Document And Entity Information - USD ($)	12 Months Ended
Document And Entity Information - USD ($)	Dec. 31, 2017	Mar. 05, 2018	Jun. 30, 2017
Document Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY
Entity Registrant Name	LILIS ENERGY, INC.
Entity Central Index Key	0001437557
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Public Float			$ 186,032,195
Trading Symbol	LLEX
Entity Common Stock, Shares Outstanding		53,496,205

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 17,462	$ 11,738
Accounts receivables, net of allowance of $39 and $106, respectively	7,426	2,247
Prepaid expenses and other current assets	584	767
Total current assets	25,472	14,752
Oil and natural gas properties, full cost method of accounting
Unproved	101,771	24,461
Proved	141,717	69,809
Less: accumulated depreciation, depletion, amortization and impairment	(73,183)	(55,771)
Total oil and natural gas properties, net	170,305	38,499
Other assets:
Other property and equipment, net	76	52
Other assets	91	216
Total other assets	167	268
Total assets	195,944	53,519
Current liabilities:
Accounts payable	10,488	5,166
Accrued liabilities	13,857	2,706
Derivative instruments	853	0
Dividends payable	0	808
Asset retirement obligations	226	338
Current portion of long-term debt	11	17
Total current liabilities	25,435	9,035
Long term liabilities:
Asset retirement obligations	726	919
Long-term debt	127,794	30,226
Derivative instruments	72,937	1,400
Total liabilities	226,892	41,580
Commitments and contingencies (Note 8)
Conditionally redeemable 6% preferred stock, $0.0001 par value, 7,000 shares authorized, 2,000 shares issued and outstanding with a liquidation preference of $2,240 at December 31, 2016	0	1,874
Stockholders’ equity (deficit):
Common stock, $0.0001 par value per share; 150,000,000 shares authorized, 53,368,331 and 20,918,901 shares issued and outstanding as of December 31, 2017 and 2016, respectively.	5	2
Additional paid-in capital	272,335	219,837
Accumulated deficit	(303,288)	(223,206)
Total stockholders’ equity (deficit)	(30,948)	10,065
Total liabilities, redeemable preferred stock and stockholders’ equity	195,944	53,519
Series B Preferred Stock [Member]
Stockholders’ equity (deficit):
Series B Preferred stock, $0.0001 par value; stated value of $1,000; 20,000 shares authorized; 16,828 shares issued and outstanding at December 31, 2016, with a liquidation preference of $20,627 at December 31, 2016	0	13,432
Total stockholders’ equity (deficit)	$ 0	$ 13,432

Consolidated Balance Sheets [Parenthetical] - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Allowance related to accounts receivable	$ 39	$ 106
Redeemable 6% preferred stock, par value		$ 0.0001
Redeemable 6% preferred stock, shares authorized		7,000
Redeemable 6% preferred stock, shares issued		2,000
Redeemable 6% preferred stock, shares outstanding		2,000
Redeemable 6% preferred stock, liquidation preferences		$ 2,240
Common Stock, Par or Stated Value Per Share (in dollars per share)	$ 0.0001	$ 0.0001
Common Stock, Shares Authorized	150,000,000	150,000,000
Common Stock, Shares, Issued	53,368,331	20,918,901
Common Stock, Shares, Outstanding	53,368,331	20,918,901
Series B Preferred Stock [Member]
Preferred Stock, Par or Stated Value Per Share	$ 0.0001	$ 0.0001
Preferred Stock Value Stated Rate	$ 1,000	$ 1,000
Preferred Stock, Shares Authorized	20,000	20,000
Preferred Stock, Shares Issued		16,828
Preferred Stock, Shares Outstanding		16,828
Preferred Stock, liquidation preference		$ 20,627

Consolidated Statements of Operations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Revenues:
Oil sales	$ 17,826	$ 2,418
Natural gas sales	2,125	844
Natural gas liquid sales	1,661	173
Total revenue	21,612	3,435
Operating expenses:
Production costs	7,023	1,590
Production taxes	1,187	(167)
General and administrative	49,851	14,227
Depreciation, depletion, accretion and amortization	7,025	1,698
Impairment of evaluated oil and natural gas properties	10,505	4,718
Total operating expenses	75,591	22,066
Loss from operations	(53,979)	(18,631)
Other income (expense):
Other income	18	90
Inducement expense	0	(8,307)
Gain on extinguishment of debt and modification of convertible debentures	0	852
Loss from commodity derivatives, net	(1,063)	0
Loss from fair value changes of debt conversion and warrant derivatives	(6,260)	(1,222)
Loss from fair value changes of conditionally redeemable 6% preferred stock	(41)	(701)
Interest expense	(18,757)	(4,924)
Total other income (expense)	(26,103)	(14,212)
Net loss before income taxes	(80,082)	(32,843)
Income tax expense	0	0
Net loss	(80,082)	(32,843)
Dividends on redeemable preferred stock	(122)	(407)
Loss on extinguishment of Series A convertible preferred stock	0	(540)
Dividend and deemed dividends on Series B convertible preferred stock	(4,635)	(8,506)
Net loss attributable to common stockholders	$ (84,839)	$ (42,296)
Net loss per common share-basic and diluted	$ (2.00)	$ (3.73)
Weighted average common shares outstanding:
Basic and diluted	42,428,148	11,328,252

Consolidated Statements of Changes in Stockholders’ Equity (Deficit) - USD ($) $ in Thousands	Total	Series A Preferred Stock [Member]	Series B Preferred Stock [Member]	Common Stock [Member]	Additional Paid-in Capital [Member]	Accumulated Deficit [Member]
Balance at Dec. 31, 2015	$ (14,343)	$ 6,794	$ 0	$ 0	$ 159,773	$ (180,910)
Balance (in shares) at Dec. 31, 2015		7,500	0	2,786,275
Stock based compensation	7,078	$ 0	$ 0	$ 0	7,078	0
Stock based compensation (in shares)		0	0	711,667
Exercise of warrants	187	$ 0	$ 0	$ 0	187	0
Exercise of warrants (in shares)		0	0	420,707
Fair value of warrants issued for financing costs	713	$ 0	$ 0	$ 0	713	0
Issuance and repricing of warrants to induce conversion	8,307	0	0	0	8,307	0
Gain on modification of convertible debentures	(602)	0	0	0	(602)	0
Fair value of warrants issued for debt discount	1,479	0	0	0	1,479	0
Common stock issued for conversion of convertible notes and accrued interest	14,872	$ 0	$ 0	$ 1	14,871	0
Common stock issued for conversion of convertible notes and accrued interest (in shares)		0	0	6,778,115
Common stock and warrants issued in connection with the Brushy merger	7,111	$ 0	$ 0	$ 0	7,111	0
Common stock and warrants issued in connection with the Brushy merger (in shares)		0	0	5,785,119
Series B Preferred stock issued for cash, net of fees	18,195	$ 0	$ 18,195	$ 0	0	0
Series B Preferred stock issued for cash, net of fees (in shares)		0	20,000	0
Warrants issued for Series B Preferred Stock offering fees	0	$ 0	$ (1,591)	$ 0	1,591	0
Conversion of Series A Preferred Stock and dividends to common stock	888	$ (6,794)	$ 0	$ 1	7,681	0
Conversion of Series A Preferred Stock and dividends to common stock (in shares)		(7,500)	0	1,500,000
Loss on extinguishment of Series A Preferred Stock	0	$ 0	$ 0	$ 0	540	(540)
Conversion of Series B Preferred Stock and dividends	57	$ 0	$ (3,172)	$ 0	3,229	0
Conversion of Series B Preferred Stock and dividends (in shares)		0	(3,172)	2,937,018
Dividends and deemed dividends on preferred stock	(1,034)	$ 0	$ 0	$ 0	7,879	(8,913)
Net loss	(32,843)	0	0	0	0	(32,843)
Balance at Dec. 31, 2016	10,065	$ 0	$ 13,432	$ 2	219,837	(223,206)
Balance (in shares) at Dec. 31, 2016		0	16,828	20,918,901
Stock based compensation	21,538	$ 0	$ 0	$ 0	21,538	0
Stock based compensation (in shares)		0	0	0
Common stock for restricted stock and stock options	524	$ 0	$ 0	$ 0	524	0
Common stock for restricted stock and stock options (in shares)		0	0	5,859,383
Common stock withheld for taxes on stock-based compensation	(3,709)	$ 0	$ 0	$ 0	(3,709)	0
Common stock withheld for taxes on stock-based compensation (in shares)		0	0	(786,081)
Exercise of warrants	593	$ 0	$ 0	$ 1	592	0
Exercise of warrants (in shares)		0	0	5,580,281
Conversion of Series B Preferred Stock and dividends	1,433		$ (13,432)	$ 2	14,863	0
Conversion of Series B Preferred Stock and dividends (in shares)			(16,828)	16,601,026
Sale of common stock in private placement, net	18,649	$ 0	$ 0	$ 0	18,649	0
Sale of common stock in private placement, net (in shares)		0	0	5,194,821
Warrants repriced for term loan	1,031	$ 0	$ 0	$ 0	1,031	0
Dividends and deemed dividends on preferred stock	(990)	0	0	0	(990)	0
Net loss	(80,082)	0	0	0	0	(80,082)
Balance at Dec. 31, 2017	$ (30,948)	$ 0	$ 0	$ 5	$ 272,335	$ (303,288)
Balance (in shares) at Dec. 31, 2017		0	0	53,368,331

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Cash flows from operating activities:
Net loss	$ (80,082)	$ (32,843)
Adjustments to reconcile net loss to net cash used in operating activities:
Equity instruments issued for services and compensation	21,538	7,078
Inducement expense	0	8,307
Bad debt expense	22	494
Amortization of debt issuance cost and debt discount	10,371	3,185
Paid-in-kind interest	6,559	0
Loss on commodity derivatives	1,063	0
Cash settlement paid for commodity derivatives	(96)	0
Loss in fair value of debt conversion and warrant derivatives	6,260	1,222
Loss in fair value of conditionally redeemable 6% preferred stock	41	701
Depreciation, depletion, amortization and accretion of asset retirement obligation	7,025	1,698
Impairment of evaluated oil and natural gas properties	10,505	4,718
Gain on extinguishment of debt and modification of convertible debentures	0	(852)
Changes in operating assets and liabilities:
Accounts receivable	(5,204)	(1,264)
Other assets	309	1,554
Accounts payable, accrued expenses and other liabilities	14,446	(307)
Net cash used in operating activities	(7,243)	(6,309)
Cash flows from investing activities:
Cash consideration for Brushy merger, net of cash acquired	0	(2,302)
Net proceeds from sale of DJ Basin and non-operated properties	1,282	0
Capital expenditures	(148,784)	(16,828)
Net cash used in investing activities	(147,502)	(19,130)
Cash flows from financing activities:
Net proceeds from issuance of Series B Preferred Stock	0	18,195
Proceeds from issuance of convertible notes	0	2,863
Proceeds from issuance of First Lien Term Loan, net of financing costs	0	29,701
Proceeds from exercise of accordion feature of the First Lien Term Loan, net of financing costs	6,706	0
Proceeds from Bridge Loan and Second Lien Term Loan, net of financing costs	178,722	0
Repayment of the First Lien Term Loan	(38,100)	0
Repayment of conditionally redeemable 6% preferred stock including dividends	(2,277)	0
Proceeds from exercise of stock options and warrants	745	187
Payment for tax withholding on stock-based compensation	(3,709)	0
Proceeds from private placement, net of financing costs	18,399	0
Repayment of notes payable	(17)	(13,879)
Net cash provided by financing activities	160,469	37,067
Assets acquired and liabilities assumed through Brushy Merger:
Increase in cash and cash equivalents	5,724	11,628
Cash and cash equivalents at beginning of period	11,738	110
Cash and cash equivalents at end of period	17,462	11,738
Supplemental disclosure:
Cash paid for interest	$ 2,292	$ 762

Organization and Business

12 Months Ended

Dec. 31, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and Business

NOTE 1 – Organization and Business

Lilis Energy, Inc. (“Lilis”, “Lilis Energy” or the “Company”) was incorporated in the State of Nevada in 2007. The Company is an independent oil and natural gas company focused on the acquisition, development, and production of conventional and unconventional oil and natural gas properties in the core of the Delaware Basin in Winkler, Loving, and Reeves Counties, Texas and Lea County, New Mexico. The Company has only one reportable operating segment, which is oil and natural gas exploration and production in the Delaware Basin.

On June 23, 2016, the Company completed a merger transaction with Brushy Resources, Inc. (“Brushy Resources”). The merger resulted in the acquisition of our properties in the Delaware Basin and the majority of our current operating activity. In connection with the merger with Brushy Resources, the Company effected a 1-for-10 reverse stock split. As a result of the reverse split, every ten shares of issued and outstanding common stock were automatically converted into one newly issued and outstanding share of common stock, without any change in the par value per share; however, the number of authorized shares of common stock remained unchanged.

Shortly after the merger with Brushy Resources, the Company began to develop and implement a development program focusing on the drilling of new horizontal wells across multiple potentially productive formations in the Delaware Basin. The Company drilled its first horizontal well in late 2016 and completed it in January 2017. The Company intends to grow its business through generating cash flow from new production of oil, natural gas and natural gas liquid (“NGL”), as well as through de-risking the development profile of our portfolio of properties in order to add overall value.

On March 31, 2017, the Company completed the divestiture of all our oil and natural gas properties located in the DJ Basin completing its transformation to a pure play Delaware Basin oil and natural gas company.

Basis of Presentation and Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Basis of Presentation and Summary of Significant Accounting Policies

NOTE 2 – Basis of Presentation and Summary of Significant Accounting Policies

Principles of Consolidation

The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries which includes Brushy Resources, ImPetro Operating, LLC (“ImPetro Operating”), ImPetro Resources, LLC (“ImPetro”), Lilis Operating Company, LLC (“Lilis Operating”), and Hurricane Resources LLC (“Hurricane”). All significant intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates

The accompanying 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 year financial statements to conform to the 2017 presentation. These reclassifications have no effect on the Company’s previously reported results of operations. For the year ended December 31, 2016, the income from operator’s overhead recovery of $0.3 million has been reclassified from production costs to general and administrative expenses.

Cash and Cash Equivalents

Cash and cash equivalents include highly liquid instruments with an original maturity of three months or less are stated at cost, which approximates fair value.

Accounts Receivable

The Company has accounts receivable from joint interest owners of properties operated by the Company. The Company typically has the right to withhold future revenue disbursements to recover any non-payment of related joint interest billings. Management routinely assesses accounts receivable amounts to determine their collectability and accrues an allowance for uncollectible receivables when, based on the judgment of management, it is probable that a receivable will not be collected. The Company records actual and estimated oil and natural gas revenue receivable from third parties at its net revenue interest. In addition, the Company has receivables derived from sales of certain oil and natural gas production which are collateral under the Company’s credit agreements.

Fair Value of Financial Instruments

As of December 31, 2017 and 2016, the carrying value of cash and cash equivalents, accounts receivable, accounts payable, accrued expenses, interest payable and advances from joint interest partners approximates fair value due to the short-term nature of such items. The carrying value of the Company’s secured debt is carried at cost which approximates the fair value of the debt as the related interest rates approximates interest rates currently available to the Company.

Oil and Natural Gas Properties

The Company uses the full cost method of accounting for oil and natural gas operations. Under this method, costs related to the exploration, non-production related development and acquisition of oil and natural gas reserves are capitalized. Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling, developing and completing productive wells and/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.

The Company accounts for its unproven long-lived assets in accordance with Accounting Standards Codification (“ASC”) Topic 360-10-05, Accounting for the Impairment or Disposal of Long-Lived Assets. 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.

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.

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.

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. For the year ended December 31, 2017, higher capital expenditures with lower than expected development of proved reserves contributed to the excess of net book value of our oil and natural gas properties over the ceiling resulting in the recognition of an impairment charge of $10.5 million. During 2016, commodity prices continued to trade in a low range. With low commodity prices sustained for the majority of 2016 in the DJ Basin, some of the Company’s properties became uneconomic triggering an impairment charge of $4.7 million for the year ended December 31, 2016.

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.

Wells in Progress

Wells in progress connotes wells that are currently in the process of being drilled or completed or otherwise under evaluation as to their potential to produce oil and natural gas reserves in commercial quantities. Such wells continue to be classified as wells in progress and withheld from the depletion calculation and the ceiling test until such time as either proved reserves can be assigned, or the wells are otherwise abandoned. Upon either the assignment of proved reserves or abandonment, the costs for these wells are then transferred to the full cost pool and become subject to both depletion and the ceiling test calculations in accordance with full cost accounting under Rule 4-10 of Regulation S-X of the Securities Exchange Act of 1934, as amended.

Capitalized Interest

For significant oil and natural gas investments in unproved properties, and significant exploration and development projects that have not commenced production, interest is capitalized as part of the historical cost of developing and constructing assets. Capitalized interest is determined by multiplying the Company’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depreciation or impairment. As of December 31, 2017, there were no significant exploratory projects on unproved properties and none of the development projects exceeded the interest capitalization qualifying asset limit. As a result, no interest was capitalized as of December 31, 2017 and 2016.

Other Property and Equipment

Property and equipment include vehicles, office equipment and furniture which are stated at cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets. The estimated useful lives of property and equipment range from three to seven years. The Company recorded approximately $0.04 million of depreciation for each of the years ended December 31, 2017 and 2016, respectively.

Accrued Liabilities

As of December 31, 2017 and 2016, the Company’s accrued liabilities consisted of the following:

	December 31,
	2017		2016
	($ in thousands)
Accrued bonus	$	3,000	$	-
Accrued drilling costs		3,615		1,331
Revenue payable		6,460		1,313
Other accrued liabilities		782		62
Total accrued liabilities	$	13,857	$	2,706

Asset Retirement Obligations

The Company incurs retirement obligations for certain assets at the time they are placed in service. The fair values of these obligations are recorded as liabilities on a discounted basis. The costs associated with these liabilities are capitalized as part of the related assets and depreciated. Over time, the liabilities are accreted for the change in their present value. For purposes of depletion, the Company includes estimated dismantlement and abandonment cost, net of salvage values, associated with future development activities that have not yet been capitalized as asset retirement obligations. Asset retirement obligations incurred are classified as Level 3 (unobservable inputs) fair value measurements.

Revenue Recognition

The Company recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller's price to the buyer is fixed or determinable, and (iv) collectability is reasonably assured.

The Company uses the entitlements method of accounting for oil, natural gas and NGL revenues. Should sales proceeds be in excess of the Company's entitlement, these amounts will be included in accrued liabilities and the Company's share of sales taken by others will be included in other assets in the accompanying consolidated balance sheets. The Company had no material oil, natural gas or NGL entitlement assets or liabilities as of December 31, 2017 and 2016.

All revenue proceeds relating to third-party royalty owners not remitted by the end of a reporting period are recorded as revenue payable, a component of accrued liabilities. As of December 31, 2017, and 2016, the Company had approximately $6.5 million and $1.3 million, respectively, of such revenue proceeds recorded in accrued liabilities.

Stock Based Compensation

The Company applies a fair value method of accounting for stock-based compensation, which requires recognition in the financial statements of the cost of services received in exchange for equity awards. For equity awards, compensation expense is based on the fair value on the grant date or modification date and is recognized in the Company’s financial statements over the vesting period. The Company utilizes the Black-Scholes Merton option-pricing model to measure the fair value of stock options based on several criteria, including but not limited to, the valuation model used and associated input factors, such as expected term of the award, stock price volatility, risk free interest rate, dividend rate and award cancellation rate. These inputs are subjective and are determined using management’s judgment. If differences arise between the assumptions used in determining stock-based compensation expense and the actual factors, which become known over time, the Company may change the input factors used in determining future stock-based compensation expense. The Company recognizes forfeitures as and when the stock awards are forfeited.

The Company accounts for warrant grants to nonemployees whereby the fair values of such warrants are determined using the option pricing model at the earlier of the date at which the nonemployee’s performance is complete or a performance commitment is reached.

Income Taxes

The Company uses the asset and liability method in accounting for income taxes. Deferred tax assets and liabilities are recognized for temporary differences between financial statement carrying amounts and the tax bases of assets and liabilities, and are measured using the tax rates expected to be in effect when the differences reverse. Deferred tax assets are also recognized for operating loss and tax credit carry forwards. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the results of operations in the period that includes the enactment date. A valuation allowance is used to reduce deferred tax assets when uncertainty exists regarding their realization.

The Company recognizes its tax benefits only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely to be realized upon settlement. A liability for “unrecognized tax benefits” is recorded for any tax benefits claimed that do not meet these recognition and measurement standards. As of December 31, 2017 and 2016, the Company has determined that no liability is required to be recognized.

The Company’s policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense. No interest or penalties were required to be accrued at December 31, 2017 and 2016. Further, the Company does not expect that the total amount of unrecognized tax benefits will significantly increase or decrease during the next 12 months.

Loss Per Share

Basic loss per share was calculated by dividing net income or loss applicable to common shares by the weighted average number of common shares outstanding during the periods presented. The calculation of diluted loss per share should include the potential dilutive impact of shares issuable upon the conversion of debt or preferred stock, warrants and options during the period, unless their effect is anti-dilutive. At December 31, 2017 and 2016, common stock equivalents including shares underlying conversion of the Second Lien Term Loan, restricted stock units, restricted stock, options, warrants, preferred stock and debentures have been excluded from the diluted share calculations as they were anti-dilutive as a result of net losses incurred. The Company included 3,522,735 warrants, with an exercise price of $.01, in its earnings per share calculation for the year ended December 31, 2016. There were no warrants exercisable at a price of $0.01 per share for the year ended December 31, 2017.

The Company excluded the following shares from the diluted loss per share calculations because they were anti-dilutive at December 31, 2017 and 2016:

	December 31,
	2017		2016
Stock Options		7,305,000		5,956,833
Restricted Stock Units		9,999		149,584
Restricted Stock		2,475,266		1,068,305
Series B Preferred Stock		-		15,454,545
Stock Purchase Warrants ⁽¹⁾		11,882,800		12,392,776
Conversion of Term Loan		24,202,016		-
		45,875,081		35,022,043

⁽¹⁾

Excludes warrants exercisable for 3,522,735 shares of common stock at an exercise price of $0.01 for the year ended December 31, 2016 since these warrants are not anti-dilutive. There were no warrants exercisable at $0.01 per share for the year ended December 31, 2017.

Concentration of Credit Risk

The Company operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payment for costs associated with the property and seeks reimbursement from the other joint interest owners in the property for their portion of those costs. When warranted, prepayments are required from joint interest owners for drilling and completion projects. Joint interest owners consist primarily of independent oil and natural gas producers whose ability to reimburse the Company could be negatively impacted by adverse market conditions.

The purchasers of the Company’s oil, natural gas and NGL production consist primarily of independent marketers, major oil and gas companies, refiners and gas pipeline companies. Credit evaluations are performed on the Company’s purchasers of its production and their financial condition is monitored on an ongoing basis. Based on those evaluations and monitoring, the Company may obtain letters of credit or parental guarantees from some purchasers.

All of the Company’s oil and natural gas derivative transactions are carried out in the over-the-counter market and are not typically subject to margin-deposit requirements. The use of derivative transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. The Company monitors the credit ratings of its derivative counterparties on an ongoing basis. If a counterparty were to default on its obligations to the Company under the derivative contracts or seek bankruptcy protection, it could have a material adverse effect on its ability to fund planned activities and could result in a larger percentage of our future production being subject to commodity price volatility. In addition, in poor economic environments and tight financial markets, the risk of a counterparty default is heightened and fewer counterparties may participate in derivative transactions, which could result in greater concentration of exposure to any one counterparty or a larger percentage of the Company’s future production being subject to commodity price changes.

Major Customers

During the years ended December 31, 2017 and 2016, the Company’s major customers, as a percentage of total revenue, consisted of the following:

	Year Ended December 31,
	2017			2016
Texican Crude & Hydrocarbon, LLC		85	%		38	%
ETC Field Services LLC		14	%		16	%
Noble Energy		-	%		41	%
All others		1	%		5	%
		100	%		100	%

Derivative Instruments

All derivative instruments are recorded on the consolidated balance sheet at fair value as either an asset or a liability with changes in fair value recognized currently in earnings. Although derivative instruments are used by the Company to manage the price risk attributable to its expected oil and natural gas production, those derivative instruments have not been designated as accounting hedges under the accounting guidance. All of our derivatives are accounted for as mark-to-market activities. Under ASC Topic 815, “Derivatives and Hedging,” these instruments are recorded on the consolidated balance sheets at fair value as either short term or long-term assets or liabilities based on their anticipated settlement date. The Company nets derivative assets and liabilities by commodity for counterparties where a legal right to such offset exists. Changes in the derivatives' fair values are recognized in current earnings since the Company has elected not to designate its current derivative contracts as cash flow hedges for accounting purposes.

The Company has recognized certain conversion features within its Second Lien Term Loan as embedded derivatives that have been bifurcated from the Loan, as defined in Note 4, and accounted for separately from the debt. Additionally, warrants issued to SOSV Investment LLC (“SOS”) to purchase up to 200,000 shares of the Company’s stock contain a price protection feature that will automatically reduce the exercise price should the Company enter into another agreement pursuant to which warrants are issued at a lower exercise price. The price protection feature has been recognized as an embedded derivative and accounted for separately.

Recently Issued Accounting Pronouncements

The Company considers the applicability and impact of all Accounting Standards Updates (“ASUs”). The ASUs not 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 August 28, 2017, the Financial Accounting Standards Board (“FASB”) issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities, which amends the hedge accounting recognition and presentation requirements in Accounting Standards Codification (“ASC”) Topic 815. The new standard provides partial relief on the timing of certain aspects of hedge documentation and eliminates the requirement to recognize hedge ineffectiveness separately in income. The amendments in this ASU are effective for fiscal years beginning after December 15, 2018 and for interim periods therein. Early adoption as of the date of issuance is permitted. The new standard does not impact accounting for derivatives that are not designated as accounting hedges. The Company does not currently account for any of its derivative position as accounting hedges. The Company may consider designating certain derivative contracts as accounting hedges in the future, but currently has no plans to do so.

On July 13, 2017, the 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. Part I of the ASU 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 the ASU 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 this new ASU 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 expects to adopt this ASU at its effective date. The Company’s SOS Warrant Liability (as defined in Note 4) is a derivative solely because of its down round feature. Any outstanding SOS Warrants as of the date of adoption will be reclassified to equity and gains or losses on changes in fair value will no longer be recognized. No other derivatives instruments outstanding as of December 31, 2017 would be affected.

On May 17, 2017, the FASB issued ASU 2017-09, Scope of Modification Accounting, clarifies Topic 718, Compensation – Stock Compensation, such that an entity must apply modification accounting to changes in the terms or conditions of a share-based payment award unless all of the following criteria are met: (1) the fair value of the modified award is the same as the fair value of the original award immediately before the modification and the ASU indicates that if the modification does not affect any of the inputs to the valuation technique used to value the award, the entity is not required to estimate the value immediately before and after the modification; (2) the vesting conditions of the modified award are the same as the vesting conditions of the original award immediately before the modification; and (3) the classification of the modified award as an equity instrument or a liability instrument is the same as the classification of the original award immediately before the modification; the ASU is effective for all entities for fiscal years beginning after December 15, 2017, including interim periods within those years. Early adoption is permitted, including adoption in an interim period. The Company adopted this ASU on January 1, 2018. The Company expects the adoption of this ASU will only impact consolidated financial statements as and when there is a modification to its share-based award agreements.

On January 5, 2017, the FASB issued ASU 2017-01 Business Combinations (Topic 805): Clarifying the Definition of a Business, 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 this ASU on January 1, 2018, and expects that the adoption of this ASU could have a material impact on future consolidated financial statements as there may be acquisitions that are no longer considered to be business combinations.

On November 17, 2016, the FASB issued ASU 2016-18, Restricted Cash (Topic 230), to clarify the presentation of restricted cash in the statement of cash flows. The amendments require that a statement of cash flows explain the change during the period in restricted cash or restricted cash equivalents. In addition, changes in cash and cash equivalents, restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. As a result, transfers between cash and restricted cash will not be presented as a separate line item in the operating, investing or financing section of the cash flow statement. The amendments are effective for public entities for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted. The Company adopted this ASU on January 1, 2018 and since the Company has no restricted cash, there is no current impact to the consolidated statement of cash flows.

On August 26, 2016, the FASB issued ASU No. 2016-15, Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force. The amendments in ASU 2016-15 address eight specific cash flow issues and apply to all entities, including both business entities and not-for-profit entities that are required to present a statement of cash flows under ASC 230, Statement of Cash Flows. The amendments in ASU 2016-15 are effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The Company adopted this ASU on January 1, 2018. The Company does not anticipate the adoption of this ASU will have a material effect on its consolidated financial statements and related disclosures.

On March 30, 2016, the FASB issued ASU 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. This ASU will simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This ASU is effective for annual and interim periods beginning in 2017 with early adoption permitted. The Company adopted this ASU on January 1, 2017. The Company grants primarily qualified incentive stock options which do not require the Company to withhold any income taxes when these options are exercised. As of December 31, 2017, none of the four employees who have non-qualified stock options have exercised their vested options. During the year ended December 31, 2017, the Company withheld income taxes for vested restricted shares but these tax withholdings were processed by a third-party payroll service company. The tax withholding payments were received from the employees who elected to pay cash within 30 days following the Company’s payment to the third-party payroll service company. As a result, these funds flowed through the operating section of the Company’s consolidated statement of cash flows and had no impact on its consolidated statement of operations.

On March 14, 2016, the FASB issued ASU 2016-06, Derivatives and Hedging (Topic 815): Contingent Put and Call Options in Debt Instruments. This new standard simplifies the embedded derivative analysis for debt instruments containing contingent call or put options by removing the requirement to assess whether a contingent event is related to interest rates or credit risks. This new standard was effective for the Company on January 1, 2017. The Company has identified the conversion feature of its debt instrument as an embedded derivative which meets the criteria to be bifurcated from its host contract, the Second Lien Credit Agreement (as defined below), and accounted for at fair value as derivative liabilities.

On February 25, 2016, the FASB issued ASU 2016-02, Leases (Topic 842), 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 the new ASU. As of December 31, 2017, the Company currently has only one operating lease within the scope of this standard that expires in less than 2 years. The effect of this guidance relating to the Company’s existing long-term leases is expected to require additional disclosures, and the Company is currently evaluating the impact that this ASU would have on the Company’s consolidated financial statements.

On May 28, 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, its final standard on revenue from contracts with customers. ASU 2014-09 outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The core principle of the revenue model is that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In applying the revenue model to contracts within its scope, an entity identifies the contract(s) with a customer, identifies the performance obligations in the contract, determines the transaction price, allocates the transaction price to the performance obligations in the contract and recognizes revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 applies to all contracts with customers and requires significantly expanded disclosures about revenue recognition. ASU 2014-09 has been amended several times with subsequent ASUs including ASU 2015-14 Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date. ASU 2014-09 will be effective for the Company on January 1, 2018, with early adoption permitted, but not earlier than January 1, 2017. The guidance under these standards is to be applied using a full retrospective method or a modified retrospective method. The Company has adopted the standard on January 1, 2018 using the modified retrospective approach. The Company has a small number of contracts with customers and has identified transactions within the scope of the standard. The Company has reviewed each of the contracts and transactions within the scope of the new standard. Based on the Company’s assessment, the adoption of the new standard will not have a material impact on the Company’s consolidated financial statements. As a result of adoption of ASU 2014-09, the Company has changed its method of recording certain natural gas gathering and processing charges that were previously recorded as expenses and will now be recorded as a reduction of revenues under the new standard. The Company has also changed its method of recording gas balancing arrangements to recognize revenues from gas balancing arrangements only when a transaction with a customer has occurred. As of the date of adoption, the Company did not have any outstanding gas balancing arrangements. Such changes are not expected to result in a material change in the Company’s controls and processes.

OIL AND NATURAL GAS PROPERTIES

12 Months Ended

Dec. 31, 2017

Extractive Industries [Abstract]

OIL AND NATURAL GAS PROPERTIES

NOTE 3 - OIL AND NATURAL GAS PROPERTIES

The following table sets forth a summary of oil and natural gas property costs (net of divestitures) not being amortized at December 31, 2017 and 2016:

	December 31,
	2017		2016
	(In thousands)
Unproved acreage:
Beginning Balance	$	24,461	$	-
Lease purchases		78,110		546
Assets conveyed		-		23,915
Transfer and other reclassification to properties		(800)		-
Total unproved acreage	$	101,771	$	24,461

Wells in progress:
Beginning Balance	$	7,453	$	-
Additions		-		7,453
Reclassification to proved properties		(7,453)		-
Total wells in progress not subject to DD&A	$	-	$	7,453

At December 31, 2017 and 2016, the Company completed an assessment of its inventory of unproved acreage for impairment, which resulted in no transfers from unproved acreage to proved properties.

Depreciation, depletion and amortization expense related to proved properties was approximately $7.0 million and $1.7 million for the years ended December 31, 2017, and 2016, respectively.

Divestiture of Oil and Natural Gas Properties

On March 31, 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 9 - Related Party Transactions. The net proceeds of $1.08 million received on March 31, 2017 included an offset against $0.7 million of severance pay and $0.22 million of net sales adjustments due to the purchaser. In addition, the Company received $0.2 million in proceeds from the sale of non-operated properties sold in 2017.

Acquisition of Unproved Properties

On October 3, 2017, the Company entered into a lease acquisition agreement (the “Acquisition Agreement”) with KEW Drilling, a Delaware limited partnership (“KEW”), pursuant to which the Company acquired from KEW unproved acreage in Winkler County, Texas for an aggregate purchase price of $48.9 million pursuant to the terms set forth in the Acquisition Agreement (collectively, the “Leases”). The Company funded the purchase price for the leases with borrowings drawn under the Delayed Draw Term Loans pursuant to the Second Lien Credit Agreement as described in Note 7 - Long-term Debt below.

FAIR VALUE OF FINANCIAL INSTRUMENTS

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [Abstract]

FAIR VALUE OF FINANCIAL INSTRUMENTS

NOTE 4 - FAIR VALUE OF FINANCIAL INSTRUMENTS

The Company measures 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. We utilize 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		Significant Other Observable Inputs		Significant Unobservable Inputs
	(Level 1)		(Level 2)		(Level 3)		Total
	(in thousands)
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)
As of December 31, 2016
Warrant liabilities		-		-		(1,400)		(1,400)
Total	$	-	$	-	$	(1,400)	$	(1,400)

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 “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 below) 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 consolidated statement operations. The embedded derivatives under the Second Lien Credit Agreement including the delayed draw term loans were recorded at closing as a derivative liability with a fair value of approximately $65.6 million. At December 31, 2017, the fair value of the derivative liabilities associated with the Loan conversion features was approximately $72.7 million. As a result, the Company recorded an unrealized loss of $7.1 million on the change in fair value of derivative liabilities associated with the Loan conversion features.

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.

Heartland Warrant Liability. On January 8, 2015, the Company entered into a credit agreement with Heartland Bank (the “Heartland Credit Agreement”). In connection with the Heartland Credit Agreement, the Company issued a warrant to purchase up to 22,500 shares of the Company’s common stock at an exercise price of $25.00. The warrant contained a price protection feature that would have automatically reduced the exercise price if the Company entered into another agreement pursuant to which warrants were issued with a lower exercise price and would also have triggered an adjustment to the number of underlying shares of common stock. On June 14, 2017, the Company and Heartland executed an amended and restated warrant agreement whereby the Company issued a warrant to purchase 160,714 shares of common stock at an exercise price of $3.50 to replace the original warrant to purchase 22,500 shares of common stock to settle a disagreement regarding the impact of the anti-dilutive price protection provisions in the original warrant. The amended and restated warrant agreement no longer contains any anti-dilutive price protection provisions and the warrant is no longer accounted for as a derivative. As a result of the issuance of the amended and restated warrant, the Company recorded approximately $0.02 million of realized gain on the Heartland warrant liability during the year ended December 31, 2017. For the year ended December 31, 2016, the Company recorded an unrealized loss of approximately $0.04 million on the Heartland warrant liability.

SOS Warrant Liability. On June 23, 2016, in conjunction with the merger with Brushy in June 2016, the Company issued to SOS a warrant to purchase up to 200,000 shares of the Company’s common stock at an exercise price of $25.00. The warrant contains 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. The fair value of the warrants was approximately $0.2 million at December 31, 2017. For the years ended December 31, 2017, and 2016, the Company incurred an unrealized loss of approximately $0.1 million and an unrealized gain of $0.02 million, respectively, on the SOS warrant liability. As of December 31, 2017 and 2016, the fair value of the SOS warrant liability was approximately $0.2 million and $0.1 million, respectively.

Bristol Capital, LLC Warrant Liability. On September 2, 2014, the Company entered into a consulting agreement with Bristol Capital, LLC (“Bristol”), pursuant to which the Company issued to Bristol a warrant to purchase up to 100,000 shares of the Company’s common stock at an exercise price of $20.00 (or, in the alternative, options exercisable for 100,000 shares of common stock, but in no case, both). The agreement had a price protection feature that automatically reduced the exercise price if the Company entered into another consulting agreement pursuant to which warrants were issued with a lower exercise price, which was triggered in year 2016. On March 14, 2017, the Company issued 77,131 shares of common stock to Bristol pursuant to a settlement agreement for a cashless exercise of the warrant. The Bristol warrant was also revalued on March 14, 2017 resulting in a realized gain in fair value of $0.8 million for the year ended December 31, 2017 and decreasing the Bristol derivative liability to $0.4 million. As a result of the cashless exercise, the Company reclassified the $0.4 million of Bristol derivative liability to additional paid-in capital as of March 31, 2017. For the year ended December 31, 2016, the Company recorded an unrealized loss of approximately $1.2 million on the Bristol warrant liability.

The following table sets forth a reconciliation of changes in the fair value of the Company’s financial assets and liabilities classified as Level 3 in the fair value hierarchy, except for the commodity derivatives classified as Level 2 as disclosed in Note 6, as of December 31, 2017 and 2016:

	Second Lien Term Loan Conversion Features		Warrant Liabilities		Total
	(in thousands)
Balance at January 1, 2017	$	-	$	(1,400)	$	(1,400)
Issuance		(65,647)		-		(65,647)
Cashless exercise of warrants		-		370		370
Change in fair value of derivative liabilities		(7,067)		807		(6,260)
Balance at December 31, 2017	$	(72,714)	$	(223)	$	(72,937)

	Convertible Debenture Derivative Liability		Warrant Liabilities		Incentive Bonus		Total
	(in thousands)
Balance at January 1, 2016	$	(6)	$	(56)	$	(223)	$	(285)
Additional liability		-		(164)		(393)		(557)
Reversal of accrued bonus		-		-		718		718
Converted to equity		(54)		-		-		(54)
Change in fair value of derivative liabilities		60		(1,180)		(102)		(1,222)
Balance at December 31, 2016	$	-	$	(1,400)	$	-	$	(1,400)

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

DERIVATIVES

12 Months Ended

Dec. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVES

NOTE 6 - DERIVATIVES

As discussed in Note 4, 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 consolidated statement of operations for the year ended December 31, 2017. The Company recorded derivative liabilities associated with the Second Lien Term Loan at an original fair value of approximately $65.6 million at issuance. As of December 31, 2017, the fair value of the derivative liability was approximately $72.7 million. As a result, the Company recognized unrealized gains of approximately $7.1 million in its consolidated statement of operations for the year ended December 31, 2017. There were no derivative liabilities associated with convertible debt instruments for the year ended December 31, 2016. In addition, as of December 31, 2017 and 2016, the Company’s outstanding derivative liabilities included the fair value of the derivative liabilities associated with the SOS warrants totaled $0.2 million and $0.2 million, respectively.

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 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 positions as of December 31, 2017:

	As of December 31,
	2017
	(In thousands)
Oil positions:
Fixed-for-floating price swaps (NYMEX WTI):
Hedged Volume (Bbls)		75,070
Average price ($/Bbl)	$	50.74

Put Options (NYMEX WTI):
Hedged Volume (Bbls)		105,930
Average price ($/Bbl)	$	52.50

Call Options (NYMEX WTI):
Hedged Volume (Bbls)		105,930
Average price ($/Bbl)	$	60.80

	Year Ended December 31,
	2017
	(In thousands)
Beginning fair value of commodity derivatives	$	—
Net losses on crude oil derivatives		(1,063)
Net settlement paid on crude oil derivative contracts		96
Net settlement unpaid on crude oil derivative contracts		114
Ending fair value of commodity derivatives	$	(853)

The Company’s derivatives are presented on a net basis under fair value of derivative instruments on the consolidated balance sheets. The following information summarizes the gross fair values of derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Company’s consolidated balance sheets:

	December 31, 2017
	Gross Amount of Recognized Assets and Liabilities		Gross Amounts Offset in the Consolidated Balance Sheets		Net Amounts Presented in the Consolidated Balance Sheets
	(in thousands)
Offsetting Derivative Assets:
Current asset	$	-	$	-	$	-
Long-term asset		-		-		-
Total asset	$	-	$	-	$	-
Offsetting Derivative Liabilities:
Current liability	$	853	$	-	$	853
Long-term liability		-		-		-
Total liability	$	853	$	-	$	853

The Company had no hedging activities as of December 31, 2016.

LONG-TERM DEBT

12 Months Ended

Dec. 31, 2017

Long-term Debt, Unclassified [Abstract]

LONG-TERM DEBTS

NOTE 7 - LONG-TERM DEBT

	As of December 31,
	2017		2016
	(In thousands)
6% Bridge Loans associated with the amended First Lien Term Loan, due 2019, net of debt issuance costs	$	30,363	$	-
6% Senior Secured Term Loan, due 2019, net of debt issuance costs		-		29,214
8.25% Second Lien Term Loans, due 2021, net of debt issuance costs and debt discount		96,431		-
6% note payable to SOS Investment, LLC, due 2019		1,000		1,000
Other notes payable, due 2018		11		29
Total Long-term debt	$	127,805	$	30,243
Less: current portion		(11)		(17)
Total Long-term debt, net of current portion	$	127,794	$	30,226

Total principal amount of debt maturities related to borrowings for the five years ending December 31, 2022 include: $0.01 million in 2018, $31.0 million in 2019, and $150.0 million in 2021. There will be no payments due in 2020 and 2022.

At December 31, 2017 and 2016, the carrying amounts of term loans were as follows:

	Principal Amount		Paid-in- kind Interest		Unamortized Debt Issuance Costs & Debt Discount		Carrying Amount
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 Loan, due April 2021		150,000		5,752		(59,321)		96,431
Total:	$	180,000	$	6,559	$	(59,765)	$	126,794

December 31, 2016:
Senior Secured Term Loan, due 2019	$	31,000	$	-	$	(1,786)	$	29,214
Total:	$	31,000	$	-	$	(1,786)	$	29,214

First Lien Credit Agreement

On September 29, 2016, the Company entered into a first lien credit agreement by and among the Company and its wholly owned subsidiaries, Brushy, Impetro Operating and Resources (the “Initial Guarantors”), and the lenders party thereto (each a “Lender” and together, the “Lenders”) and T.R. Winston & Company, LLC (“TRW”) acting as initial collateral agent (the “First Lien Credit Agreement”).

The First Lien Credit Agreement provided for a $50 million three-year senior secured term loan with initial commitments of $31 million. On February 7, 2017, pursuant to the terms of the First Lien Credit Agreement, the Company exercised the accordion advance feature, increasing the aggregate principal amount outstanding under the term loan from $31 million to $38.1 million (the “First Lien Term Loan”).

In connection with the exercise of the accordion advance feature for $7.1 million, the Company incurred $0.4 million in commitment fees and also amended certain warrants held by the lenders to purchase up to approximately 738,638 shares of common stock, such that the exercise price per share was lowered from $2.50 to $0.01. The Company accounted for these repriced warrants as additional debt discount to the First Lien Term Loan for $1.0 million, to be accreted, together with the remaining $0.6 million debt discount at December 31, 2016, over the remaining term of the loan. On April 26, 2017, the Company fully paid off the amount outstanding of $38.1 million including accrued interest on the First Lien Term Loan. As a result, for the year ended December 31, 2017, the Company fully amortized approximately $1.4 million of debt discount and approximately $1.6 million of deferred financing costs, respectively. These amounts were recorded as a non-cash component of interest expense.

Amendments to First Lien Credit Agreement

On April 24, 2017, and subsequently on April 26, 2017, and July 25, 2017, and October 19, 2017 the Company entered into the first, second, third and fourth amendments (together, the “First Lien Amendments”), respectively, to the Company’s First Lien Credit Agreement. The First Lien Amendments, among other things, added Lilis Operating and Hurricane Resources as guarantors under the credit agreement, added certain lenders, and extended further credit in the form of an initial bridge loan in an aggregate principal amount of $15.0 million (the “Initial Bridge Loan”). The Initial Bridge Loan was fully drawn on April 24, 2017, and is secured by the same first priority liens on substantially all of the Company’s assets as the First Lien Term Loan. Additionally, pursuant to the First Lien Amendments, the lenders made further extensions of credit, in addition to the currently existing loans under the First Lien Credit Agreement (the “Bridge Loans”), in the form of an additional, incremental bridge loan in an aggregate principal amount of $15,000,000 (the “Incremental Bridge Loan”, and together with the Bridge Loans, the “First Lien Loans”). The First Lien Loans, including the Incremental Bridge Loan, were fully drawn as of October 19, 2017. As of December 31, 2017, the unamortized portion of the debt issuance costs associated with the First Lien Loans were approximately $0.3 million.

The First Lien Credit Agreement, as amended, (a) provides that, effective as of October 1, 2017, the unpaid principal of the First Lien Loans will bear (i) cash interest at a rate per annum of 10% and (ii) additional interest at a rate per annum of 6%, payable only in-kind by increasing the principal amount of the First Lien Loans by the amount of such interest due on each interest payment date and (b) permits the loans under the Second Lien Credit Agreement to equal an increased amount of up to $175.0 million. The First Lien Loans mature on October 21, 2018 and may be repaid in whole or part at any time at the option of the Company, subject to the payment of certain specified prepayment premiums. Additionally, the First Lien Loans are subject to mandatory prepayment with the net proceeds of certain asset sales and casualty events, subject to the right of the Company to reinvest the net proceeds of asset sales and casualty events within 180 days. The Company subsequently used approximately $31.5 million of the proceeds of the Riverstone First Lien Loans (hereinafter defined) to repay in full our obligations under and retire the First Lien Credit Agreement. As the First Lien Loans were fully repaid subsequent to December 31, 2017, these loans were classified as long-term.

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 in two 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 per annum of 8.25%, compounded quarterly in arrears and payable only in-kind by increasing the principal amount of the loan by the amount of the interest due on each interest payment date.

On October 3, 2017, the Company, certain subsidiaries of the Company, as guarantors (the “Guarantors”), Wilmington Trust, National Association, as administrative agent and the lenders party thereto, 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 Drilling, a Delaware limited partnership. 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.

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 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 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 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 (the “Conversion Sum”), 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 the Conversion Sum 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 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.

As discussed in Note 4, Fair Value of Financial Instruments, above and Note 6, Derivatives, above, the Company separately accounts for the embedded conversion features 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 Second Lien Term Loan. The debt discount is amortized over the term of the Second Lien Term Loan using the effective interest method.

Restrictive Covenants

As of December 31, 2017, the Company’s First Lien Credit Agreement and Second Lien Credit Agreement contain various covenants, including restrictions on additional indebtedness, payment of cash dividends on common stock and preferred stock, and maintenance of certain financial ratios. The First Lien Credit Agreement, as amended, requires that, commencing with the testing period ending at December 31, 2018, we satisfy an asset coverage ratio (“ACR”) test by maintaining an ACR of 1.00 to 1.00 or greater. In addition, the Second Lien Credit Agreement requires us to maintain, commencing with the testing period ending June 30, 2018, an ACR of 1.00 to 1.00. or greater. At December 31, 2017, the Company was in compliance with all restricted covenants.

SOS Note

On June 30, 2016, pursuant to the merger agreement with Brushy and as a condition of the fourth amendment to such merger agreement, the Company was required to make a cash payment of $500,000 to SOS, and also executed a subordinated promissory note with SOS, for $1 million, at an interest rate of 6% per annum which matures on June 30, 2019. In conjunction with the cash payment and the note, the Company also issued 200,000 warrants at an exercise price of $25.00. The Company accounted for the cost of warrants of $0.2 million as part of the Brushy merger transaction costs during the year ended December 31, 2016. The SOS note was fully paid on January 22, 2018.

Interest Expense

The components of interest expense are as follows:

	Years Ended December 31,
	2017		2016

Interest on term loans	$	1,774	$	446
Interest on notes payable		53		412
Interest on convertible notes and debentures ⁽¹⁾		-		880
Paid-in-kind interest on term loans		6,559		-
Amortization of debt financing costs on term loans		1,886		328
Amortization of discount on term loans		8,485		2,858
Total:	$	18,757	$	4,924

(1)

These convertible notes and debentures including accrued interest were fully converted into the Company’s common stock upon closing of the Brushy merger on June 23, 2016.

COMMITMENTS AND CONTINGENCIES

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

NOTE 8 - COMMITMENTS AND CONTINGENCIES

Environmental and Governmental Regulation

At December 31, 2017, 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 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 December 31, 2017, the Company had not been fined or cited for any violations of governmental regulations that would have a material adverse effect upon the financial condition of the Company.

Legal Proceedings

The Company may from time to time be involved in various legal actions arising in the normal 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.

Operating Leases

The Company has a two-year operating lease for office space in San Antonio, Texas and various other operating leases on a month-to-month basis which include office leases in Fort Worth and Houston, Texas and corporate apartment leases in San Antonio, Texas. Rent expense for the years ended December 31, 2017 and 2016, was approximately $0.6 million and $0.2 million, respectively. As of December 31, 2017, the Company has approximately $0.2 million of minimum lease payments on its operating lease which consists of annual minimum lease payments of approximately $0.2 million in 2018.

Consolidated Statements of Operations [Parenthetical]	12 Months Ended
Consolidated Statements of Operations [Parenthetical]	Dec. 31, 2017	Dec. 31, 2016
Percentage Of Redeemable Preferred Stock	6.00%	6.00%