold	2,670	1,097	5,760	1,927
Natural Gas [Member]
Revenues:
Revenues	1,144	538	2,034	1,039
Natural Gas Gathering Transportation Marketing And Processing [Member]
Operating expenses:
Costs of goods and services sold	872	338	1,334	437
Natural Gas Liquids [Member]
Revenues:
Revenues	$ 2,085	$ 600	$ 3,001	$ 686

Condensed Consolidated Stateme5

Condensed Consolidated Statements of Operations (Unaudited) [Parenthetical]	6 Months Ended
	Jun. 30, 2017
Income Statement [Abstract]
Percentage of redeemable preferred stock	6.00%

Condensed Consolidated Stateme6

Condensed Consolidated Statements of Changes in Stockholders’ Deficit (Unaudited) - 6 months ended Jun. 30, 2018 - USD ($) $ in Thousands	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Treasury Stock [Member]	Accumulated Deficit [Member]
Beginning Balance at Dec. 31, 2017	$ (30,948)	$ 5	$ 272,335	$ 0	$ (303,288)
Beginning Balance (in shares) at Dec. 31, 2017		53,368,331		0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock based compensation	5,554		5,554
Common stock issued for restricted stock	0		0
Common stock for restricted stock and stock options (in shares)		467,860
Common stock forfeited for taxes withheld on stock awards	(509)		(509)
Common stock forfeited for taxes withheld on stock awards (in shares)		(134,235)
Common stock for acquisition of oil and gas properties	24,778	$ 1	24,777
Common stock for acquisition of oil and gas properties (in shares)		6,940,722
Exercise of warrants	1,051		1,051
Exercise of warrants (in shares)		2,848,440
Exercise of stock options	1,022		1,022
Exercise of stock options (in shares)		554,805
Reclassification of warrant derivative liabilities	223		223
Purchase of treasury stock	(997)		0	$ (997)
Purchase of treasury stock (in shares)				(253,598)
Dividends on Series C convertible preferred stock	(4,117)		(4,117)
Net loss	(18,962)				(18,962)
Ending Balance at Jun. 30, 2018	$ (22,905)	$ 6	$ 300,336	$ (997)	$ (322,250)
Ending Balance (in shares) at Jun. 30, 2018		64,045,923		253,598

Condensed Consolidated Stateme7

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($)	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Cash flows from operating activities:
Net loss	$ (18,962,000)	$ (31,904,000)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Stock based compensation	5,554,000	9,386,000
Bad debt expense	(14,000)	0
Amortization of debt issuance cost and debt discount	8,685,000	5,210,000
Payable in-kind interest	6,437,000	1,341,000
Loss from commodity derivatives, net	4,572,000	2,072,000
Net cash settlement paid for commodity derivative contracts	(1,710,000)	0
Gain in fair value of debt conversion and warrant derivatives	(8,887,000)	1,000
Loss in fair value of conditionally redeemable 6% preferred stock	0	41,000
Depreciation, depletion, amortization and accretion of asset retirement obligation	10,400,000	2,504,000
Proceeds for options to provide future gas midstream services, net of transaction costs	34,650,000	0
Changes in operating assets and liabilities:
Accounts receivable	(10,521,000)	(1,756,000)
Prepaid expenses and other assets	(436,000)	(479,000)
Accounts payable and accrued liabilities	12,442,000	6,170,000
Net cash provided by (used in) operating activities	42,210,000	(7,414,000)
Cash flows from investing activities:
Net proceeds from sale of DJ Basin properties	0	1,082,000
Acquisition of oil and natural gas properties	(69,820,000)	0
Capital expenditures	(76,160,000)	(40,925,000)
Net cash used in investing activities	(145,980,000)	(39,843,000)
Cash flows from financing activities:
Proceeds from issuance of Series C Preferred Stock	100,000,000	0
Proceeds from private placement	0	20,000,000
Proceeds from exercise of accordion features of 2016 Term Loans	0	6,706,000
Proceeds from Bridge Loan and Second Lien Term Loans	0	94,700,000
Proceeds from issuance of Riverstone Term Loans	50,000,000	0
Debt and equity issuance costs	(5,040,000)	(1,600,000)
Repayment of debt	(31,821,000)	(40,385,000)
Repurchase of common stock	(997,000)	0
Proceeds from exercise of warrants and stock options	2,073,000	392,000
Payment for tax withholding on stock-based compensation	(509,000)	(1,555,000)
Net cash provided by financing activities	113,706,000	78,258,000
Net increase in cash, cash equivalents and restricted cash	9,936,000	31,001,000
Cash, cash equivalents and restricted cash at beginning of period	17,462,000	11,738,000
Cash, cash equivalents and restricted cash at end of period	27,398,000	42,739,000
Supplemental disclosure:
Cash paid for interest	$ 2,538,000	$ 1,318,000

Condensed Consolidated Stateme8

Condensed Consolidated Statements of Cash Flows (Unaudited) Condensed Consolidated Statements of Cash Flows (Unaudited) [Parenthetical]	6 Months Ended
	Jun. 30, 2017
Statement of Cash Flows [Abstract]
Percentage of redeemable preferred stock	6.00%

ORGANIZATION

ORGANIZATION	6 Months Ended
	Jun. 30, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
ORGANIZATION	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.

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND ESTIMATES	6 Months Ended
	Jun. 30, 2018
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND ESTIMATES	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND ESTIMATES Principles of Consolidation and Presentation The condensed consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries which includes Brushy Resources, Inc. ("Brushy Resources"), 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. The unaudited condensed consolidated financial statements included herein reflect all adjustments (consisting only of normal, recurring adjustments) which are, in our opinion, necessary for a fair presentation of the information as of and for the periods presented. These unaudited condensed consolidated interim financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and the instructions to Quarterly Report on Form 10–Q and Article 10 of Regulation S–X. Accordingly, they do not include all disclosures required under GAAP for complete consolidated financial statements. These unaudited condensed consolidated financial statements should be read in conjunction with our annual report on Form 10–K for the twelve months ended December 31, 2017, as filed with the Securities and Exchange Commission on March 9, 2018, (the “2017 Annual Report on Form 10-K”). Use of Estimates The accompanying condensed consolidated financial statements are prepared in conformity with generally accepted accounting principles in the United States (“U.S. 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, inducement transactions and common stock; and the allocation of general administrative expenses. Actual results could differ significantly from these estimates. Reclassifications Certain reclassifications have been made to the prior period financial statements to conform to the current period presentation. These reclassifications have no effect on the Company’s previously reported results of operations. The following reclassifications have been made to the three and six months ended June 30, 2017 : (i) the income from operator’s overhead recovery of approximately $0.12 million and $0.27 million , respectively, have been reclassified from revenue to operating expense as an offset against general and administrative expenses in the condensed consolidated statement of operations; and (ii) $0.6 million of the escrow on a drilling rig has been reclassified from investing activities to cash, cash equivalents and restricted cash in the condensed consolidated statement of cash flows as required with the adoption of ASU No. 2016–18, “Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force), see Recently Adopted Accounting Standards. Recently Adopted Accounting Standards On January 1, 2018, the Company adopted the new accounting standard, Accounting Standards Codification, ASC 606 , Revenue from Contracts with Customers and all the related amendments (the “New Revenue Standard”) using the modified retrospective method. In accordance with the modified retrospective method, comparative information is not restated and continues to be reported under the accounting standards in effect for those periods. The cumulative effect of initially adopting the New Revenue Standard, if any, is recorded as an adjustment to the opening balance of retained earnings. The Company’s revenues from customers are derived from production and sales of crude oil, natural gas and natural gas liquids and recognized when control is transferred to the customer. As operator, the Company may market production on behalf of joint interest partners and various royalty owners. Under the terms of our joint operating agreements, the Company does not take control of the production attributable to our joint interest partners and the various royalty owners and consequently, the Company recognizes revenues only for its share of the production. In accordance with the New Revenue Standard requirements, the impact of adoption on our condensed consolidated statements of operations and condensed consolidated balance sheets was as follows: For the three months ended June 30, 2018 As Reported Balances without Adoption of ASC 606 Increase (Decrease) Condensed Consolidated Statements of Operations: Revenues $ 17,483 $ 17,498 $ (15 ) Operating expenses $ (872 ) $ (887 ) $ (15 ) For the six months ended June 30, 2018 Condensed Consolidated Statements of Operations: Revenues $ 31,878 $ 31,943 $ (65 ) Operating expenses $ (1,334 ) $ (1,399 ) $ (65 ) As of June 30, 2018 Condensed Consolidated Balance Sheets: Accounts receivable $ 8,378 $ 8,443 $ (65 ) Accrued liabilities $ (394 ) $ (459 ) $ (65 ) As shown in this comparison table, there is no impact on the net loss from the New Revenue Standard adoption and, therefore, no adjustment to the opening balance of accumulated deficit. Prior to the adoption of the New Revenue Standard, the revenue line included the value of our natural gas gatherer’s contractual volume retainage fee, with an offsetting cost included in the gathering, processing and marketing costs line. In accordance with the New Revenue Standard, the Company will only recognize revenues for its share of the production, resulting in the removal of the retainage fee approximating $15,000 and $65,000 from both revenues and operating expenses during the three and six months ended June 30, 2018 , respectively. On July 13, 2017, the Financial Accounting Standards Board (“FASB”) issued a two-part ASU 2017-11, (Part I) Accounting for Certain Financial Instruments with Down Round Features, (Part II) Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Redeemable Noncontrolling Interests with a Scope Exception (ASU 2017-11) . Part I of ASU 2017-11 simplifies the accounting for certain financial instruments with down round features by requiring companies to disregard the down round feature when assessing whether the instrument is indexed to its own stock, for purposes of determining liability or equity classification. Companies that provide earnings per share (EPS) data will adjust their basic EPS calculation for the effect of the feature when triggered (that is, when the exercise price of the related equity-linked financial instrument is adjusted downward because of the down round feature) and will also recognize the effect of the trigger within equity. Part II of ASU 2017-11 is not applicable to the Company since it addresses concerns relating to an indefinite deferral available to private companies with mandatorily redeemable financial instruments and certain noncontrolling interests. The provisions of ASU 2017-11 related to down rounds are effective for public business entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. Early adoption is permitted for all organizations. The Company elected to adopt ASU 2017-11 on January 1, 2018. The Company’s SOS Warrant Liability (as described in Note 6) was accounted for as a derivative instrument solely because of its down round feature. Any outstanding SOS Warrants as of the date of adoption were reclassified to equity and the Company will no longer recognize any gain or loss based on the fair value of the SOS Warrants. No other derivatives instruments outstanding as of January 1, 2018 were affected by the adoption of ASU 2017-11. On January 5, 2017, the FASB issued ASU 2017-01 B usiness Combinations (Topic 805): Clarifying the Definition of a Business (ASU 2017-01) , which clarifies the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. The standard introduces a screen for determining when assets acquired are not a business and clarifies that a business must include, at a minimum, an input and a substantive process that contribute to an output to be considered a business. This standard is effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period. The Company adopted ASU 2017-01 on January 1, 2018. On March 15, 2018, the Company completed an acquisition of proved and unproved properties from OneEnergy Partners, LLC (“OEP”) (See Note 5-Acquisitions and Divestitures). As a result of the adoption of ASU 2017-01, the Company accounted for the acquisition as an asset purchase instead of a business combination. As a result, acquisition costs of approximately $1.1 million were capitalized as part of the acquisition and the purchase price was allocated to unproved and proved properties based on relative fair value. On January 1, 2018, we retroactively adopted ASU No. 2016–18, Statement of Cash Flows (Topic 230) : Restricted Cash (a consensus of the FASB Emerging Issues Task Force).” This ASU requires the statements of cash flows to present the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents are now included with cash and cash equivalents when reconciling the beginning of period and end of period amounts presented on the statements of cash flows. The retrospective application of this new accounting guidance resulted in a decrease of $0.6 million in “restricted cash” in Cash Flows from Investing Activities, an increase of $0.6 million in “Cash, Cash Equivalents, and Restricted Cash, beginning of the period,” and an increase of $0.6 million in “Cash, Cash Equivalents, and Restricted Cash, end of period” in our accompanying condensed consolidated statement of cash flows for the six months ended June 30, 2017, from what was previously presented in our Quarterly Report on Form 10–Q for the quarterly period ended June 30, 2017. Recently Issued Accounting Pronouncements The Company considers the applicability and impact of all Accounting Standards Updates (“ASUs”). The ASUs listed below were assessed and determined to be either not applicable or are expected to have minimal impact on its consolidated financial position and/or results of operations. On February 25, 2016, the FASB issued ASU 2016-02, Leases (Topic 842) (ASU 2016-02) , which requires companies to recognize the assets and liabilities for the rights and obligations created by long-term leases of assets on the balance sheet. The guidance requires adoption by application of a modified retrospective transition approach for existing long-term leases and is effective for fiscal years beginning after December 15, 2018, including interim periods within those years. Oil and natural gas leases are scoped out of ASU 2016-02. The Company is currently gathering all lease and other agreements which may contain embedded leases to evaluate the impact that ASU 2016-02 would have on the Company’s consolidated financial statements. The Company expects that the adoption of ASU 2016-02 will likely increase the Company’s recorded assets and liabilities. As of June 30, 2018 , the Company is continuing to evaluate each of its lease arrangements and has not yet determined the aggregate impact on its consolidated financial statements. Accrued Liabilities At June 30, 2018 and December 31, 2017 , the Company’s accrued liabilities consisted of the following: June 30, 2018 December 31, 2017 ($ in thousands) Accrued bonus $ 1,234 $ 3,000 Accrued capital expenditures 9,474 3,615 Other accrued liabilities 3,380 1,019 $ 14,088 $ 7,634

REVENUE

REVENUE	6 Months Ended
	Jun. 30, 2018
Revenues [Abstract]
REVENUE	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 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 the 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 be entitled 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. The Company’s crude oil is currently sold under a single short-term contract. The purchaser’s commitment includes all quantities of crude oil from the leases that are covered by the contract, with no quantity-based restrictions or variable terms. Pricing is based on posted indexes for crude oil of similar quality, less a fees deduction that is subject to negotiation. As of the most recent contract amendments, the negotiable fees deduction is $5.25 per barrel from June 1, 2018 through July 31, 2018, then $5.15 per barrel from August 1, 2018 through February 28, 2019, continuing on a month-to-month basis thereafter unless renegotiated or canceled upon 30 days' notice. The posted index prices change monthly based on the average of daily index price points for each sales month. Natural gas and NGL revenues Natural gas 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 of our operated natural gas production is sold under one of three natural gas contracts 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 NGL produced on specific wellbores or dedicated acreage as defined in the contract, with no quantity-based restrictions or variable terms. The gas contracts are 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 condensed 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 underproduction is recorded as a receivable. The Company did not have any significant natural gas imbalance positions as of June 30, 2018 and December 31, 2017 . 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 condensed 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 under the New Revenue Standard. 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 consider ourselves principals 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 has utilized the practical expedient in the New Revenue Standard 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 greater than one year, the Company has utilized 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 ): Three Months Ended Short-term contracts Long-term contracts Total Crude Oil $ 14,254 $ — $ 14,254 Natural Gas $ 145 $ 999 $ 1,144 NGLs $ 265 $ 1,820 $ 2,085 Six Months Ended Short-term contracts Long-term contracts Total Crude oil $ 26,843 $ — $ 26,843 Natural gas $ 524 $ 1,510 2,034 NGLs $ 774 $ 2,227 $ 3,001 Customer Credit Risk Our principal exposures to credit risk is through receivables from the sale of our oil and natural gas production of approximately $8.4 million at June 30, 2018 , and through receivables from our joint interest partners of approximately $5.0 million together with $4.2 million of accrued unbilled receivables at June 30, 2018 . 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. For the three months ended June 30, 2018 , sales to three customers, Texican Crude & Hydrocarbons, LLC, Lucid Energy Delaware, LLC, and ETC Field Services LLC, accounted for approximately 86% , 12% and 2% of our revenue, respectively. For the six months ended June 30, 2018, sales to these same three customers accounted for approximately 86% , 10% and 4% of our revenue, respectively. For the three months ended June 30, 2017 , sales to two customers, Texican Crude & Hydrocarbons, LLC and ETC Field Services LLC, accounted for approximately 79% and 21% of our revenue, respectively. For the six months ended June 30, 2017, sales to these same two customers accounted for approximately 78% and 22% of our revenue, respectively. Due to availability of other purchasers, we do not believe the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations. LONG-TERM DEFERRED REVENUE On May 21, 2018, the Company entered into a crude oil gathering agreement and option agreement with Salt Creek Midstream, LLC (“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 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 and is expected to be completed in November 2018. 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 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 of payment $35 million which was recorded as deferred revenue in long-term deferred revenue.

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES	6 Months Ended
	Jun. 30, 2018
Extractive Industries [Abstract]
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/or plugging and abandoning non-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, (b) estimated future development cost to be incurred in developing proved reserves; and (c) estimated decommissioning and abandonment/restoration costs, net of estimated salvage values, 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 and 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. As of June 30, 2018, the ceiling value of the Company's reserves was calculated based upon SEC pricing of $57.67 per barrel for oil, $2.92 per MMBtu for natural gas and $54.79 per barrel for NGLs. The Company accounts for its unproven long-lived assets in accordance with ASC Topic 360-10-05, Accounting for the Impairment or Disposal of Long-Lived Assets (ASC Topic 360-10-05). ASC Topic 360-10-05 requires that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the historical carrying value of an asset may no longer be appropriate. Costs associated with undeveloped acreage are excluded from the depletion base until it is determined whether proved reserves can be assigned to the properties. When proved reserves are assigned to such properties or one or more specific properties are deemed to be impaired, the cost of such properties is added to the full cost pool which is subject to depletions. The following table sets forth a summary of oil and natural gas property costs (net of divestitures) not being amortized at June 30, 2018 and December 31, 2017 : June 30, 2018 December 31, 2017 (In thousands) Unproved unevaluated acreage: Beginning balance 101,771 $ 24,461 Lease purchases 86,181 78,110 Transfer and other reclassification to proved properties (19,593 ) (800 ) Total unproved acreage $ 168,359 $ 101,771 Wells in progress: Beginning balance $ — $ 7,453 Additions 625 — Reclassification to evaluated properties — (7,453 ) Total wells in progress not subject to DD&A $ 625 $ — During the six months ended June 30, 2018 , the Company completed an assessment of its inventory of unproved acreage for impairment which resulted in $11.1 million being transferred from unproved properties to proved properties in the full cost pool due to defective titles on certain leases. During the three and six months ended June 30, 2017 , no impairment was recorded on the Company’s unproved oil and natural gas properties. For the three months ended June 30, 2018 and 2017 , depreciation, depletion, amortization and accretion expense related to proved properties was $5.8 million and $1.4 million , respectively. For the six months ended June 30, 2018 and 2017, depreciation, depletion, amortization and accretion expense related to proved properties was $10.4 million and $2.5 million, respectively.

ACQUISITIONS AND DIVESTITURES

ACQUISITIONS AND DIVESTITURES	6 Months Ended
	Jun. 30, 2018
Business Combinations [Abstract]
ACQUISITIONS AND DIVESTITURES	ACQUISITIONS AND DIVESTITURES OEP Acquisition On January 30, 2018, the Company entered into a Purchase and Sale Agreement (the “Purchase and Sale Agreement”) by and between the Company and OneEnergy Partners Operating, LLC (“OEP”), pursuant to which the Company agreed to purchase from OEP, and OEP agreed to sell to the Company, certain oil and natural gas properties and related assets for a purchase price of $70 million , subject to customary purchase price adjustments (the “OEP Acquisition”). The properties acquired by the Company pursuant to the Purchase and Sale Agreement consists of leasehold acreage in the Delaware Basin in Lea County, New Mexico. On March 15, 2018, the Company completed the OEP Acquisition whereby the Company paid $40 million in cash and issued 6,940,722 shares of the Company’s common stock valued at approximately $24.8 million for a total purchase price of approximately $64.9 million , before acquisition costs and customary purchase price adjustments. The value of the shares issued was determined using the closing price of the Company’s stock on the date of closing. The OEP Acquisition was accounted for as an asset purchase of proved properties and unproved properties using relative fair value of the assets acquired. The proved producing properties were valued based on internal estimates of future production using strip pricing and the present value discounted at 10%. Unproved properties acquired were valued using a market approach. The purchase price and the value of the assets acquired in the OEP Acquisition were as follows: (in thousands, except per share amount) Cash $ 40,000 Common stock issued (6,940,722 shares at $3.57) 24,778 Transaction costs and purchase price adjustments 1,074 Total purchase price $ 65,852 Proved properties $ 4,168 Unproved properties 61,684 $ 65,852 VPD Acquisition On February 28, 2018, the Company completed the acquisition of certain leasehold interests and other oil and gas assets in Loving and Winkler Counties, Texas from VPD Texas, L.P. ("VPD") for cash consideration of $10.6 million plus $0.5 million of related acquisition costs (the "VPD Acquisition"). The acquisition was recorded at fair value which was the total cash consideration of approximately $11.1 million . VPD is an affiliate of Värde Partners, Inc. (“Värde”). Värde participated as lead lender in the Company’s Second Lien Term Loan transaction in 2017 and as investor of the Company’s Series C Preferred Stock transaction in January 2018. As a result, the VPD Acquisition is considered a related party transaction. See Note 11 - Related Party Transactions. In connection with the above VPD Acquisition and pursuant to Article XVI.3(b) of the Joint Operating Agreement (the “JOA”) entered into between VPD and ImPetro Operating, LLC (“Operator”), a subsidiary of the Company, the Company has committed to the following drilling commitments: • drill and complete two horizontal wells (“Initial Commitment Wells”) no later than December 31, 2018; and • drill and complete at least two additional horizontal wells (“Subsequent Commitment Wells”) that target the Wolfcamp A/B Formation no later than December 31, 2019. The Company has a one-time option to extend the deadline by an additional 75 days by providing written notice to VPD of such election on or before August 31, 2018 in the case of the Initial Commitment Wells and August 31, 2019 in the case of the Subsequent Commitment Wells. The purchase price and the value of the assets acquired in the VPD Acquisition were as follows: (in thousands, except per share amount) Cash purchase price $ 10,611 Proved properties $ 3,185 Unproved properties 7,426 $ 10,611 Anadarko Acquisition On May 3, 2018, the Company completed the acquisition of certain leasehold interests and other oil and gas assets in Loving and Winkler Counties, Texas from Anadarko for a cash consideration of $7.1 million . The acquisition includes unproved leaseholds and non-consent proved producing oil and natural gas properties. As a result, the transaction is accounted for as an asset acquisition using the fair value of $7.1 million which was the total cash consideration. KEW Acquisition As of December 31, 2017 , the Company completed the acquisition of unproved acreage in Winkler County, Texas from KEW Drilling, a Delaware limited partnership (“KEW”) for cash consideration of $48.9 million plus $0.8 million of related acquisition costs. The acquisition was recorded at fair value which was the total cash consideration of approximately $49.7 million . DJ Basin Properties Divestiture On June 30, 2017 , the Company entered into a purchase and sale agreement with Nanke Energy LLC for the divestiture of all of its oil and natural gas properties located in the Denver-Julesburg Basin (the “DJ Basin”) for consideration of $2 million , subject to customary post-closing purchase price adjustments. The sale of the Company’s DJ Basin assets did not significantly alter the relationship between capitalized costs and proved reserves, and as such, all proceeds were recorded as adjustments to the Company’s full cost pool with no gain or loss recognized. The DJ Basin assets were sold to an entity owned by the Company’s former chief financial officer and, therefore, the divestiture is considered a related party transaction. See Note 10 - Related Party Transactions . The net proceeds of $1.08 million received on June 30, 2017 , included an offset against $0.7 million of severance pay and $0.22 million of net sales adjustments due to the purchaser.

FAIR VALUE OF FINANCIAL INSTRUM

FAIR VALUE OF FINANCIAL INSTRUMENTS	6 Months Ended
	Jun. 30, 2018
Fair Value Disclosures [Abstract]
FAIR VALUE OF FINANCIAL INSTRUMENTS	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. The determination of the fair values of our derivative contracts incorporates various factors, which include 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 June 30, 2018 Oil and natural gas derivative swap contracts $ — $ (2,106 ) $ — $ (2,106 ) Oil and natural gas derivative collar contracts — (2,899 ) — (2,899 ) Oil and natural gas derivative basis swap contracts — 910 — 910 Second Lien Term Loan conversion features — — (63,827 ) (63,827 ) Total $ — $ (4,095 ) $ (63,827 ) $ (67,922 ) As of December 31, 2017 Oil and natural gas derivative swap contracts $ — $ (706 ) $ — $ (706 ) Oil and natural gas derivative collar contracts — (147 ) — (147 ) Warrant liabilities — — (223 ) (223 ) Second Lien Term Loan conversion features — — (72,714 ) (72,714 ) Total $ — $ (853 ) $ (72,937 ) $ (73,790 ) The Company’s derivative liability associated with the Second Lien Term Loan and warrants are measured using Level 3 inputs as follows: Second Lien Term Loan Conversion Features: Under the terms of the Company’s second lien credit agreement, dated as of April 26, 2017, by and among the Company, certain subsidiaries of the Company, as guarantors (the “Guarantors”), Wilmington Trust, National Association, as administrative agent (the “Agent”), and the lenders party thereto (the “Lenders”), including Värde Partners, Inc., as lead lender (the “Lead Lender”), as amended (the “Second Lien Credit Agreement”), the Lead Lender has the option to convert 70% of the principal amount of each tranche of the Second Lien Term Loan (the “ Second Lien Loan”) under the Second Lien Credit Agreement, together with accrued paid-in-kind interest and the make-whole premium on such principal amount (together, the “Conversion Sum”), into shares of common stock. The make-whole premium is the cash amount representing the excess of (a) the present value at such repayment, prepayment or acceleration date or the date the obligations otherwise become due and payable in full of (1) the sum of the principal amount repaid, prepaid or accelerated plus (2) the interest accruing on such principal amount from the date of such repayment, prepayment or acceleration through the maturity date (excluding accrued but unpaid paid-in-kind interest to the date of such repayment, prepayment or acceleration), such present value to be computed using a discount rate equal to the Treasury Rate plus 50 basis points discounted to the repayment, prepayment or acceleration date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months), over (b) the principal amount of the Loan repaid, prepaid or accelerated. The number of shares issued will be based on the division of 70% of the Conversion Sum by the conversion price then in effect. The Company also has the option to cause the Loan to convert if, at the time of exercise of the Company’s conversion option, the closing price of the Company’s common stock has been at least 150% of the Conversion Price (as defined in Note 9) then in effect for at least 20 of the 30 immediately preceding trading days. The features of the make-whole premium in the Loan require the conversion features to be recorded as embedded derivatives and bifurcated from its host contracts, the Loan, and accounted for separately from the debt. The conversion features contained in the Loan are recorded as a derivative liability at fair value each reporting period based upon values determined through the use of discounted lattice models of the Loan under the Second Lien Credit Agreement. Change in fair value is accounted for in the condensed consolidated statement operations. As of December 31, 2017, the fair value of the embedded derivative under the Second Lien Credit Agreement associated with the Loan conversion features was a liability of approximately $72.7 million . As of June 30, 2018 , the fair value of the embedded derivative liability was $63.8 million. As a result, the Company recorded an unrealized loss of $19.5 million and an unrealized gain of $8.9 million on the change in fair value of derivative liabilities associated with the Loan conversion features for the three and six months ended June 30, 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. SOS Warrant Liability. On June 23, 2016, in conjunction with the merger with Brushy Resources, the Company issued to SOS Investment LLC ("SOS") warrants to purchase up to 200,000 shares of the Company’s common stock at an exercise price of $25.00 (the "SOS Warrants"). The warrants contain a price protection feature that will automatically reduce the exercise price if the Company enters into another agreement pursuant to which warrants are issued with a lower exercise price. As of December 31, 2017 , the fair value of the SOS Warrant liability was approximately $0.2 million . As a result of the Company’s early adoption of ASU 2017-11, “Accounting for Financial Instruments with Down Round Features” on January 1, 2018, the $0.2 million on the SOS Warrants were reclassified from current liabilities to stockholders’ equity at January 1, 2018. During the three and six months ended June 30, 2017 , the Company recorded an unrealized gain of approximately $0.3 million on the SOS Warrant liability.

ASSET RETIREMENT OBLIGATIONS (A

ASSET RETIREMENT OBLIGATIONS (ARO)	6 Months Ended
	Jun. 30, 2018
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT OBLIGATIONS (ARO)	ASSET RETIREMENT OBLIGATIONS (ARO) The Company’s 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 asset retirement obligations for the six months ended June 30, 2018 and year ended December 31, 2017: Six Months Ended June 30, 2018 Year Ended December 31, 2017 (In thousands) ARO, beginning of period $ 952 $ 1,257 Additional liabilities incurred 315 20 Accretion expense 48 82 Liabilities settled (87 ) (288 ) Revision in estimates (66 ) (119 ) 1,162 952 Less: current portion of ARO (63 ) (226 ) ARO, end of period $ 1,099 $ 726

DERIVATIVES

DERIVATIVES	6 Months Ended
	Jun. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVES	DERIVATIVES Embedded Derivatives As discussed in Note 6, the Second Lien Term Loan contains conversion features that are exercisable at the option of the Lead Lender or 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) separate, stand-alone instruments with similar terms 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 condensed consolidated statement of operations for each reporting period. As of June 30, 2018 and December 31, 2017 , the fair value of the derivative liability was $63.8 million and $72.7 million , respectively. As a result, the Company recognized an unrealized loss of $19.5 million and unrealized gain of $8.9 million in its condensed consolidated statement of operations for the three and six months ended June 30, 2018 , respectively. There were no derivative liabilities associated with convertible debt instruments for the three and six months ended June 30, 2017 . Commodity Derivatives To reduce the impact of fluctuations in oil and natural gas prices on the Company’s revenues, or 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 price floor 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). These hedging activities, which are governed by the terms of our Second Lien Credit Agreement, are intended to support oil and natural gas prices at targeted levels and manage exposure to oil and natural gas price fluctuations. It is our policy to enter into derivative contracts only with counterparties that are creditworthy and competitive market makers. All of our derivatives are with non-lender counterparties and are designated as unsecured. Certain of our derivative counterparties may require the posting of cash collateral under certain conditions. It is never the Company’s intention to enter into derivative contracts for speculative trading purposes. 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 Company's condensed 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 following table presents the Company’s derivative position for the production periods indicated as of June 30, 2018: Description Notional Volume (Bbls/d) Production Period Weighted Average Price ($/Bbl) Oil Swaps 900 July 2018 - December 2018 $ 57.68 Basis Swaps 1,500 July 2018 - December 2018 $ (5.62 ) Basis Swaps 1,500 January 2019 - December 2019 $ (5.62 ) Basis Swaps 1,500 January 2020 - December 2020 $ (5.62 ) 3 Way Collar Floor sold price (put) 1,252 January 2019 - December 2019 $ 45.00 3 Way Collar Floor purchase price (put) 1,252 January 2019 - December 2019 $55.00 3 Way Collar Ceiling sold price (call) 1,252 January 2019 - December 2019 $70.61 Oil Collar Floor purchase price (put) 1,763 July 2018 - December 2018 $ 58.35 Oil Collar Ceiling sold price (call) 1,763 July 2018 - December 2018 $69.86 Oil Collar Floor purchase price (put) 1,000 January 2019 - June 2019 $52.50 Oil Collar Ceiling sold price (call) 1,000 January 2019 - June 2019 $67.60 Six Months Ended Year Ended (in thousands) Beginning fair value of commodity derivatives $ (853 ) $ — Change in fair value of derivative instruments (4,572 ) (1,063 ) Net settlements paid on crude oil derivative contracts 1,710 96 Change in settlements accrued on crude oil derivative contracts (383 ) 114 Ending fair value of commodity derivatives, net $ (4,098 ) $ (853 ) 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 condensed consolidated balance sheets: As of June 30, 2018 Gross Amount of Recognized Assets and Liabilities Gross Amounts Offset in the Condensed Consolidated Balance Sheets Net Amounts Presented in the Condensed Consolidated Balance Sheets (in thousands) Offsetting Derivative Assets: Current asset $ 3,249 $ (1,474 ) $ 1,775 Long-term asset — — — Total asset $ 3,249 $ (1,474 ) $ 1,775 Offsetting Derivative Liabilities: Current liability $ 4,444 $ (1,457 ) $ 2,987 Long-term liability 2,738 148 2,886 Total liability $ 7,182 $ (1,309 ) $ 5,873 As of December 31, 2017 Gross Amount of Recognized Assets and Liabilities Gross Amounts Offset in the Condensed Consolidated Balance Sheets Net Amounts Presented in the Condensed Consolidated Balance Sheets (in thousands) Offsetting Derivative Assets: Current asset $ — $ — $ — Long-term asset — — — Total asset $ — $ — $ — Offsetting Derivative Liabilities: Current liability $ 853 $ — $ 853 Long-term liability — — — Total liability $ 853 $ — $ 853

LONG-TERM DEBT

LONG-TERM DEBT	6 Months Ended
	Jun. 30, 2018
Debt Disclosure [Abstract]
LONG-TERM DEBT	LONG-TERM DEBT June 30, 2018 December 31, 2017 (In thousands) Riverstone First Lien Loans associated with the Amended and Restated Senior Secured Term Loan Credit Agreement, due 2021, net of debt issuance costs and debt discount $ 47,805 $ — 6% Bridge Loans associated with the amended First Lien Term Loan, due 2019, net of debt issuance costs — 30,363 8.25% Second Lien Term Loans, due 2021, net of debt issuance costs and debt discount 110,743 96,431 6% note payable to SOS Investment, LLC, due 2019 — 1,000 Other notes payable, due 2018 5 11 Total long-term debt $ 158,553 $ 127,805 Less: current portion (5 ) (11 ) Total long-term debt, net of current portion $ 158,548 $ 127,794 As of June 30, 2018 and December 31, 2017 , the carrying amounts of the Company's Riverstone First Lien Loans and Second Lien Term Loans were as follows (in thousands) : Principal Amount Paid-in- kind Interest Unamortized Debt Issuance Costs & Debt Discount Carrying Amount June 30, 2018: Riverstone First Lien Loans, due January 2021 $ 50,000 $ — $ (2,195 ) $ 47,805 Second Lien Term Loans, due April 2021 150,000 12,189 (51,446 ) 110,743 Total: $ 200,000 $ 12,189 $ (53,641 ) $ 158,548 December 31, 2017: Bridge Loans associated with the amended First Lien Term Loan, due September 2019 $ 30,000 $ 807 $ (444 ) $ 30,363 Second Lien Term Loans, due April 2021 150,000 5,752 (59,321 ) 96,431 Total: $ 180,000 $ 6,559 $ (59,765 ) $ 126,794 Second Lien Credit Agreement On April 26, 2017, the Company entered into the Second Lien Credit Agreement comprised of convertible loans in an aggregate initial principal amount of up to $125 million available in two separate tranches. The first tranche consists of an $80 million term loan (the “Second Lien Term Loan”), which was fully drawn and funded on April 26, 2017. The second tranche consists of up to $45 million in delayed-draw term loans (the “Delayed Draw Term Loan” and, together with the Second Lien Term Loan, the “Second Lien Loans”) to be funded on or before February 28, 2019, at the request of the Company, subject to certain conditions, in a single draw or in multiple draws. Each tranche of Second Lien Loans will bear interest at a rate of 8.25% per annum, 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. On October 3, 2017, the Company, the Guarantors, the Agent and the Lenders entered into Amendment No. 1 to the Second Lien Credit Agreement (“Amendment No. 1 to the Second Lien Credit Agreement”). The purpose of Amendment No. 1 to the Second Lien Credit Agreement is to waive certain conditions precedent to the drawing of the Delayed Draw Term Loan under the Second Lien Credit Agreement and to provide for the funding of such Delayed Draw Term Loan upon the signing of the lease acquisition agreement with KEW. The Company borrowed the full $45.0 million of the availability under the Delayed Draw Term Loan on October 4, 2017. On October 19, 2017, the Company entered into a second amendment to the Second Lien Credit Agreement (“Amendment No. 2 to the Second Lien Credit Agreement”), by and among the Company, the Guarantors, the Agent and the Lenders, including the Lead Lender. Amendment No. 2 to the Second Lien Credit Agreement permits the Company to incur the Incremental Bridge Loan under the First Lien Credit Agreement. On November 10, 2017, the Company entered into a third amendment to the Second Lien Credit Agreement (“Amendment No. 3 to the Second Lien Credit Agreement”), by and among the Company, the Guarantors, the Agent and the Lenders, including the Lead Lender. Amendment No. 3 to the Second Lien Credit Agreement increased by $25.0 million the amount of delayed draw term loans available for borrowing under the Second Lien Credit Agreement. The additional $25.0 million of Delayed Draw Term Loan was drawn on November 10, 2017. The $25.0 million of proceeds from these loans may be used to fund oil and natural gas property acquisitions, subject to certain limitations, to fund drilling and completion costs or for other general corporate purposes. On January 31, 2018, the Company entered into a fourth amendment to the Second Lien Credit Agreement with the Guarantors, the Lenders, including Värde Partners, Inc., as lead lender, and the Agent (“Amendment No. 4 to the Second Lien Credit Agreement”). The purpose of Amendment No. 4 to the Second Lien Credit Agreement was to, among other matters: • permit the Company to enter into the Riverstone First Lien Credit Agreement and incur the Riverstone First Lien Loans and related liens; • permit the Company to issue the Series C Preferred Stock; and • after the issuance of the Series C Preferred Stock, reduce from two to one the maximum number of members of the Board of Directors, the lenders under the Second Lien Credit Agreement will have the right to appoint following the conversion of the convertible loans under the Second Lien Credit Agreement. The Second Lien Loans are secured by second priority liens on substantially all of the Company’s and the Guarantors’ assets, including their oil and natural gas properties located in the Delaware Basin, and all of the obligations thereunder are unconditionally guaranteed by each of the Guarantors. The Second Lien Loans mature on April 26, 2021 . The Second Lien Loans are subject to mandatory prepayment with the net proceeds of certain asset sales, casualty events and debt incurrences, subject to the right of the Company to reinvest the net proceeds of asset sales and casualty events within 180 days and, in the case of asset sales and casualty events, prepayment of the Bridge Loan. The Company may not voluntarily prepay the Second Lien Loans prior to March 31, 2019 except (a) in connection with a Change of Control (as defined in the Second Lien Credit Agreement) or (b) if the closing price of our common stock on the principal exchange on which it is traded has been equal to or greater than 110% of the Conversion Price (as defined below) for at least 20 of the 30 trading days immediately preceding the prepayment. The Company will be required to pay a make-whole premium in connection with any mandatory or voluntary prepayment of the Second Lien Loans. Each tranche of the Second Lien Loans is separately convertible at any time, in full and not in part, at the option of the Lead Lender, as follows: • 70% of the principal amount of each tranche of Second Lien Loans, together with accrued and unpaid interest and the make-whole premium on such principal amount, will convert into a number of newly issued shares of 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 • 30% of the principal amount of each tranche of Second Lien Loans, together with accrued and unpaid interest and the make-whole premium on such principal amount, will convert on a dollar for dollar basis into a new term loan (the “Take Back Loans”). The terms of the Take Back Loans will be substantially the same as the terms of the Second Lien Loans, except that the Take Back Loans will not be convertible and will bear interest payable in cash at a rate of LIBOR plus 9% (subject to a 1% LIBOR floor). Additionally, the Company will have the option to convert the Second Lien Loans, in whole or in part, into shares of common stock at any time or from time to time if, at the time of exercise of the Company’s conversion option, the closing price of the Company's common stock on the principal exchange on which it is traded has been at least 150% of the Conversion Price then in effect for at least 20 of the 30 immediately preceding trading days. Conversion at the Company’s option will occur on the same terms as conversion at the Lender’s option. The Second Lien Loans 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; limitations on incurrence of indebtedness, investments, dividends and other restricted payments, lease obligations, hedging and capital expenditures; and maintenance of a specified asset coverage ratio. The Second Lien Loans also provides for events of default, including failure to pay any principal or interest when due, failure to perform or observe covenants, cross-default on certain outstanding debt obligations, the failure of a Guarantor to comply with the provisions of its Guaranty, and bankruptcy or insolvency events, subject to certain specified cure periods. The amounts under the Second Lien Loans could be accelerated and be due and payable upon an event of default. As of June 30, 2018 , the Company was in compliance with all restrictive covenants. As discussed in Note 6, Fair Value of Financial Instruments, and Note 8, Derivatives , the Company separately accounts for the embedded conversion features of the Second Lien Loans as a derivative instrument in accordance with accounting guidance relating to recording embedded derivatives at fair value. The initial fair value of the embedded derivatives is recorded as a debt discount to the convertible Second Lien Term Loan. The debt discount is amortized over the term of the Second Lien Loans using effective interest rate. Riverstone First Lien Credit Agreement On January 30, 2018, the Company entered into an Amended and Restated Senior Secured Term Loan Credit Agreement (the “Riverstone First Lien Credit Agreement”) by and among the Company, the subsidiaries of the Company party thereto as guarantors, Riverstone Credit Management LLC, as administrative agent and collateral agent, and the lenders party thereto. Effective at closing under the Riverstone First Lien Credit Agreement, which occurred on January 31, 2018, the Riverstone First Lien Credit Agreement amended and restated the Company's First Lien Credit Agreement, which was entered into by the Company on September 29, 2016, and subsequently amended on April 26, 2017, July 25, 2017, and October 19, 2017 (the "First Lien Credit Agreement"). Pursuant to the Riverstone First Lien Credit Agreement, the lenders thereunder agreed to make term loans to the Company in the aggregate principal amount of $50 million (the “Riverstone First Lien Loans”), all of which were funded in full at closing at an original issue discount of 1.0% of the principal amount. The Riverstone First Lien Credit Agreement provides the potential for additional term loans of up to $30 million , as requested by the Company and subject to certain conditions, which additional loans were uncommitted at closing. The Company used approximately $31.5 million of the proceeds of the Riverstone First Lien Loans to repay in full its obligations under and retire the First Lien Credit Agreement during the first quarter of 2018 . Amendments to Riverstone First Lien Credit Agreement and Second Lien Credit Agreement On February 20, 2018, the Company entered into the following amendments to its existing credit agreements (collectively, the “Amendments”): (i) Amendment No. 1 to the Riverstone First Lien Credit Agreement and (ii) Amendment No. 5 to the Second Lien Credit Agreement. Pursuant to the Amendments and a consent letter received from the Purchasers (as defined in Note 12 below), in their capacity as the holders of all of the issued and outstanding shares of Series C Preferred Stock, the Company has been granted the right to repurchase shares of its Common Stock for an aggregate purchase price up to $10,000,000 (subject to certain exceptions and conditions). The commencement of any repurchase of shares of Common Stock is subject to compliance with applicable law, Board approval, and market conditions. Interest Expense The components of interest expense are as follows ( in thousands) : Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Interest on term loans $ 1,078 $ 330 $ 2,538 $ 847 Interest on notes payable — 15 — 29 Paid-in-kind interest on term loans 3,269 1,341 6,437 1,341 Amortization of debt financing costs 262 1,495 881 1,622 Amortization of discount on term loans 3,963 3,473 7,804 3,588 Total $ 8,572 $ 6,654 $ 17,660 $ 7,427

LONG-TERM DEFERRED REVENUE

LONG-TERM DEFERRED REVENUE	6 Months Ended
	Jun. 30, 2018
Revenue from Contract with Customer [Abstract]
LONG-TERM DEFERRED LIABILITIES	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 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 the 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 be entitled 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. The Company’s crude oil is currently sold under a single short-term contract. The purchaser’s commitment includes all quantities of crude oil from the leases that are covered by the contract, with no quantity-based restrictions or variable terms. Pricing is based on posted indexes for crude oil of similar quality, less a fees deduction that is subject to negotiation. As of the most recent contract amendments, the negotiable fees deduction is $5.25 per barrel from June 1, 2018 through July 31, 2018, then $5.15 per barrel from August 1, 2018 through February 28, 2019, continuing on a month-to-month basis thereafter unless renegotiated or canceled upon 30 days' notice. The posted index prices change monthly based on the average of daily index price points for each sales month. Natural gas and NGL revenues Natural gas 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 of our operated natural gas production is sold under one of three natural gas contracts 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 NGL produced on specific wellbores or dedicated acreage as defined in the contract, with no quantity-based restrictions or variable terms. The gas contracts are 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 condensed 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 underproduction is recorded as a receivable. The Company did not have any significant natural gas imbalance positions as of June 30, 2018 and December 31, 2017 . 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 condensed 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 under the New Revenue Standard. 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 consider ourselves principals 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 has utilized the practical expedient in the New Revenue Standard 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 greater than one year, the Company has utilized 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 ): Three Months Ended Short-term contracts Long-term contracts Total Crude Oil $ 14,254 $ — $ 14,254 Natural Gas $ 145 $ 999 $ 1,144 NGLs $ 265 $ 1,820 $ 2,085 Six Months Ended Short-term contracts Long-term contracts Total Crude oil $ 26,843 $ — $ 26,843 Natural gas $ 524 $ 1,510 2,034 NGLs $ 774 $ 2,227 $ 3,001 Customer Credit Risk Our principal exposures to credit risk is through receivables from the sale of our oil and natural gas production of approximately $8.4 million at June 30, 2018 , and through receivables from our joint interest partners of approximately $5.0 million together with $4.2 million of accrued unbilled receivables at June 30, 2018 . 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. For the three months ended June 30, 2018 , sales to three customers, Texican Crude & Hydrocarbons, LLC, Lucid Energy Delaware, LLC, and ETC Field Services LLC, accounted for approximately 86% , 12% and 2% of our revenue, respectively. For the six months ended June 30, 2018, sales to these same three customers accounted for approximately 86% , 10% and 4% of our revenue, respectively. For the three months ended June 30, 2017 , sales to two customers, Texican Crude & Hydrocarbons, LLC and ETC Field Services LLC, accounted for approximately 79% and 21% of our revenue, respectively. For the six months ended June 30, 2017, sales to these same two customers accounted for approximately 78% and 22% of our revenue, respectively. Due to availability of other purchasers, we do not believe the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations. LONG-TERM DEFERRED REVENUE On May 21, 2018, the Company entered into a crude oil gathering agreement and option agreement with Salt Creek Midstream, LLC (“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 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 and is expected to be completed in November 2018. 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 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 of payment $35 million which was recorded as deferred revenue in long-term deferred revenue.

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	6 Months Ended
	Jun. 30, 2018
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	RELATED PARTY TRANSACTIONS There were no related party transactions during the three months ended June 30, 2018 and 2017. During the six months ended June 30, 2018 and 2017 , the Company was engaged in the following transactions, which occurred during the first quarters of 2018 and 2017, with certain related parties: Six Months Ended June 30, Related Party Transactions 2018 2017 ($ in thousands) Directors and Officers: Brennan Short (former Chief Operating Officer) Consulting fees paid to MMZ Consulting, Inc. (“MMZ”) which is owned by Mr. Short. Mr. Short is the sole member of MMZ. $ — $ 204 Total: $ — $ 204 Kevin Nanke (former Chief Financial Officer) Purchased the DJ Basin properties from the Company through Nanke Energy, LLC $ — $ 2,000 Total: $ — $ 2,000 Värde Partners, Inc. (“Värde”) (1) The Company acquired oil and natural gas interests from VPD, an affiliate of Värde $ 10,611 $ — $ 10,611 $ — (1) Värde is the lead lender in the Company’s Second Lien Loans (see Note 9 – Long-term Debts) and also participated in the issuance of Series C 9.75% Convertible Preferred Stock in January 2018 (see Note 11 – Shareholders’ Equity and Redeemable Preferred Stock).

SHAREHOLDERS_ EQUITY AND REDEEM

SHAREHOLDERS’ EQUITY AND REDEEMABLE PREFERRED STOCK	6 Months Ended
	Jun. 30, 2018
Equity [Abstract]
SHAREHOLDERS’ EQUITY AND REDEEMABLE PREFERRED STOCK	SHAREHOLDERS’ EQUITY AND REDEEMABLE PREFERRED STOCK Preferred Stock Issuance On January 30, 2018, the Company entered into a Securities Purchase Agreement (the “Securities Purchase Agreement”) by and among the Company and certain private funds affiliated with Värde Partners, Inc. (the “Purchasers”), pursuant to which the Company agreed to issue and sell to the Purchasers, and the Purchasers agreed to purchase from the Company, 100,000 shares of a newly created series of preferred stock of the Company, designated as “Series C 9.75% Convertible Participating Preferred Stock”(the “ Series C Preferred Stock”), for a purchase price of $1,000 per share, or an aggregate of $100,000,000 . Värde Partners, Inc. is the lead lender, and certain private funds affiliated with Värde Partners, Inc. are lenders, under the Company’s Second Lien Credit Agreement (as defined above in Note 9 – Long Term Debt ). Closing of the issuance and sale of the shares of Series C Preferred Stock pursuant to the Securities Purchase Agreement occurred on January 31, 2018. The terms of the Series C Preferred Stock are set forth in the Certificate of Designation for the Series C Preferred Stock (the “Certificate of Designation”) filed by the Company with the Secretary of State of the State of Nevada on January 31, 2018. The following is a description of the material terms of the Series C Preferred Stock and the Securities Purchase Agreement. Ranking . 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. Dividends . Holders of shares of Series C 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 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. The Company expects to pay dividends-in-kind for the foreseeable future. In addition to these preferential dividends, holders of shares of Series C Preferred Stock will be entitled to participate in any dividends paid on the Common Stock on an as-converted basis. As of June 30, 2018 , the Company had $4.1 million of dividends in arrears on the Series C Preferred Stock. These dividends have not been declared by the Company’s Board of Directors. 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 “Optional Redemption Amount”). The Series C 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 Certificate of Designation) as described below. Conversion . Each share of Series C Preferred Stock is convertible at any time at the option of the holder into a number of shares of Common Stock equal to (i) the applicable Optional Redemption Amount divided by (ii) a conversion price of $6.15 , subject to adjustment (the “Series C Preferred Stock Conversion Price”). The Series C Preferred Stock 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 Series C Preferred Stock 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 lesser of (i) $5.25 and (ii) the Series C Preferred Stock Conversion Price then in effect, subject to certain exceptions and to the Share Cap (as defined below). The Company has the right to force the conversion of any or all of the outstanding shares of Series C Preferred Stock if (i) the volume-weighted average price per share of the Common Stock on the principal exchange on which it is then traded has been at least 140% of the Series C Preferred Stock Conversion Price then in effect for at least 20 of the 30 consecutive trading days immediately preceding the exercise by the Company of the forced conversion right and (ii) certain trading and other conditions are satisfied. Change of Control . Upon the occurrence of a Change of Control (as defined in the Certificate of Designation), each holder of shares of Series C Preferred Stock will have the option to: • cause the Company to redeem all of such holder’s shares of Series C Preferred Stock for cash in an amount per share equal to (i) the 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 Series C 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 Series C Preferred Stock, subject to any adjustments to the Series C Preferred Stock 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 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 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 a share of Series C Preferred Stock is then convertible. Voting Rights; Negative Covenants . In addition to the Board designation rights described in the Certificate of Designation, holders of shares of Series C 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 Series C Preferred Stock will entitle the holder to a number of votes equal to (i) the Stated Value as of the applicable record date or other determination date divided by (ii) $4.42 (the closing price of the Common Stock on the NYSE American on January 30, 2018). 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 six months ended June 30, 2018 , the Company purchased 253,598 shares of the Company’s common stock for approximately $1.0 million . Warrants The following table provides a summary of warrant activity for the six months ended June 30, 2018 : Warrants Weighted- Average Exercise Price Outstanding at January 1, 2018 11,882,800 $ 3.46 Exercised (2,848,440 ) $ 2.50 Expired or canceled (2,324,304 ) $ 3.84 Outstanding at June 30, 2018 6,710,056 $ 3.27

SHARE BASED AND OTHER COMPENSAT

SHARE BASED AND OTHER COMPENSATION	6 Months Ended
	Jun. 30, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
SHARE BASED AND OTHER COMPENSATION	SHARE BASED AND OTHER COMPENSATION The Company’s share-based compensation consisted of the following (dollars in thousands): Six Months Ended June 30, 2018 Six Months Ended June 30, 2017 Stock Options Restricted Stock Total Stock Options Restricted Stock Total Share-based compensation expensed $ 1,238 $ 4,316 $ 5,554 $ 3,273 $ 6,113 $ 9,386 Unrecognized share-based compensation costs $ 1,346 $ 4,777 $ 6,123 $ 7,669 $ 2,094 $ 9,763 Weighted average amortization period remaining (in years) 0.56 0.63 1.19 0.82 0.74 1.56 Restricted Stock A summary of restricted stock grant activity pursuant to the Lilis Energy, Inc. 2012 Omnibus Incentive Plan (the “2012 Plan”) and the 2016 Omnibus Incentive Plan (the “2016 Plan”) for the six months ended June 30, 2018 , is presented below: Number of Shares Weighted Average Grant Date Price Outstanding at January 1, 2018 2,475,266 $ 4.22 Granted 799,944 $ 4.28 Vested and issued (654,946 ) $ (4.06 ) Forfeited or canceled (1) (847,898 ) $ (4.88 ) Outstanding at June 30, 2018 1,772,366 $ 3.93 Restricted Stock Units A summary of restricted stock unit grant activity pursuant to the 2012 Plan for the six months ended June 30, 2018 , is presented below: Number of Shares Weighted Average Grant Date Price Outstanding at January 1, 2018 9,999 $ 6.57 Vested and issued (9,999 ) $ (6.57 ) Outstanding at June 30, 2018 — $ — Stock Options A summary of stock option activity pursuant to the 2016 Plan for the six months ended June 30, 2018 , is presented below: Stock Options Outstanding and Exercisable 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 $ 3.82 Exercised (675,500 ) $ (1.66 ) Forfeited or canceled (1) (1,480,850 ) $ (4.20 ) Outstanding at June 30, 2018 5,501,150 $ 3.68 4,201,200 8.4 (1) Forfeitures are accounted for as and when incurred. During the six months ended June 30, 2018 , options to purchase 352,500 shares of the Company’s common stock were granted under the 2016 Plan. The weighted average fair value of these options was $3.68 . During the six months ended June 30, 2018 , the Company received $1.0 million from the exercise of vested stock options. The fair value of stock option awards is determined using the Black-Scholes-Merton option-pricing model based on several assumptions. These assumptions are based on management’s best estimate at the time of grant. The Company used the following weighted average of each assumption based on the grants in each fiscal year: 2018 Expected Term in Years 6 Expected Volatility 58.8% - 72.6% Expected Dividends — % Risk-Free Interest Rate 2.59% - 2.71%

LOSS PER COMMON SHARE

LOSS PER COMMON SHARE	6 Months Ended
	Jun. 30, 2018
Earnings Per Share [Abstract]
EARNINGS (LOSS) PER COMMON SHARE	LOSS PER COMMON SHARE The following table shows the computation of basic and diluted net loss per share for the three and six months ended June 30, 2018 and 2017 (in thousands) : Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Net loss $ (31,208 ) (23,148 ) $ (18,962 ) $ (31,904 ) Less: dividends on redeemable preferred stock — (92 ) — (122 ) Less: dividends and deemed dividends on Series B convertible preferred stock — (4,422 ) — (4,635 ) Less: dividends on Series C convertible preferred stock (2,465 ) — (4,117 ) — Net loss attributable to common stockholders $ (33,673 ) $ (27,662 ) $ (23,079 ) $ (36,661 ) Weighted average common shares outstanding - basic and diluted 64,098,309 44,332,270 57,801,098 34,282,784 Net loss per common share – basic and diluted $ (0.53 ) $ (0.62 ) $ (0.40 ) $ (1.07 ) The Company excluded the following shares from the diluted loss per share calculations above because they were anti-dilutive for the three and six months ended June 30, 2018 and 2017 : 2018 2017 Stock Options 5,501,150 7,158,500 Restricted Stock Units — 9,999 Series C Preferred Stock 20,312,607 — Stock Purchase Warrants 6,710,056 12,523,045 Conversion of Term Loans 23,970,219 13,572,950 56,494,032 33,264,494

SUPPLEMENTAL NON-CASH TRANSACTI

SUPPLEMENTAL NON-CASH TRANSACTIONS	6 Months Ended
	Jun. 30, 2018
Supplemental Cash Flow Elements [Abstract]
SUPPLEMENTAL NON-CASH TRANSACTIONS	SUPPLEMENTAL NON-CASH TRANSACTIONS The following table presents the supplemental disclosure of cash flow information for the six months ended June 30, 2018 and 2017 : Six Months Ended June 30, 2018 2018 2017 ($ in thousands) Non-cash investing and financing activities excluded from the statement of cash flows: Conversion of Series B Preferred Stock and accrued dividends to common stock — 14,087 Fair value of warrants issued and repriced as debt discount — 1,031 Common stock issued for acquisition of oil and gas properties 24,778 — Common stock issued for commitment fees associated with Private Placement — 250 Cashless exercise of warrants — 371 Change in capital expenditures for drilling costs in accrued liabilities 5,859 871 Accrued dividends for Series C Preferred Stock 4,117 — Change in asset retirement obligations 66 — Issuance of common stock for drilling services — 96 Increase in final settlement on the divestiture of DJ Basin properties in accrued liabilities — 584 Deemed dividends on Series B 6% Convertible Preferred Stock associated with beneficial conversion features — 3,767 Fair value of derivative liabilities associated with conversion features of Second Lien Term Loan — 36,741

SEGMENT INFORMATION

SEGMENT INFORMATION	6 Months Ended
	Jun. 30, 2018
Segment Reporting [Abstract]
SEGMENT INFORMATION	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 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	6 Months Ended
	Jun. 30, 2018
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES Environmental and Governmental Regulation As of June 30, 2018 , 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, and various other matters including taxation. Oil and natural gas industry legislation and administrative regulations are periodically changed for a variety of political, economic, and other reasons. As of June 30, 2018 , 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.

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	6 Months Ended
	Jun. 30, 2018
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	SUBSEQUENT EVENTS Firm Oil Takeaway and Pricing Agreement On August 2, 2018, the Company successfully executed a five -year agreement with an affiliate of Salt Creek Midstream, LLC (“SCM”), an ARM Energy Holdings' affiliate, to secure firm takeaway and pricing. Commencing in the second half of 2019, the agreement locks down firm long-haul pipeline capacity to the Gulf Coast as well as Gulf Coast pricing. Under the terms of the agreement, 6,000 Bbl/d of firm capacity will be delivered to Gulf Coast for one year-beginning on July 1, 2019. During the next four years, from July 1, 2020 through June 30, 2024, firm capacity will adjust to 5,000 Bbl/d. All volumes have with firm Gulf Coast pricing throughout the 5-year term. The Company also has the ability to expand its capacity with SCM during the term of the agreement as the Company believes having flexibility with barrels in the future is desirable. Water Gathering and Disposal Agreement In July 2018, the Company entered into a water gathering and disposal agreement with SCM Water, LLC ("SCM Water"), an ARM Energy Holdings' affiliate. The water gathering project will complement 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 expenditure will be fully funded by SCM Water and will be designed to accommodate all water produced by the Company’s operations. The Company will act as contract operator of SCM Water’s salt water disposal wells (SWD). The Company has sold to SCM Water for cash consideration upon closing, with additional payments based on reaching certain milestones, an option to acquire the Company’s existing water infrastructure, a system which is comprised of approximately 14 miles of pipeline and one SWD. The Company is actively working on permitting additional SWD locations. The Company anticipates that the majority of its water will eventually be disposed 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 payment of $10.0 million for option to acquire our existing water infrastructure for the firm transportation and pricing for crude oil and a $5.0 million for prefunded drilling bonus. The Company expects to receive the remaining $5.0 million for both the right-of-way/easement bonus and hitting target of 40,000 barrels per day of produced water during the third quarter of 2018. Exchange of Acreage The Company entered into a definitive acre-for-acre trade agreement of approximately 750 net acres in Lea County, New Mexico on August 1, 2018. The transaction increases the Company's Gross Working Interest (GWI) in its Delaware Basin acreage in New Mexico up to 100% in core areas of the Company's operations. All the acreage that was traded away was in non-operated sections with lower working interests. The transaction is subject to customary adjustments and is expected to close August 20, 2018.

SUMMARY OF SIGNIFICANT ACCOUN27

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND ESTIMATES (Policies)	6 Months Ended
	Jun. 30, 2018
Accounting Policies [Abstract]
Principles of Consolidation	Principles of Consolidation and Presentation The condensed consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries which includes Brushy Resources, Inc. ("Brushy Resources"), 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 condensed consolidated financial statements are prepared in conformity with generally accepted accounting principles in the United States (“U.S. 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, inducement transactions and common stock; and the allocation of general administrative expenses. Actual results could differ significantly from these estimates.
Reclassifications	Reclassifications Certain reclassifications have been made to the prior period financial statements to conform to the current period presentation. These reclassifications have no effect on the Company’s previously reported results of operations. The following reclassifications have been made to the three and six months ended June 30, 2017 : (i) the income from operator’s overhead recovery of approximately $0.12 million and $0.27 million , respectively, have been reclassified from revenue to operating expense as an offset against general and administrative expenses in the condensed consolidated statement of operations; and (ii) $0.6 million of the escrow on a drilling rig has been reclassified from investing activities to cash, cash equivalents and restricted cash in the condensed consolidated statement of cash flows as required with the adoption of ASU No. 2016–18, “Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force), see Recently Adopted Accounting Standards.
Recently Issued Accounting Pronouncements	Recently Adopted Accounting Standards On January 1, 2018, the Company adopted the new accounting standard, Accounting Standards Codification, ASC 606 , Revenue from Contracts with Customers and all the related amendments (the “New Revenue Standard”) using the modified retrospective method. In accordance with the modified retrospective method, comparative information is not restated and continues to be reported under the accounting standards in effect for those periods. The cumulative effect of initially adopting the New Revenue Standard, if any, is recorded as an adjustment to the opening balance of retained earnings. The Company’s revenues from customers are derived from production and sales of crude oil, natural gas and natural gas liquids and recognized when control is transferred to the customer. As operator, the Company may market production on behalf of joint interest partners and various royalty owners. Under the terms of our joint operating agreements, the Company does not take control of the production attributable to our joint interest partners and the various royalty owners and consequently, the Company recognizes revenues only for its share of the production. In accordance with the New Revenue Standard requirements, the impact of adoption on our condensed consolidated statements of operations and condensed consolidated balance sheets was as follows: For the three months ended June 30, 2018 As Reported Balances without Adoption of ASC 606 Increase (Decrease) Condensed Consolidated Statements of Operations: Revenues $ 17,483 $ 17,498 $ (15 ) Operating expenses $ (872 ) $ (887 ) $ (15 ) For the six months ended June 30, 2018 Condensed Consolidated Statements of Operations: Revenues $ 31,878 $ 31,943 $ (65 ) Operating expenses $ (1,334 ) $ (1,399 ) $ (65 ) As of June 30, 2018 Condensed Consolidated Balance Sheets: Accounts receivable $ 8,378 $ 8,443 $ (65 ) Accrued liabilities $ (394 ) $ (459 ) $ (65 ) As shown in this comparison table, there is no impact on the net loss from the New Revenue Standard adoption and, therefore, no adjustment to the opening balance of accumulated deficit. Prior to the adoption of the New Revenue Standard, the revenue line included the value of our natural gas gatherer’s contractual volume retainage fee, with an offsetting cost included in the gathering, processing and marketing costs line. In accordance with the New Revenue Standard, the Company will only recognize revenues for its share of the production, resulting in the removal of the retainage fee approximating $15,000 and $65,000 from both revenues and operating expenses during the three and six months ended June 30, 2018 , respectively. On July 13, 2017, the Financial Accounting Standards Board (“FASB”) issued a two-part ASU 2017-11, (Part I) Accounting for Certain Financial Instruments with Down Round Features, (Part II) Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Redeemable Noncontrolling Interests with a Scope Exception (ASU 2017-11) . Part I of ASU 2017-11 simplifies the accounting for certain financial instruments with down round features by requiring companies to disregard the down round feature when assessing whether the instrument is indexed to its own stock, for purposes of determining liability or equity classification. Companies that provide earnings per share (EPS) data will adjust their basic EPS calculation for the effect of the feature when triggered (that is, when the exercise price of the related equity-linked financial instrument is adjusted downward because of the down round feature) and will also recognize the effect of the trigger within equity. Part II of ASU 2017-11 is not applicable to the Company since it addresses concerns relating to an indefinite deferral available to private companies with mandatorily redeemable financial instruments and certain noncontrolling interests. The provisions of ASU 2017-11 related to down rounds are effective for public business entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. Early adoption is permitted for all organizations. The Company elected to adopt ASU 2017-11 on January 1, 2018. The Company’s SOS Warrant Liability (as described in Note 6) was accounted for as a derivative instrument solely because of its down round feature. Any outstanding SOS Warrants as of the date of adoption were reclassified to equity and the Company will no longer recognize any gain or loss based on the fair value of the SOS Warrants. No other derivatives instruments outstanding as of January 1, 2018 were affected by the adoption of ASU 2017-11. On January 5, 2017, the FASB issued ASU 2017-01 B usiness Combinations (Topic 805): Clarifying the Definition of a Business (ASU 2017-01) , which clarifies the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. The standard introduces a screen for determining when assets acquired are not a business and clarifies that a business must include, at a minimum, an input and a substantive process that contribute to an output to be considered a business. This standard is effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period. The Company adopted ASU 2017-01 on January 1, 2018. On March 15, 2018, the Company completed an acquisition of proved and unproved properties from OneEnergy Partners, LLC (“OEP”) (See Note 5-Acquisitions and Divestitures). As a result of the adoption of ASU 2017-01, the Company accounted for the acquisition as an asset purchase instead of a business combination. As a result, acquisition costs of approximately $1.1 million were capitalized as part of the acquisition and the purchase price was allocated to unproved and proved properties based on relative fair value. On January 1, 2018, we retroactively adopted ASU No. 2016–18, Statement of Cash Flows (Topic 230) : Restricted Cash (a consensus of the FASB Emerging Issues Task Force).” This ASU requires the statements of cash flows to present the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents are now included with cash and cash equivalents when reconciling the beginning of period and end of period amounts presented on the statements of cash flows. The retrospective application of this new accounting guidance resulted in a decrease of $0.6 million in “restricted cash” in Cash Flows from Investing Activities, an increase of $0.6 million in “Cash, Cash Equivalents, and Restricted Cash, beginning of the period,” and an increase of $0.6 million in “Cash, Cash Equivalents, and Restricted Cash, end of period” in our accompanying condensed consolidated statement of cash flows for the six months ended June 30, 2017, from what was previously presented in our Quarterly Report on Form 10–Q for the quarterly period ended June 30, 2017. Recently Issued Accounting Pronouncements The Company considers the applicability and impact of all Accounting Standards Updates (“ASUs”). The ASUs listed below were assessed and determined to be either not applicable or are expected to have minimal impact on its consolidated financial position and/or results of operations. On February 25, 2016, the FASB issued ASU 2016-02, Leases (Topic 842) (ASU 2016-02) , which requires companies to recognize the assets and liabilities for the rights and obligations created by long-term leases of assets on the balance sheet. The guidance requires adoption by application of a modified retrospective transition approach for existing long-term leases and is effective for fiscal years beginning after December 15, 2018, including interim periods within those years. Oil and natural gas leases are scoped out of ASU 2016-02. The Company is currently gathering all lease and other agreements which may contain embedded leases to evaluate the impact that ASU 2016-02 would have on the Company’s consolidated financial statements. The Company expects that the adoption of ASU 2016-02 will likely increase the Company’s recorded assets and liabilities. As of June 30, 2018 , the Company is continuing to evaluate each of its lease arrangements and has not yet determined the aggregate impact on its consolidated financial statements.

SUMMARY OF SIGNIFICANT ACCOUN28

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND ESTIMATES (Tables)	6 Months Ended
	Jun. 30, 2018
Accounting Policies [Abstract]
New Accounting Pronouncement, Early Adoption	In accordance with the New Revenue Standard requirements, the impact of adoption on our condensed consolidated statements of operations and condensed consolidated balance sheets was as follows: For the three months ended June 30, 2018 As Reported Balances without Adoption of ASC 606 Increase (Decrease) Condensed Consolidated Statements of Operations: Revenues $ 17,483 $ 17,498 $ (15 ) Operating expenses $ (872 ) $ (887 ) $ (15 ) For the six months ended June 30, 2018 Condensed Consolidated Statements of Operations: Revenues $ 31,878 $ 31,943 $ (65 ) Operating expenses $ (1,334 ) $ (1,399 ) $ (65 ) As of June 30, 2018 Condensed Consolidated Balance Sheets: Accounts receivable $ 8,378 $ 8,443 $ (65 ) Accrued liabilities $ (394 ) $ (459 ) $ (65 )
Schedule of Accrued Liabilities	At June 30, 2018 and December 31, 2017 , the Company’s accrued liabilities consisted of the following: June 30, 2018 December 31, 2017 ($ in thousands) Accrued bonus $ 1,234 $ 3,000 Accrued capital expenditures 9,474 3,615 Other accrued liabilities 3,380 1,019 $ 14,088 $ 7,634

REVENUE (Tables)

REVENUE (Tables)	6 Months Ended
	Jun. 30, 2018
Revenues [Abstract]
Disaggregation of Revenue	The following table disaggregates the Company's revenue by contract type ( in thousands ): Three Months Ended Short-term contracts Long-term contracts Total Crude Oil $ 14,254 $ — $ 14,254 Natural Gas $ 145 $ 999 $ 1,144 NGLs $ 265 $ 1,820 $ 2,085 Six Months Ended Short-term contracts Long-term contracts Total Crude oil $ 26,843 $ — $ 26,843 Natural gas $ 524 $ 1,510 2,034 NGLs $ 774 $ 2,227 $ 3,001

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES (Tables)	6 Months Ended
	Jun. 30, 2018
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) not being amortized at June 30, 2018 and December 31, 2017 : June 30, 2018 December 31, 2017 (In thousands) Unproved unevaluated acreage: Beginning balance 101,771 $ 24,461 Lease purchases 86,181 78,110 Transfer and other reclassification to proved properties (19,593 ) (800 ) Total unproved acreage $ 168,359 $ 101,771 Wells in progress: Beginning balance $ — $ 7,453 Additions 625 — Reclassification to evaluated properties — (7,453 ) Total wells in progress not subject to DD&A $ 625 $ —

ACQUISITIONS AND DIVESTITURES (

ACQUISITIONS AND DIVESTITURES (Tables)	6 Months Ended
	Jun. 30, 2018
OEP Acquisition [Member]
Business Acquisition [Line Items]
Schedule of Business Acquisitions, by Acquisition	The purchase price and the value of the assets acquired in the OEP Acquisition were as follows: (in thousands, except per share amount) Cash $ 40,000 Common stock issued (6,940,722 shares at $3.57) 24,778 Transaction costs and purchase price adjustments 1,074 Total purchase price $ 65,852 Proved properties $ 4,168 Unproved properties 61,684 $ 65,852
VPD Texas, L.P. [Member]
Business Acquisition [Line Items]
Schedule of Business Acquisitions, by Acquisition	The purchase price and the value of the assets acquired in the VPD Acquisition were as follows: (in thousands, except per share amount) Cash purchase price $ 10,611 Proved properties $ 3,185 Unproved properties 7,426 $ 10,611

FAIR VALUE OF FINANCIAL INSTR32

FAIR VALUE OF FINANCIAL INSTRUMENTS (Tables)	6 Months Ended
	Jun. 30, 2018
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 June 30, 2018 Oil and natural gas derivative swap contracts $ — $ (2,106 ) $ — $ (2,106 ) Oil and natural gas derivative collar contracts — (2,899 ) — (2,899 ) Oil and natural gas derivative basis swap contracts — 910 — 910 Second Lien Term Loan conversion features — — (63,827 ) (63,827 ) Total $ — $ (4,095 ) $ (63,827 ) $ (67,922 ) As of December 31, 2017 Oil and natural gas derivative swap contracts $ — $ (706 ) $ — $ (706 ) Oil and natural gas derivative collar contracts — (147 ) — (147 ) Warrant liabilities — — (223 ) (223 ) Second Lien Term Loan conversion features — — (72,714 ) (72,714 ) Total $ — $ (853 ) $ (72,937 ) $ (73,790 )

ASSET RETIREMENT OBLIGATIONS 33

ASSET RETIREMENT OBLIGATIONS (ARO) (Tables)	6 Months Ended
	Jun. 30, 2018
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Asset Retirement Obligations	The following table summarizes the changes in the Company’s asset retirement obligations for the six months ended June 30, 2018 and year ended December 31, 2017: Six Months Ended June 30, 2018 Year Ended December 31, 2017 (In thousands) ARO, beginning of period $ 952 $ 1,257 Additional liabilities incurred 315 20 Accretion expense 48 82 Liabilities settled (87 ) (288 ) Revision in estimates (66 ) (119 ) 1,162 952 Less: current portion of ARO (63 ) (226 ) ARO, end of period $ 1,099 $ 726

DERIVATIVES (Tables)

DERIVATIVES (Tables)	6 Months Ended
	Jun. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value	The following table presents the Company’s derivative position for the production periods indicated as of June 30, 2018: Description Notional Volume (Bbls/d) Production Period Weighted Average Price ($/Bbl) Oil Swaps 900 July 2018 - December 2018 $ 57.68 Basis Swaps 1,500 July 2018 - December 2018 $ (5.62 ) Basis Swaps 1,500 January 2019 - December 2019 $ (5.62 ) Basis Swaps 1,500 January 2020 - December 2020 $ (5.62 ) 3 Way Collar Floor sold price (put) 1,252 January 2019 - December 2019 $ 45.00 3 Way Collar Floor purchase price (put) 1,252 January 2019 - December 2019 $55.00 3 Way Collar Ceiling sold price (call) 1,252 January 2019 - December 2019 $70.61 Oil Collar Floor purchase price (put) 1,763 July 2018 - December 2018 $ 58.35 Oil Collar Ceiling sold price (call) 1,763 July 2018 - December 2018 $69.86 Oil Collar Floor purchase price (put) 1,000 January 2019 - June 2019 $52.50 Oil Collar Ceiling sold price (call) 1,000 January 2019 - June 2019 $67.60 Six Months Ended Year Ended (in thousands) Beginning fair value of commodity derivatives $ (853 ) $ — Change in fair value of derivative instruments (4,572 ) (1,063 ) Net settlements paid on crude oil derivative contracts 1,710 96 Change in settlements accrued on crude oil derivative contracts (383 ) 114 Ending fair value of commodity derivatives, net $ (4,098 ) $ (853 )
Schedule of Derivative Instruments	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 condensed consolidated balance sheets: As of June 30, 2018 Gross Amount of Recognized Assets and Liabilities Gross Amounts Offset in the Condensed Consolidated Balance Sheets Net Amounts Presented in the Condensed Consolidated Balance Sheets (in thousands) Offsetting Derivative Assets: Current asset $ 3,249 $ (1,474 ) $ 1,775 Long-term asset — — — Total asset $ 3,249 $ (1,474 ) $ 1,775 Offsetting Derivative Liabilities: Current liability $ 4,444 $ (1,457 ) $ 2,987 Long-term liability 2,738 148 2,886 Total liability $ 7,182 $ (1,309 ) $ 5,873 As of December 31, 2017 Gross Amount of Recognized Assets and Liabilities Gross Amounts Offset in the Condensed Consolidated Balance Sheets Net Amounts Presented in the Condensed Consolidated Balance Sheets (in thousands) Offsetting Derivative Assets: Current asset $ — $ — $ — Long-term asset — — — Total asset $ — $ — $ — Offsetting Derivative Liabilities: Current liability $ 853 $ — $ 853 Long-term liability — — — Total liability $ 853 $ — $ 853

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	6 Months Ended
	Jun. 30, 2018
Debt Disclosure [Abstract]
Schedule of long-term debt instruments	June 30, 2018 December 31, 2017 (In thousands) Riverstone First Lien Loans associated with the Amended and Restated Senior Secured Term Loan Credit Agreement, due 2021, net of debt issuance costs and debt discount $ 47,805 $ — 6% Bridge Loans associated with the amended First Lien Term Loan, due 2019, net of debt issuance costs — 30,363 8.25% Second Lien Term Loans, due 2021, net of debt issuance costs and debt discount 110,743 96,431 6% note payable to SOS Investment, LLC, due 2019 — 1,000 Other notes payable, due 2018 5 11 Total long-term debt $ 158,553 $ 127,805 Less: current portion (5 ) (11 ) Total long-term debt, net of current portion $ 158,548 $ 127,794
Schedule of debt	As of June 30, 2018 and December 31, 2017 , the carrying amounts of the Company's Riverstone First Lien Loans and Second Lien Term Loans were as follows (in thousands) : Principal Amount Paid-in- kind Interest Unamortized Debt Issuance Costs & Debt Discount Carrying Amount June 30, 2018: Riverstone First Lien Loans, due January 2021 $ 50,000 $ — $ (2,195 ) $ 47,805 Second Lien Term Loans, due April 2021 150,000 12,189 (51,446 ) 110,743 Total: $ 200,000 $ 12,189 $ (53,641 ) $ 158,548 December 31, 2017: Bridge Loans associated with the amended First Lien Term Loan, due September 2019 $ 30,000 $ 807 $ (444 ) $ 30,363 Second Lien Term Loans, due April 2021 150,000 5,752 (59,321 ) 96,431 Total: $ 180,000 $ 6,559 $ (59,765 ) $ 126,794
Schedule Of Interest Expenses	The components of interest expense are as follows ( in thousands) : Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Interest on term loans $ 1,078 $ 330 $ 2,538 $ 847 Interest on notes payable — 15 — 29 Paid-in-kind interest on term loans 3,269 1,341 6,437 1,341 Amortization of debt financing costs 262 1,495 881 1,622 Amortization of discount on term loans 3,963 3,473 7,804 3,588 Total $ 8,572 $ 6,654 $ 17,660 $ 7,427

RELATED PARTY TRANSACTIONS (Tab

RELATED PARTY TRANSACTIONS (Tables)	6 Months Ended
	Jun. 30, 2018
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	During the six months ended June 30, 2018 and 2017 , the Company was engaged in the following transactions, which occurred during the first quarters of 2018 and 2017, with certain related parties: Six Months Ended June 30, Related Party Transactions 2018 2017 ($ in thousands) Directors and Officers: Brennan Short (former Chief Operating Officer) Consulting fees paid to MMZ Consulting, Inc. (“MMZ”) which is owned by Mr. Short. Mr. Short is the sole member of MMZ. $ — $ 204 Total: $ — $ 204 Kevin Nanke (former Chief Financial Officer) Purchased the DJ Basin properties from the Company through Nanke Energy, LLC $ — $ 2,000 Total: $ — $ 2,000 Värde Partners, Inc. (“Värde”) (1) The Company acquired oil and natural gas interests from VPD, an affiliate of Värde $ 10,611 $ — $ 10,611 $ — (1) Värde is the lead lender in the Company’s Second Lien Loans (see Note 9 – Long-term Debts) and also participated in the issuance of Series C 9.75% Convertible Preferred Stock in January 2018 (see Note 11 – Shareholders’ Equity and Redeemable Preferred Stock).

SHAREHOLDERS_ EQUITY AND REDE37

SHAREHOLDERS’ EQUITY AND REDEEMABLE PREFERRED STOCK (Tables)	6 Months Ended
	Jun. 30, 2018
Equity [Abstract]
Summary of warrant activity	The following table provides a summary of warrant activity for the six months ended June 30, 2018 : Warrants Weighted- Average Exercise Price Outstanding at January 1, 2018 11,882,800 $ 3.46 Exercised (2,848,440 ) $ 2.50 Expired or canceled (2,324,304 ) $ 3.84 Outstanding at June 30, 2018 6,710,056 $ 3.27

SHARE BASED AND OTHER COMPENS38

SHARE BASED AND OTHER COMPENSATION (Tables)	6 Months Ended
	Jun. 30, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of Share-based Compensation, Activity	The Company’s share-based compensation consisted of the following (dollars in thousands): Six Months Ended June 30, 2018 Six Months Ended June 30, 2017 Stock Options Restricted Stock Total Stock Options Restricted Stock Total Share-based compensation expensed $ 1,238 $ 4,316 $ 5,554 $ 3,273 $ 6,113 $ 9,386 Unrecognized share-based compensation costs $ 1,346 $ 4,777 $ 6,123 $ 7,669 $ 2,094 $ 9,763 Weighted average amortization period remaining (in years) 0.56 0.63 1.19 0.82 0.74 1.56
Schedule of Share-based Compensation, Restricted Stock Units Award Activity	A summary of restricted stock grant activity pursuant to the Lilis Energy, Inc. 2012 Omnibus Incentive Plan (the “2012 Plan”) and the 2016 Omnibus Incentive Plan (the “2016 Plan”) for the six months ended June 30, 2018 , is presented below: Number of Shares Weighted Average Grant Date Price Outstanding at January 1, 2018 2,475,266 $ 4.22 Granted 799,944 $ 4.28 Vested and issued (654,946 ) $ (4.06 ) Forfeited or canceled (1) (847,898 ) $ (4.88 ) Outstanding at June 30, 2018 1,772,366 $ 3.93 Restricted Stock Units A summary of restricted stock unit grant activity pursuant to the 2012 Plan for the six months ended June 30, 2018 , is presented below: Number of Shares Weighted Average Grant Date Price Outstanding at January 1, 2018 9,999 $ 6.57 Vested and issued (9,999 ) $ (6.57 ) Outstanding at June 30, 2018 — $ —
Schedule of Share-based Compensation, Stock Options, Activity	A summary of stock option activity pursuant to the 2016 Plan for the six months ended June 30, 2018 , is presented below: Stock Options Outstanding and Exercisable 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 $ 3.82 Exercised (675,500 ) $ (1.66 ) Forfeited or canceled (1) (1,480,850 ) $ (4.20 ) Outstanding at June 30, 2018 5,501,150 $ 3.68 4,201,200 8.4 (1) Forfeitures are accounted for as and when incurred.
Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions	The Company used the following weighted average of each assumption based on the grants in each fiscal year: 2018 Expected Term in Years 6 Expected Volatility 58.8% - 72.6% Expected Dividends — % Risk-Free Interest Rate 2.59% - 2.71%

LOSS PER COMMON SHARE (Tables)

LOSS PER COMMON SHARE (Tables)	6 Months Ended
	Jun. 30, 2018
Earnings Per Share [Abstract]
Schedule of basic and diluted earnings per share	The following table shows the computation of basic and diluted net loss per share for the three and six months ended June 30, 2018 and 2017 (in thousands) : Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Net loss $ (31,208 ) (23,148 ) $ (18,962 ) $ (31,904 ) Less: dividends on redeemable preferred stock — (92 ) — (122 ) Less: dividends and deemed dividends on Series B convertible preferred stock — (4,422 ) — (4,635 ) Less: dividends on Series C convertible preferred stock (2,465 ) — (4,117 ) — Net loss attributable to common stockholders $ (33,673 ) $ (27,662 ) $ (23,079 ) $ (36,661 ) Weighted average common shares outstanding - basic and diluted 64,098,309 44,332,270 57,801,098 34,282,784 Net loss per common share – basic and diluted $ (0.53 ) $ (0.62 ) $ (0.40 ) $ (1.07 )
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	The Company excluded the following shares from the diluted loss per share calculations above because they were anti-dilutive for the three and six months ended June 30, 2018 and 2017 : 2018 2017 Stock Options 5,501,150 7,158,500 Restricted Stock Units — 9,999 Series C Preferred Stock 20,312,607 — Stock Purchase Warrants 6,710,056 12,523,045 Conversion of Term Loans 23,970,219 13,572,950 56,494,032 33,264,494

SUPPLEMENTAL NON-CASH TRANSAC40

SUPPLEMENTAL NON-CASH TRANSACTIONS (Tables)	6 Months Ended
	Jun. 30, 2018
Supplemental Cash Flow Elements [Abstract]
Schedule of Cash Flow, Supplemental Disclosures	The following table presents the supplemental disclosure of cash flow information for the six months ended June 30, 2018 and 2017 : Six Months Ended June 30, 2018 2018 2017 ($ in thousands) Non-cash investing and financing activities excluded from the statement of cash flows: Conversion of Series B Preferred Stock and accrued dividends to common stock — 14,087 Fair value of warrants issued and repriced as debt discount — 1,031 Common stock issued for acquisition of oil and gas properties 24,778 — Common stock issued for commitment fees associated with Private Placement — 250 Cashless exercise of warrants — 371 Change in capital expenditures for drilling costs in accrued liabilities 5,859 871 Accrued dividends for Series C Preferred Stock 4,117 — Change in asset retirement obligations 66 — Issuance of common stock for drilling services — 96 Increase in final settlement on the divestiture of DJ Basin properties in accrued liabilities — 584 Deemed dividends on Series B 6% Convertible Preferred Stock associated with beneficial conversion features — 3,767 Fair value of derivative liabilities associated with conversion features of Second Lien Term Loan — 36,741

SUMMARY OF SIGNIFICANT ACCOUN41

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND ESTIMATES (Details Textual) - USD ($)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017	Mar. 15, 2018
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	$ (17,483,000)	$ (5,305,000)	$ (31,878,000)	$ (8,387,000)
Operating expenses	(872,000)		(1,334,000)
Decrease in net cash used in investing activities			(145,980,000)	(39,843,000)
Capitalized costs, proved and unproved properties						$ 1,100,000
Cash, cash equivalents and restricted cash at beginning of period			17,462,000	11,738,000	$ 11,738,000
Cash, cash equivalents and restricted cash at end of period	27,398,000	42,739,000	27,398,000	42,739,000	17,462,000
Restatement Adjustment [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenues		120,000		270,000
Operating expenses		(120,000)		(270,000)
Decrease in net cash used in investing activities		$ (600,000)		$ (600,000)
Cash, cash equivalents and restricted cash at end of period	600,000		600,000
Accounting Standards Update 2014-09 [Member] | Difference between Revenue Guidance in Effect before and after Topic 606 [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	15,000		65,000
Operating expenses	$ (15,000)		(65,000)
Accounting Standards Update 2016-18 [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Decrease in net cash used in investing activities					600,000
Cash, cash equivalents and restricted cash at beginning of period			$ 600,000
Cash, cash equivalents and restricted cash at end of period					$ 600,000

SUMMARY OF SIGNIFICANT ACCOUN42

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND ESTIMATES (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Condensed Consolidated Statements of Operations:
Revenues	$ 17,483,000	$ 5,305,000	$ 31,878,000	$ 8,387,000
Operating expenses	(872,000)		(1,334,000)
Condensed Consolidated Balance Sheets:
Accounts receivable	8,378,000		8,378,000
Accrued liabilities	(394,000)		(394,000)
Calculated under Revenue Guidance in Effect before Topic 606 [Member]
Condensed Consolidated Statements of Operations:
Revenues	17,498,000		31,943,000
Operating expenses	(887,000)		(1,399,000)
Condensed Consolidated Balance Sheets:
Accounts receivable	8,443,000		8,443,000
Accrued liabilities	(459,000)		(459,000)
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member]
Condensed Consolidated Statements of Operations:
Revenues	(15,000)		(65,000)
Operating expenses	(15,000)		(65,000)
Condensed Consolidated Balance Sheets:
Accounts receivable	(65,000)		(65,000)
Accrued liabilities	$ (65,000)		$ (65,000)

SUMMARY OF SIGNIFICANT ACCOUN43

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND ESTIMATES (Details 1) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Accounting Policies [Abstract]
Accrued bonus	$ 1,234	$ 3,000
Accrued capital expenditures	9,474	3,615
Other accrued liabilities	3,380	1,019
Total accrued liabilities	$ 14,088	$ 7,634

REVENUE (Details Textual)

REVENUE (Details Textual) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018USD ($)	Jun. 30, 2017	Jun. 30, 2018USD ($)	Jun. 30, 2017	Feb. 28, 2019$ / bbl
Disaggregation of Revenue [Line Items]
Receivables from customers	$ 8.4		$ 8.4
Receivables from joint interest partners	5		5
Accrued unbilled receivables	$ 4.2		$ 4.2
Scenario, Forecast [Member]
Disaggregation of Revenue [Line Items]
Crude oil price differential (in dollars per barrel) | $ / bbl					5.15
Texican Crude & Hydrocarbons, LLC [Member]
Disaggregation of Revenue [Line Items]
Percentage of revenue	86.00%	79.00%	86.00%	78.00%
Lucid Energy Delaware, LLC [Member]
Disaggregation of Revenue [Line Items]
Percentage of revenue	12.00%		10.00%
ETC Field Services LLC [Member]
Disaggregation of Revenue [Line Items]
Percentage of revenue	2.00%	21.00%	4.00%	22.00%

REVENUE (Details)

REVENUE (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Disaggregation of Revenue [Line Items]
Revenues	$ 17,483	$ 5,305	$ 31,878	$ 8,387
Crude Oil [Member]
Disaggregation of Revenue [Line Items]
Revenues	14,254		26,843
Crude Oil [Member] | Short term contract [Member]
Disaggregation of Revenue [Line Items]
Revenues	14,254		26,843
Crude Oil [Member] | Long-term contracts [Member]
Disaggregation of Revenue [Line Items]
Revenues	0		0
Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenues	1,144	538	2,034	1,039
Natural Gas [Member] | Short term contract [Member]
Disaggregation of Revenue [Line Items]
Revenues	145		524
Natural Gas [Member] | Long-term contracts [Member]
Disaggregation of Revenue [Line Items]
Revenues	999		1,510
Natural Gas Liquids [Member]
Disaggregation of Revenue [Line Items]
Revenues	2,085	$ 600	3,001	$ 686
Natural Gas Liquids [Member] | Short term contract [Member]
Disaggregation of Revenue [Line Items]
Revenues	265		774
Natural Gas Liquids [Member] | Long-term contracts [Member]
Disaggregation of Revenue [Line Items]
Revenues	$ 1,820		$ 2,227

OIL AND NATURAL GAS PROPERTIE46

OIL AND NATURAL GAS PROPERTIES (Details Textual) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Extractive Industries [Abstract]
Reserved ceiling value for oil (USD per barrel)	$ 57.67		$ 57.67
Reserved ceiling value for natural gas (USD per MMBtu)	2.92		2.92
Reserved ceiling value for NGLs (USD per barrel)	54.79		54.79
Results of operations, impairment of oil and gas properties		$ 0	11,100,000	$ 0
Depreciation, depletion, amortization and accretion expense to proved properties	$ 5,800,000	$ 1,400,000	$ 10,400,000	$ 2,504,000

OIL AND NATURAL GAS PROPERTIE47

OIL AND NATURAL GAS PROPERTIES (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Unproved unevaluated acreage:
Beginning balance	$ 101,771	$ 24,461
Lease purchases	86,181	78,110
Transfer and other reclassification to proved properties	(19,593)	(800)
Total unproved acreage	168,359	101,771
Wells in progress:
Beginning balance	0	7,453
Additions	625	0
Reclassification to evaluated properties	0	(7,453)
Total wells in progress not subject to DD&A	$ 625	$ 0

ACQUISITIONS AND DIVESTITURES48

ACQUISITIONS AND DIVESTITURES (Details Textual) $ in Thousands	Mar. 15, 2018USD ($)shares	Mar. 03, 2018USD ($)	Feb. 28, 2018USD ($)	Jun. 30, 2017USD ($)	Jan. 30, 2018USD ($)shares	Dec. 31, 2017USD ($)	Dec. 31, 2019Well	Dec. 31, 2018Well
OneEnergy Partners Operating, LLC [Member]
Business Acquisition [Line Items]
Capital expenditures incurred but not yet paid					$ 70,000
Cash	$ 40,000				$ 40,000
Business acquisition, equity interest issued or issuable (in shares) | shares	6,940,722				6,940,722
Common stock issued (6,940,722 shares at $3.57)	$ 24,800				$ 24,778
Business acquisition purchase price before acquisition costs and customary purchase price adjustments	$ 64,900
Transaction costs and purchase price adjustments					1,074
Total purchase price					$ 65,852
VPD Texas, L.P. [Member]
Business Acquisition [Line Items]
Cash			$ 10,611
Transaction costs and purchase price adjustments			500
Total purchase price			$ 11,100
Anadarko [Member]
Business Acquisition [Line Items]
Total purchase price		$ 7,100
KEW Drilling [Member]
Business Acquisition [Line Items]
Cash						$ 48,900
Transaction costs and purchase price adjustments						800
Total purchase price						$ 49,700
DJ Basin [Member]
Business Acquisition [Line Items]
Disposal of oil and gas property and equipment, consideration				$ 2,000
Proceeds from sale of oil and gas property and equipment				1,080
Severance costs				700
Net sale adjustment amount due to purchaser				$ 220
Subsequent Event [Member] | VPD Texas, L.P. [Member]
Business Acquisition [Line Items]
Number of horizontal wells | Well							2	2

ACQUISITIONS AND DIVESTITURES49

ACQUISITIONS AND DIVESTITURES (Details) - USD ($) $ / shares in Units, $ in Thousands	Mar. 15, 2018	Feb. 28, 2018	Jan. 30, 2018
OneEnergy Partners Operating, LLC [Member]
Business Acquisition [Line Items]
Cash	$ 40,000		$ 40,000
Common stock issued (6,940,722 shares at $3.57)	$ 24,800		24,778
Transaction costs and purchase price adjustments			1,074
Value of assets acquired			$ 65,852
Business acquisition, equity interest issued or issuable (in shares)	6,940,722		6,940,722
Shares issued (in dollars per share)			$ 3.57
OneEnergy Partners Operating, LLC [Member] | Proved Properties [Member]
Business Acquisition [Line Items]
Value of assets acquired			$ 4,168
OneEnergy Partners Operating, LLC [Member] | Unproved Properties [Member]
Business Acquisition [Line Items]
Value of assets acquired			$ 61,684
VPD Texas, L.P. [Member]
Business Acquisition [Line Items]
Cash		$ 10,611
Transaction costs and purchase price adjustments		500
Value of assets acquired		10,611
VPD Texas, L.P. [Member] | Proved Properties [Member]
Business Acquisition [Line Items]
Value of assets acquired		3,185
VPD Texas, L.P. [Member] | Unproved Properties [Member]
Business Acquisition [Line Items]
Value of assets acquired		$ 7,426

FAIR VALUE OF FINANCIAL INSTR50

FAIR VALUE OF FINANCIAL INSTRUMENTS (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements	$ (5,873)	$ (853)
Total recurring fair value measurements	(67,922)	(73,790)
Oil and natural gas derivative swap contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements	(2,106)	(706)
Oil and natural gas derivative collar contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements	(2,899)	(147)
Basis Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements	910
Warrant liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements		(223)
Second Lien Term Loan conversion features [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements	(63,827)	(72,714)
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total recurring fair value measurements	0	0
Fair Value, Inputs, Level 1 [Member] | Oil and natural gas derivative swap contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements	0	0
Fair Value, Inputs, Level 1 [Member] | Oil and natural gas derivative collar contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements	0	0
Fair Value, Inputs, Level 1 [Member] | Basis Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements	0
Fair Value, Inputs, Level 1 [Member] | Warrant liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements		0
Fair Value, Inputs, Level 1 [Member] | Second Lien Term Loan conversion features [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements	0	0
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total recurring fair value measurements	(4,095)	(853)
Fair Value, Inputs, Level 2 [Member] | Oil and natural gas derivative swap contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements	(2,106)	(706)
Fair Value, Inputs, Level 2 [Member] | Oil and natural gas derivative collar contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements	(2,899)	(147)
Fair Value, Inputs, Level 2 [Member] | Basis Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements	910
Fair Value, Inputs, Level 2 [Member] | Warrant liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements		0
Fair Value, Inputs, Level 2 [Member] | Second Lien Term Loan conversion features [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements	0	0
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total recurring fair value measurements	(63,827)	(72,937)
Fair Value, Inputs, Level 3 [Member] | Oil and natural gas derivative swap contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements	0	0
Fair Value, Inputs, Level 3 [Member] | Oil and natural gas derivative collar contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements	0	0
Fair Value, Inputs, Level 3 [Member] | Basis Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements	0
Fair Value, Inputs, Level 3 [Member] | Warrant liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements		(223)
Fair Value, Inputs, Level 3 [Member] | Second Lien Term Loan conversion features [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Recurring fair value measurements	$ (63,827)	$ (72,714)

FAIR VALUE OF FINANCIAL INSTR51

FAIR VALUE OF FINANCIAL INSTRUMENTS (Details Textual) - USD ($) $ / shares in Units, $ in Thousands	Jan. 31, 2018	Jun. 23, 2016	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017	Apr. 26, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Basis spread on discount rate								0.50%
Derivative liability			$ 5,873		$ 5,873		$ 853
Unrealized gain (loss) on derivatives			19,500	$ 0	8,900	$ 0
Current liabilities			49,715		49,715		25,435
Stockholders’ equity			(22,905)		(22,905)		(30,948)
SOS Warrant [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liability			$ 63,800		$ 63,800		72,700
Warrants issued to related parties (in shares)		200,000
Class of warrant or right, exercise price of warrants or rights (in dollars per share)		$ 25
Current liabilities				$ 300		$ 300	200
Accounting Standards Update 2017-11 [Member] | Restatement Adjustment [Member] | SOS Warrant [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Current liabilities							200
Stockholders’ equity							$ 200
Conversion To Newly Issued Shares [Member] | Second Lien Term Loan [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Conversion percentage of principal amount	70.00%

ASSET RETIREMENT OBLIGATIONS 52

ASSET RETIREMENT OBLIGATIONS (ARO) (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO, beginning of period	$ 952	$ 1,257
Additional liabilities incurred	315	20
Accretion expense	48	82
Liabilities settled	(87)	(288)
Revision in estimates	(66)	(119)
Balance, end of year	1,162	952
Less: current portion of ARO	(63)	(226)
ARO, end of period	$ 1,099	$ 726

DERIVATIVES (Details Textual)

DERIVATIVES (Details Textual) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Derivative [Line Items]
Derivative liability	$ 5,873		$ 5,873		$ 853
Unrealized gain (loss) on derivatives	19,500	$ 0	8,900	$ 0
SOS Warrant [Member]
Derivative [Line Items]
Derivative liability	$ 63,800		$ 63,800		$ 72,700

DERIVATIVES (Details)

DERIVATIVES (Details)	6 Months Ended
	Jun. 30, 2018bbl$ / bbl
Oil Swaps July 2018 to December 2018 [Member]
Derivative [Line Items]
Notional Volume (Bbls/Day) | bbl	900
Weighted Average Price ($/Bbl) | $ / bbl	57.68
Basis Swaps July 2018 to December 2018 [Member]
Derivative [Line Items]
Notional Volume (Bbls/Day) | bbl	1,500
Weighted Average Price ($/Bbl) | $ / bbl	(5.62)
Basis Swaps January 2019 to December 2019 [Member]
Derivative [Line Items]
Notional Volume (Bbls/Day) | bbl	1,500
Weighted Average Price ($/Bbl) | $ / bbl	(5.62)
Basis Swaps January 2020 to December 2020 [Member]
Derivative [Line Items]
Notional Volume (Bbls/Day) | bbl	1,500
Weighted Average Price ($/Bbl) | $ / bbl	(5.62)
Three Way Collar - Floor Sold Price January 2019 to December 2019 [Member]
Derivative [Line Items]
Notional Volume (Bbls/Day) | bbl	1,252
Weighted Average Price ($/Bbl) | $ / bbl	45
Three Way Collar - Floor Purchase Price January 2019 to December 2019 [Member]
Derivative [Line Items]
Notional Volume (Bbls/Day) | bbl	1,252
Weighted Average Price ($/Bbl) | $ / bbl	55
Three Way Collar - Ceiling Sold Price January 2019 to December 2019 [Member]
Derivative [Line Items]
Notional Volume (Bbls/Day) | bbl	1,252
Weighted Average Price ($/Bbl) | $ / bbl	70.61
Oil Collar - Floor Purchase Price July 2018 to December 2018 [Member]
Derivative [Line Items]
Notional Volume (Bbls/Day) | bbl	1,763
Weighted Average Price ($/Bbl) | $ / bbl	58.35
Oil Collar - Ceiling Sold Price July 2018 to December 2018 [Member]
Derivative [Line Items]
Notional Volume (Bbls/Day) | bbl	1,763
Weighted Average Price ($/Bbl) | $ / bbl	69.86
Oil Caller - Floor Purchase Price January 2019 to June 2019 [Member]
Derivative [Line Items]
Notional Volume (Bbls/Day) | bbl	1,000
Weighted Average Price ($/Bbl) | $ / bbl	52.50
Oil Caller - Ceiling Sold Price January 2019 to June 2019 [Member]
Derivative [Line Items]
Notional Volume (Bbls/Day) | bbl	1,000
Weighted Average Price ($/Bbl) | $ / bbl	67.60

DERIVATIVES (Details 1)

DERIVATIVES (Details 1) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Commodity Derivatives, Fair Value [Roll Forward]
Beginning fair value of commodity derivatives	$ (853)	$ 0
Change in fair value of derivative instruments	(4,572)	(1,063)
Net settlements paid on crude oil derivative contracts	1,710	96
Change in settlements accrued on crude oil derivative contracts	(383)	114
Ending fair value of commodity derivatives, net	$ (4,098)	$ (853)

DERIVATIVES (Details 2)

DERIVATIVES (Details 2) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Gross amount of recognized offsetting derivative assets	$ 3,249	$ 0
Gross amounts of offsetting derivative assets in the condensed consolidated balance sheets	(1,474)	0
Net amounts of offsetting derivative assets presented in the condensed consolidated balance sheets	1,775	0
Gross amount of recognized offsetting derivative liabilities	7,182	853
Gross amounts of offsetting derivative liabilities in the condensed consolidated balance sheets	(1,309)	0
Net amounts of offsetting derivative liabilities presented in the condensed consolidated balance sheets	5,873	853
Current liability [Member]
Derivatives, Fair Value [Line Items]
Gross amount of recognized offsetting derivative liabilities	4,444	853
Gross amounts of offsetting derivative liabilities in the condensed consolidated balance sheets	(1,457)	0
Net amounts of offsetting derivative liabilities presented in the condensed consolidated balance sheets	2,987	853
Long-term liability [Member]
Derivatives, Fair Value [Line Items]
Gross amount of recognized offsetting derivative liabilities	2,738	0
Gross amounts of offsetting derivative liabilities in the condensed consolidated balance sheets	148	0
Net amounts of offsetting derivative liabilities presented in the condensed consolidated balance sheets	2,886	0
Current asset [Member]
Derivatives, Fair Value [Line Items]
Gross amount of recognized offsetting derivative assets	3,249	0
Gross amounts of offsetting derivative assets in the condensed consolidated balance sheets	(1,474)	0
Net amounts of offsetting derivative assets presented in the condensed consolidated balance sheets	1,775	0
Long-term asset [Member]
Derivatives, Fair Value [Line Items]
Gross amount of recognized offsetting derivative assets	0	0
Gross amounts of offsetting derivative assets in the condensed consolidated balance sheets	0	0
Net amounts of offsetting derivative assets presented in the condensed consolidated balance sheets	$ 0	$ 0

LONG-TERM DEBT (Details)

LONG-TERM DEBT (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017	Apr. 26, 2017
Debt Instrument [Line Items]
Total long-term debt	$ 158,553	$ 127,805
Less: current portion	(5)	(11)
Long-term debt, less current maturities	158,548	127,794
Riverstone First Lien Loans [Member]
Debt Instrument [Line Items]
Total long-term debt	47,805	0
Term Loan [Member]
Debt Instrument [Line Items]
Long-term debt, less current maturities	158,548	126,794
Term Loan [Member] | Riverstone First Lien Loans [Member]
Debt Instrument [Line Items]
Long-term debt, less current maturities	47,805
Term Loan [Member] | 6% Bridge Loans associated with the amended First Lien Term Loan, due 2019, net of debt issuance costs
Debt Instrument [Line Items]
Total long-term debt	0	30,363
Term Loan [Member] | 8.25% Second Lien Term Loans, due 2021, net of debt issuance costs and debt discount
Debt Instrument [Line Items]
Total long-term debt	110,743	96,431
Term Loan [Member] | 6% note payable to SOS Investment, LLC, due 2019
Debt Instrument [Line Items]
Total long-term debt	0	1,000
Convertible Debenture [Member] | Other notes payable, due 2018
Debt Instrument [Line Items]
Total long-term debt	$ 5	$ 11
Bridge Loan [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	6.00%	6.00%
Second Lien Credit Agreement [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	8.25%	8.25%	8.25%
6% note payable to SOS Investment, LLC, due 2019
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	6.00%	6.00%

LONG-TERM DEBT (Details 1)

LONG-TERM DEBT (Details 1) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Debt Instrument [Line Items]
Payable in-kind interest	$ 3,269	$ 1,341	$ 6,437	$ 1,341
Carrying Amount	158,548		158,548		$ 127,794
Term Loan [Member]
Debt Instrument [Line Items]
Principal Amount	200,000		200,000		180,000
Payable in-kind interest			12,189		6,559
Unamortized Debt Issuance Costs & Debt Discount	(53,641)		(53,641)		(59,765)
Carrying Amount	158,548		158,548		126,794
Term Loan [Member] | Riverstone First Lien Loans [Member]
Debt Instrument [Line Items]
Principal Amount	50,000		50,000
Payable in-kind interest			0
Unamortized Debt Issuance Costs & Debt Discount	(2,195)		(2,195)
Carrying Amount	47,805		47,805
Term Loan [Member] | Bridge Loan [Member]
Debt Instrument [Line Items]
Principal Amount					30,000
Payable in-kind interest					807
Unamortized Debt Issuance Costs & Debt Discount					(444)
Carrying Amount					30,363
Term Loan [Member] | Second Lien Term Loans [Member]
Debt Instrument [Line Items]
Principal Amount	150,000		150,000		150,000
Payable in-kind interest			12,189		5,752
Unamortized Debt Issuance Costs & Debt Discount	(51,446)		(51,446)		(59,321)
Carrying Amount	$ 110,743		$ 110,743		$ 96,431

LONG-TERM DEBT (Details Textual

LONG-TERM DEBT (Details Textual)	Jan. 31, 2018memberday$ / shares	Jan. 30, 2018USD ($)member	Nov. 10, 2017USD ($)	Apr. 26, 2017USD ($)	Apr. 26, 2017USD ($)	Jun. 30, 2018USD ($)	Jun. 30, 2017USD ($)	Feb. 20, 2018USD ($)	Dec. 31, 2017	Oct. 04, 2017USD ($)
Debt Instrument [Line Items]
Debt instrument, description					Each tranche of the Second Lien Loans is separately convertible at any time, in full and not in part, at the option of the Lead Lender, as follows:   ⋅ 70% of the principal amount of each tranche of Second Lien Loans, together with accrued and unpaid interest and the make-whole premium on such principal amount, will convert into a number of newly issued shares of 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   ⋅ 30% of the principal amount of each tranche of Second Lien Loans, together with accrued and unpaid interest and the make-whole premium on such principal amount, will convert on a dollar for dollar basis into a new term loan (the “Take Back Loans”). The terms of the Take Back Loans will be substantially the same as the terms of the Second Lien Loans, except that the Take Back Loans will not be convertible and will bear interest payable in cash at a rate of LIBOR plus 9% (subject to a 1% LIBOR floor).
Repayments of Debt						$ 31,821,000	$ 40,385,000
Stock repurchase program, authorized amount								$ 10,000,000
First Lien Credit Agreement [Member]
Debt Instrument [Line Items]
Debt instrument, face amount		$ 50,000,000
Original issue discount percentage		1.00%
Debt instrument, additional maximum face amount		$ 30,000,000
Repayments of Debt		$ 31,500,000
Second Lien Credit Agreement [Member]
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity				$ 125,000,000	$ 125,000,000					$ 45,000,000
Debt instrument, interest rate, stated percentage				8.25%	8.25%	8.25%			8.25%
Line of credit facility, increase in borrowing capacity			$ 25,000,000
Line of credit facility additional borrowing capacity			25,000,000
Proceeds from lines of credit			$ 25,000,000
Take Back Loans [Member]
Debt Instrument [Line Items]
Debt instrument, convertible, threshold percentage of stock price trigger				150.00%
Debt instrument, description of variable rate basis				LIBOR plus 9% (subject to a 1% LIBOR floor).
Second Lien Term Loan [Member]
Debt Instrument [Line Items]
Number of members of the Board of Directors | member	1	2
Debt instrument, maturity date				Apr. 26, 2021
Proceeds reinvested, threshold days | day	180
Debt instrument, convertible, threshold percentage of stock price trigger				110.00%
Second Lien Term Loan [Member] | Second Lien Credit Agreement [Member]
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity				$ 80,000,000	$ 80,000,000
Delayed Draw Loans [Member] | Second Lien Credit Agreement [Member]
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity				$ 45,000,000	$ 45,000,000
Minimum [Member] | Second Lien Term Loan [Member]
Debt Instrument [Line Items]
Threshold trading days | day	20
Maximum [Member] | Second Lien Term Loan [Member]
Debt Instrument [Line Items]
Threshold trading days | day	30
Conversion To Newly Issued Shares [Member] | Second Lien Term Loan [Member]
Debt Instrument [Line Items]
Conversion percentage of principal amount	70.00%
Conversion price | $ / shares	$ 5.50
Conversion To New Term Loan [Member] | Second Lien Term Loan [Member]
Debt Instrument [Line Items]
Conversion percentage of principal amount	30.00%
Take Back Loans [Member]
Debt Instrument [Line Items]
LIBOR basis spread	9.00%
Take Back Loans [Member] | Minimum [Member]
Debt Instrument [Line Items]
LIBOR basis spread	1.00%

LONG-TERM DEBT (Details 2)

LONG-TERM DEBT (Details 2) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Debt Disclosure [Abstract]
Interest on term loans	$ 1,078	$ 330	$ 2,538	$ 847
Interest on notes payable	0	15	0	29
Paid-in-kind interest on term loans	3,269	1,341	6,437	1,341
Amortization of debt financing costs	262	1,495	881	1,622
Amortization of discount on term loans	3,963	3,473	7,804	3,588
Total	$ 8,572	$ 6,654	$ 17,660	$ 7,427

LONG-TERM DEFERRED REVENUE (Det

LONG-TERM DEFERRED REVENUE (Details) $ in Millions	6 Months Ended
	Jun. 30, 2018USD ($)
Revenue from Contract with Customer [Abstract]
Contract with customer, term	12 years
Deferred revenue	$ 35

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details) - USD ($)	Jan. 30, 2018	Jun. 30, 2018	Jun. 30, 2018	Jun. 30, 2017
Related Party Transaction [Line Items]
Related party transactions		$ 0
Brennan Short [Member]
Related Party Transaction [Line Items]
Payment for consulting fees			$ 0	$ 204,000
Proceeds from (repayments of) related party debt			0	204,000
Värde Partners, Inc. [Member]
Related Party Transaction [Line Items]
Proceeds from (repayments of) related party debt			10,611,000	0
Payments to acquire businesses, gross			10,611,000	0
Kevin Nanke [Member]
Related Party Transaction [Line Items]
Proceeds from (repayments of) related party debt			0	2,000,000
Purchase of properties from related parties			$ 0	$ 2,000,000
Series C Preferred Stock [Member]
Related Party Transaction [Line Items]
Preferred stock, dividend rate, percentage	9.75%
Series C Preferred Stock [Member] | Värde Partners, Inc. [Member]
Related Party Transaction [Line Items]
Preferred stock, dividend rate, percentage			9.75%

SHAREHOLDERS_ EQUITY AND REDE63

SHAREHOLDERS’ EQUITY AND REDEEMABLE PREFERRED STOCK (Details Textual)	Jan. 31, 2018day	Jan. 30, 2018USD ($)$ / sharesshares	Jun. 30, 2018USD ($)	Jun. 30, 2018USD ($)shares	Jun. 30, 2017USD ($)	Dec. 31, 2021	Apr. 26, 2021	Mar. 31, 2018USD ($)	Feb. 20, 2018USD ($)	Dec. 31, 2017USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Dividends payable			$ 4,117,000	$ 4,117,000						$ 0
Percentage of redeemable preferred stock					6.00%
Convertible preferred stock, adjustment feature (in dollars per share) | $ / shares		$ 5.25
Convertible preferred stock, percentage of conversion price		140.00%
Convertible preferred stock, change of control, percentage of stated value		2.50%
Stock repurchase program, authorized amount									$ 10,000,000
Repurchase of common stock				$ 997,000	$ 0
Share price (in dollars per share) | $ / shares		$ 4.42
Share Repurchase Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock repurchase program, authorized amount								$ 1,000,000
Purchase of treasury stock (in shares) | shares				253,598
Repurchase of common stock				$ 1,000,000
Series C Preferred Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock issued during period, shares, new issues | shares		100,000
Shares issued (in dollars per share) | $ / shares		$ 1,000
Stock issued during period, value, new issues		$ 100,000,000
Preferred stock, dividend rate, percentage		9.75%
Dividends payable			$ 4,100,000	$ 4,100,000
Preferred stock, redemption terms		(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
Preferred stock conversion price per share (in dollars per share) | $ / shares		$ 6.15
Preferred stock conversion price description		the Series C Preferred Stock 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 lesser of (i) $5.25 and (ii) the Series C Preferred Stock Conversion Price then in effect, subject to certain exceptions and to the Share Cap
Convertible preferred stock, terms of conversion		(i) the volume-weighted average price per share of the Common Stock on the principal exchange on which it is then traded has been at least 140% of the Series C Preferred Stock Conversion Price then in effect for at least 20 of the 30 consecutive trading days immediately preceding the exercise by the Company of the forced conversion right and (ii) certain trading and other conditions are satisfied.
Preferred share holder's right upon change of control			cause the Company to redeem all of such holder’s shares of Series C Preferred Stock for cash in an amount per share equal to (i) the 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 Series C 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 Series C 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 and to the Company’s or its successor’s optional redemption rights described above.
Preferred stock, conversion basis		the Common Stock, each share of Series C Preferred Stock will entitle the holder to a number of votes equal to (i) the Stated Value as of the applicable record date or other determination date divided by (ii) $4.42
Series C Preferred Stock [Member] | Scenario, Forecast [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Preferred stock, dividend rate, percentage							9.75%
Series C Preferred Stock [Member] | Minimum [Member] | Scenario, Forecast [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Preferred stock, dividend rate, percentage						12.00%
Series C Preferred Stock [Member] | Maximum [Member] | Scenario, Forecast [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Preferred stock, dividend rate, percentage						15.00%
Preferred Stock, Redemption, Period One [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of redeemable preferred stock		120.00%
Preferred Stock, Redemption, Period Two [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of redeemable preferred stock		125.00%
Preferred Stock, Redemption, Period Three [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of redeemable preferred stock		130.00%
Second Lien Term Loan [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Threshold trading days | day	20
Second Lien Term Loan [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Threshold trading days | day	30

SHAREHOLDERS_ EQUITY AND REDE64

SHAREHOLDERS’ EQUITY AND REDEEMABLE PREFERRED STOCK (Details) - Warrant [Member]	6 Months Ended
	Jun. 30, 2018$ / sharesshares
Warrants
Outstanding beginning (in shares) | shares	11,882,800
Exercised (in shares) | shares	(2,848,440)
Expired or canceled (in shares) | shares	(2,324,304)
Outstanding ending (in shares) | shares	6,710,056
Weighted- Average Exercise Price
Outstanding beginning (in dollars per share) | $ / shares	$ 3.46
Exercised (in dollars per share) | $ / shares	2.50
Expired or canceled (in dollars per share) | $ / shares	3.84
Outstanding ending (in dollars per share) | $ / shares	$ 3.27

SHARE BASED AND OTHER COMPENS65

SHARE BASED AND OTHER COMPENSATION (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expensed	$ 5,554	$ 9,386
Unrecognized share-based compensation costs	$ 6,123	$ 9,763
Weighted average amortization period remaining (in years)	1 year 2 months 9 days	1 year 6 months 22 days
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expensed	$ 1,238	$ 3,273
Unrecognized share-based compensation costs	$ 1,346	$ 7,669
Weighted average amortization period remaining (in years)	6 months 22 days	9 months 26 days
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expensed	$ 4,316	$ 6,113
Unrecognized share-based compensation costs	$ 4,777	$ 2,094
Weighted average amortization period remaining (in years)	7 months 17 days	8 months 27 days

SHARE BASED AND OTHER COMPENS66

SHARE BASED AND OTHER COMPENSATION (Details 1)	6 Months Ended
	Jun. 30, 2018$ / sharesshares
Restricted Stock [Member]
Number of Shares
Beginning Outstanding (in shares) | shares	2,475,266
Granted (in shares) | shares	799,944
Vested and issued (in shares) | shares	(654,946)
Forfeited or canceled (in shares) | shares	(847,898)
Ending Outstanding (in shares) | shares	1,772,366
Weighted Average Grant Date Price
Beginning Outstanding (in dollars per share) | $ / shares	$ 4.22
Granted (in dollars per share) | $ / shares	4.28
Vested and issued (in dollars per share) | $ / shares	(4.06)
Forfeited or canceled (in dollars per share) | $ / shares	(4.88)
Ending Outstanding (in dollars per share) | $ / shares	$ 3.93
Restricted Stock Units (RSUs) [Member]
Number of Shares
Beginning Outstanding (in shares) | shares	9,999
Vested and issued (in shares) | shares	(9,999)
Ending Outstanding (in shares) | shares	0
Weighted Average Grant Date Price
Beginning Outstanding (in dollars per share) | $ / shares	$ 6.57
Vested and issued (in dollars per share) | $ / shares	(6.57)
Ending Outstanding (in dollars per share) | $ / shares	$ 0

SHARE BASED AND OTHER COMPENS67

SHARE BASED AND OTHER COMPENSATION (Details 2) - Equity Option [Member] - $ / shares	3 Months Ended	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Jun. 30, 2018	Dec. 31, 2017
Number of Options
Outstanding beginning (in shares)		7,305,000
Granted (in shares)	352,500	352,500
Exercised (in shares)		(675,500)
Forfeited or canceled (in shares)		(1,480,850)
Outstanding ending (in shares)	5,501,150	5,501,150	7,305,000
Weighted Average Exercise Price
Outstanding beginning (in dollars per share)		$ 3.74
Granted (in dollars per share)		3.82
Exercised (in dollars per share)		(1.66)
Forfeited or canceled (in dollars per share)		(4.20)
Outstanding ending (in dollars per share)	$ 3.68	$ 3.68	$ 3.74
Stock Options Outstanding and Exercisable
Stock Options Outstanding and Exercisable, Number of Options Vested/Exercisable (in shares)	4,201,200	4,201,200	3,534,484
Stock Options Outstanding and Exercisable, Weighted Average Remaining Contractual Life (Years)		8 years 4 months 24 days	8 years 10 months 24 days

SHARE BASED AND OTHER COMPENS68

SHARE BASED AND OTHER COMPENSATION (Details Textual) - Equity Option [Member] - USD ($) $ / shares in Units, $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	352,500	352,500
Weighted Average Exercise Price (in dollars per share)	$ 3.68
Proceeds from Stock Options Exercised	$ 1

SHARE BASED AND OTHER COMPENS69

SHARE BASED AND OTHER COMPENSATION (Details 3)	6 Months Ended
	Jun. 30, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected Term in Years	6 years
Expected Dividends	0.00%
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected Volatility	72.60%
Risk-Free Interest Rate	2.71%
Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected Volatility	58.80%
Risk-Free Interest Rate	2.59%

LOSS PER COMMON SHARE (Details)

LOSS PER COMMON SHARE (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Earnings Per Share [Abstract]
Net loss	$ (31,208)	$ (23,148)	$ (18,962)	$ (31,904)
Less: dividends on redeemable preferred stock	0	(92)	0	(122)
Less: dividends and deemed dividends on Series B convertible preferred stock	0	(4,422)	0	(4,635)
Less: dividends on Series C convertible preferred stock	(2,465)	0	(4,117)	0
Net loss attributable to common stockholders	$ (33,673)	$ (27,662)	$ (23,079)	$ (36,661)
Weighted average common shares outstanding - basic and diluted (in shares)	64,098,309	44,332,270	57,801,098	34,282,784
Net loss per common share - basic and diluted (in dollars per share)	$ (0.53)	$ (0.62)	$ (0.40)	$ (1.07)

LOSS PER COMMON SHARE (Details

LOSS PER COMMON SHARE (Details 1) - shares	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)	56,494,032	33,264,494	56,494,032	33,264,494
Series C Preferred Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)	20,312,607	0	20,312,607	0
Employee Stock Option [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)	5,501,150	7,158,500	5,501,150	7,158,500
Restricted Stock Units (RSUs) [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)	0	9,999	0	9,999
Stock Purchase Warrants [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)	6,710,056	12,523,045	6,710,056	12,523,045
Conversion of Term Loans [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)	23,970,219	13,572,950	23,970,219	13,572,950

SUPPLEMENTAL NON-CASH TRANSAC72

SUPPLEMENTAL NON-CASH TRANSACTIONS (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Non-cash investing and financing activities excluded from the statement of cash flows:
Conversion of Series B Preferred Stock and accrued dividends to common stock	$ 0	$ 14,087
Fair value of warrants issued and repriced as debt discount	0	1,031
Common stock issued for acquisition of oil and gas properties	24,778	0
Common stock issued for commitment fees associated with Private Placement	0	250
Cashless exercise of warrants	0	371
Change in capital expenditures for drilling costs in accrued liabilities	5,859	871
Change in asset retirement obligations	66	0
Issuance of common stock for drilling services	0	96
Increase in final settlement on the divestiture of DJ Basin properties in accrued liabilities	0	584
Fair value of derivative liabilities associated with conversion features of Second Lien Term Loan	0	$ 36,741
Dividends Payable [Line Items]
Percentage of redeemable preferred stock		6.00%
Series C Preferred Stock [Member]
Dividends Payable [Line Items]
Accrued dividends for Preferred Stock	4,117	$ 0
Series B Preferred Stock [Member]
Dividends Payable [Line Items]
Accrued dividends for Preferred Stock	$ 0	$ 3,767

SEGMENT INFORMATION (Details)

SEGMENT INFORMATION (Details)	6 Months Ended
	Jun. 30, 2018segment
Segment Reporting [Abstract]
Number of reportable segments	1

SUBSEQUENT EVENTS (Details)

SUBSEQUENT EVENTS (Details) - Subsequent Event [Member] $ in Millions	Aug. 02, 2018bbl	Jul. 25, 2018USD ($)	Jul. 31, 2018USD ($)Wellmi	Sep. 30, 2018USD ($)bbl	Aug. 01, 2018a
Subsequent Event [Line Items]
Crude oil takeaway, number of barrels per day (in barrels) | bbl				40,000
Net acres | a					750
Salt Creek Midstream Water, LLC [Member]
Subsequent Event [Line Items]
Number of miles of pipeline | mi			14
Number of salt water disposal wells (SWD) | Well			1
Total purchase price | $			$ 20
Upfront payment to acquire existing water infrastructure | $		$ 10		$ 5
Prefunded drilling bonus | $		$ 5
Salt Creek Midstream, LLC [Member]
Subsequent Event [Line Items]
Agreement period	5 years
Salt Creek Midstream, LLC [Member] | July 1, 2019 to June 30, 2020 [Member]
Subsequent Event [Line Items]
Crude oil takeaway, number of barrels per day (in barrels) | bbl	6,000
Salt Creek Midstream, LLC [Member] | July 1, 2020 to June 30, 2024 [Member]
Subsequent Event [Line Items]
Crude oil takeaway, number of barrels per day (in barrels) | bbl	5,000