LILIS ENERGY, INC. - FORM 10-Q

Attached files

file	filename
EX-32.2 - EXHIBIT 32.2 - LILIS ENERGY, INC.	v476323_32-2.htm
EX-32.1 - EXHIBIT 32.1 - LILIS ENERGY, INC.	v476323_32-1.htm
EX-31.2 - EXHIBIT 31.2 - LILIS ENERGY, INC.	v476323_31-2.htm
EX-31.1 - EXHIBIT 31.1 - LILIS ENERGY, INC.	v476323_31-1.htm
EX-10.5 - EXHIBIT 10.5 - LILIS ENERGY, INC.	v476323_10-5.htm
EX-2.1 - EXHIBIT 2.1 - LILIS ENERGY, INC.	v476323_2-1.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2017

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

For the transition period from ______to______.

Commission file number: 001-35330

Lilis Energy, Inc.

(Name of registrant as specified in its charter)

Nevada

74-3231613

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

300 E. Sonterra Blvd., Suite No. 1220, San Antonio, TX 78258

(Address of principal executive offices, including zip code)

Registrant’s telephone number including area code: (210) 999-5400

Indicate by check mark if the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Act.

Large accelerated filer	¨	Accelerated filer	¨
Non-accelerated filer	¨	Smaller reporting company	x
(Do not check if a smaller reporting Company)		Emerging growth Company	¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

As of November 13, 2017, 53,300,332 shares of the registrant’s common stock were issued and outstanding.

Lilis Energy, Inc.

INDEX

PART I - FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)
	Condensed Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016	4
	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2017 and 2016	6
	Condensed Consolidated Statement of Changes in Stockholders’ Equity (Deficit) for the Nine Months Ended September 30, 2017	7
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2017 and 2016	8
	Notes to the Condensed Consolidated Financial Statements	9

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	43
Item 4.	Controls and Procedures	43

PART II - OTHER INFORMATION

Item 1.	Legal Proceedings	43
Item 1A.	Risk Factors	43
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	44
Item 4.	Mine Safety Disclosures	44
Item 5.	Other Information	44
Item 6.	Exhibits	44

SIGNATURES		47

EXHIBIT INDEX		48

FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q, including materials incorporated by reference herein, contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. All statements other than statements of historical fact are “forward-looking statements” for purposes of federal and state securities laws, including, but not limited to, any projections of earnings, revenue or other financial items; any statements of the plans, strategies and objectives of management for future operations; any statements concerning future production, reserves or other resource development opportunities; any projected well performance or economics, or potential joint ventures or strategic partnerships; any statements regarding future economic conditions or performance; any statements regarding future capital-raising activities; any statements of belief; and any statements of assumptions underlying any of the foregoing.

Forward-looking statements may include the words “may,” “should,” “could,” “estimate,” “intend,” “plan,” “project,” “continue,” “believe,” “expect” or “anticipate” or other similar words. These forward-looking statements present our estimates and assumptions only as of the date of this report. Except as required by law, we undertake no obligation to update any forward-looking statement.

Although we believe that the expectations reflected in any of our forward-looking statements are reasonable, actual results could differ materially from those projected or assumed in any of our forward-looking statements. Our future financial condition and results of operations, as well as any forward-looking statements, are subject to change and inherent risks and uncertainties. The factors impacting these risks and uncertainties include, the risk factors discussed in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2016 and the following additional factors:

•		our estimates regarding operating results, future revenues and capital requirements;
•		availability of capital on an economic basis, or at all, to fund any continuing capital or operating needs;
•		our level of debt, which could adversely affect our ability to raise additional capital, limit our ability to react to economic changes and make it more difficult to meet our obligations under our debt;
•		restrictions imposed on us under our credit agreements or other debt instruments that limit our discretion in operating our business;
•		the loss of any members of our management team;
•		potential default under our material debt agreements;
•		failure to meet requirements or covenants under our debt instruments, which could lead to foreclosure of significant core assets;
•		failure to fund our authorization for expenditures from other operators for key projects which will reduce or eliminate our interest in the wells/asset;
•		the inability of management to effectively implement our strategies and business plans;
•		estimated quantities and quality of oil and natural gas reserves;
•		exploration, exploitation and development results;
•		fluctuations in the price of oil and natural gas, including further reductions in prices that would adversely affect our revenue, cash flow, liquidity and access to capital;
•		availability of, or delays related to, drilling, completion and production, personnel, supplies (including water) and equipment;
•		the timing and amount of future production of oil and natural gas;
•		the timing and success of our drilling and completion activity;
•		lower oil and natural gas prices negatively affecting our ability to borrow or raise capital, or enter into joint venture arrangements;
•		declines in the values of our oil and natural gas properties resulting in further write-downs or impairments;
•		inability to hire or retain sufficient qualified operating field personnel;
•		our ability to successfully identify and consummate acquisition transactions;
•		our ability to successfully integrate acquired assets or dispose of non-core assets; and
•		the occurrence of natural disasters, unforeseen weather conditions, or other events or circumstances that could impact our operations or could impact the operations of companies or contractors we depend upon in our operations.

Many of these factors are beyond our ability to control or predict. These factors are not intended to represent a complete list of the general or specific factors that may affect us.

LILIS ENERGY, INC.

Condensed Consolidated Balance Sheets

(In thousands, except share and per share data)

(Unaudited)

	September 30,			December 31,
	2017			2016

ASSETS
Current assets:
Cash and cash equivalents	$	17,820		$	11,738
Accounts receivable, net of allowance of $118 and $106, respectively		4,599			2,247
Prepaid expenses and other current assets		654			767
Total current assets		23,073			14,752
Oil and natural gas properties, full cost method of accounting
Unproved		47,546			24,461
Proved		115,294			69,809
Less: accumulated depreciation, depletion, amortization and impairment		(59,527	)		(55,771	)
Total oil and natural gas properties, net		103,313			38,499

Other property and equipment, net		81			52
Other assets		343			216
Total other assets		424			268

Total assets	$	126,810		$	53,519

The accompanying notes are an integral part of these condensed consolidated financial statements.

LILIS ENERGY, INC.

Condensed Consolidated Balance Sheets

(In thousands, except share and per share data)

(Unaudited)

	September 30,			December 31,
	2017			2016

LIABILITIES, REDEEMABLE PREFERRED STOCK AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	7,561		$	5,166
Accrued liabilities		13,958			2,706
Dividends payable		-			808
Asset retirement obligations		194			338
Current portion of long-term debt		14			17
Total current liabilities		21,727			9,035
Asset retirement obligations		938			919
Long-term debt, net of current portion		65,710			30,226
Long-term derivative liabilities		33,475			1,400
Total liabilities		121,850			41,580

Commitments and contingencies (Note 11)

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		-			1,874

Stockholders’ Equity:
Series B convertible 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		-			13,432
Common stock, $0.0001 par value; 150,000,000 shares authorized, 50,763,137 and 20,918,901 shares issued and outstanding as of September 30, 2017 and December 31, 2016, respectively		5			2
Additional paid-in capital		266,300			219,837
Accumulated deficit		(261,345	)		(223,206	)
Total stockholders’ equity		4,960			10,065

Total liabilities, redeemable preferred stock and stockholders’ equity	$	126,810		$	53,519

The accompanying notes are an integral part of these condensed consolidated financial statements.

LILIS ENERGY, INC.

Condensed Consolidated Statements of Operations

(In thousands, except share and per share data)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Revenue:
Oil, natural gas and natural gas liquid sales	$	5,390		$	1,158		$	13,779		$	2,180

Costs and expenses:
Production costs		1,814			613			4,178			978
Production taxes		290			61			710			115
General and administrative		10,943			4,582			36,273			9,741
Depreciation, depletion, accretion and amortization		1,443			601			3,946			1,162
Total costs and expenses		14,490			5,857			45,107			11,996

Loss from operations		(9,100	)		(4,699	)		(31,328	)		(9,816	)

Other income (expenses):
Other income (expense)		151			51			19			297
Gain on modification of convertible debentures		-			602			-			602
Inducement expense		-			(3,180	)		-			(8,307	)
Change in fair value of derivative liabilities		6,368			(438	)		4,295			(535	)
Change in fair value of conditionally redeemable 6% preferred stock		-			134			(41	)		(644	)
Interest expense		(3,656	)		(617	)		(11,084	)		(4,220	)
Total other income (expenses)		2,863			(3,448	)		(6,811	)		(12,807	)

Net loss		(6,237	)		(8,147	)		(38,139	)		(22,623	)
Dividends on redeemable preferred stock		-			(30	)		(122	)		(90	)
Dividend on Series A Convertible Preferred Stock		-			-			-			(287	)
Loss on extinguishment of Series A Convertible Preferred Stock		-			(300	)		-			(540	)
Dividends and deemed dividends on Series B Convertible Preferred Stock		-			-			(4,635	)		(8,206	)
Net loss attributable to common shareholders	$	(6,237	)	$	(8,477	)	$	(42,896	)	$	(31,746	)

Net loss per common share basic and diluted	$	(0.12	)	$	(0.50	)	$	(1.06	)	$	(2.59	)
Weighted average shares outstanding:
Basic and diluted		50,785,588			17,113,942			40,596,281			12,280,013

The accompanying notes are an integral part of these condensed consolidated financial statements.

LILIS ENERGY, INC.

Condensed Consolidated Statement of Changes in Stockholders’ Equity (Deficit)

Nine Months Ended September 30, 2017

(In thousands, except share and per share data)

(Unaudited)

	Series B Preferred											Additional
	Shares						Common Shares					Paid In			Accumulated
	Shares			Amount			Shares			Amount		Capital			Deficit			Total

Balance, December 31, 2016		16,828		$	13,432			20,918,901		$	2	$	219,837		$	(223,206	)	$	10,065
Stock based compensation		-			-			-			-		14,477			-			14,477
Restricted stock awards		-			-			2,720,918			-		-			-			-
Common stock for exercise of stock options		-			-			263,735			-		227						227
Common stock withheld for taxes on stock based compensation		-			-			(523,411	)		-		(2,427	)		-			(2,427	)
Common stock for drilling services		-			-			22,938			-		97			-			97
Exercise of warrants		-			-			5,487,078			-		165			-			165
Cashless exercise of warrants		-			-			77,131			-		371			-			371
Conversion of Series B preferred stock and dividends to common stock		(16,828	)		(13,432	)		16,601,026			2		14,863			-			1,433
Common stock for private placement, net		-			-			5,194,821			1		18,649			-			18,650
Warrant repriced for term loan		-			-			-			-		1,031			-			1,031
Dividends on conditionally redeemable preferred stock		-			-			-			-		(122	)		-			(122	)
Dividends and deemed dividends on Series B preferred stock		-			-			-			-		(868	)		-			(868	)
Net loss		-			-			-			-		-			(38,139	)		(38,139	)
Balance, September 30, 2017		-		$	-			50,763,137		$	5	$	266,300		$	(261,345	)	$	4,960

The accompanying notes are an integral part of these condensed consolidated financial statements.

LILIS ENERGY, INC.

Condensed Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)

	Nine Months Ended September 30,
	2017			2016
Cash flows from operating activities:
Net loss	$	(38,139	)	$	(22,623	)
Adjustments to reconcile net loss to net cash used in operating activities:
Equity instruments issued for compensation		14,477			3,552
Inducement expense		-			8,307
Bad debt expense		12			200
Amortization of debt issuance cost and debt discount		6,703			2,958
Paid-in-kind interest		3,258			-
(Gain) loss in fair value of derivative instruments		(4,295	)		535
Loss in fair value of conditionally redeemable 6% preferred stock		41			644
Depreciation, depletion, accretion and amortization		3,946			1,162
Gain on modification of convertible debentures		-			(602	)
Gain on extinguishment of debt		-			(250	)
Changes in operating assets and liabilities:
Accounts receivable		(2,364	)		166
Prepaid expenses and other assets		(13	)		(555	)
Accounts payable and accrued liabilities		8,764			(11	)
Net cash used in operating activities		(7,610	)		(6,517	)

Cash flows from investing activities:
Cash advance to Brushy Resources, Inc.		-			(552	)
Net proceeds from sale of DJ Basin and non-operated properties		1,282			-
Capital expenditures		(64,971	)		(3,418	)
Net cash used in investing activities		(63,689	)		(3,970	)

Cash flows from financing activities:
Net proceeds from issuance of Series B Preferred Stock		-			18,195
Proceeds from issuance of convertible notes		-			2,863
Proceeds from exercise of accordion feature of the First Lien Term Loan, net of financing costs		6,706			-
Proceeds from Bridge Loan and Second Lien Term Loan, net of financing costs		94,700			-
Repayment of the First Lien Term Loan		(38,100	)		-
Repayment of conditionally redeemable 6% preferred stock including dividends		(2,276	)		-
Proceeds from warrant exercise		165			187
Proceeds from exercise of stock options		227			-
Payment for tax withholding on stock based compensation		(2,427	)		-
Proceeds from private placement, net of financing costs		18,399			-
Proceeds from the First Lien Term Loan, net of financing costs		-			24,000
Repayment of notes payable		(13	)		(13,879	)
Net cash provided by financing activities		77,381			31,366
Increase in cash		6,082			20,879
Cash and cash equivalents at beginning of period		11,738			110
Cash and cash equivalents at end of period	$	17,820		$	20,989
Supplemental disclosure:
Cash paid for interest	$	1,594		$	217

The accompanying notes are an integral part of these condensed consolidated financial statements.

LILIS ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

NOTE 1 - ORGANIZATION

Lilis Energy, Inc. (“Lilis”, “Lilis Energy” and the “Company”) is an independent oil and natural gas exploration and production company focused on the Delaware Basin in Reeves, Winkler and Loving Counties, Texas and Lea County, New Mexico.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND ESTIMATES

Principles of Consolidation

The condensed consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. As of September 30, 2017, the Company’s wholly owned subsidiaries include Brushy Resources, Inc. (“Brushy”), ImPetro Operating, LLC (“ImPetro Operating”), ImPetro Resources, LLC (“Resources”), Lilis Operating Company, LLC (“Lilis Operating”), and Hurricane Resources LLC (“Hurricane Resources”). All significant intercompany accounts and transactions have been eliminated in consolidation.

Interim Financial Statements

In management’s opinion, these unaudited condensed consolidated financial statements reflect all adjustments, consisting only of normal and recurring adjustments, necessary to fairly state the Company’s financial position as of, and results of operations for, the periods presented. These financial statements should be read in conjunction with the financial statements and related notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016. The Company’s accounting policies are described in the Notes to the Condensed Consolidated Financial Statements in its Annual Report on Form 10-K for the year ended December 31, 2016, and updated, as necessary, in this Quarterly Report on Form 10-Q.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”) requires the Company to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ significantly from those estimates. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. Although actual results may differ from these estimates under different assumptions or conditions, the Company believes that its estimates are reasonable.

The most significant financial estimates are associated with the Company’s estimated volumes of proved oil and natural gas reserves, asset retirement obligations, assessments of impairment on oil and natural gas properties, fair value of financial instruments including derivative liabilities, depreciation and accretion, income taxes and contingencies.

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. For the three and nine months ended September 30, 2016, the income from operator’s overhead recovery of $60,615 and $75,731, respectively, have been reclassified from revenues to operating expenses as an offset against general and administrative expenses.

Oil and Natural Gas Producing Activities

The Company follows the full cost method of accounting for oil and natural gas operations whereby all 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 costs 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.

The costs of undeveloped acreage are withheld 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 or the amount of the impairment is added to the full cost pool which is subject to depletion calculations.

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. During the three and nine months ended September 30, 2017 and 2016, respectively, no impairment was recorded.

The present value of estimated future net cash flows was computed by applying a flat oil price to forecasted 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.

The flat oil price is based on the WTI Spot Posting SEC price. Specifically, it is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, as defined by the SEC in Rule 4-10 of Regulation S-X. The flat oil price is adjusted to match up with accounting data through the use of a differential.

Accrued Liabilities

As of September 30, 2017 and December 31, 2016, the Company’s accrued liabilities consisted of the following:

	September 30, 2017		December 31, 2016
	($ in thousands)
Accrued bonus	$	1,194	$	-
Accrued drilling costs		6,963		1,331
Revenue payable		4,707		1,313
Other accrued liabilities		1,094		62
	$	13,958	$	2,706

Asset Retirement Obligations

The Company incurs retirement obligations for certain assets at the time they are placed in service. The present 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 calculations, 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. The asset retirement liability is allocated to operating expense using a systematic and rational method. The Company has accreted approximately $23,000 and $67,000 for the three and nine months ended September 30, 2017, respectively, and approximately $17,000 and $23,000 for the three and nine months ended September 30, 2016, respectively. Accretion expense is recorded in “depreciation, depletion, accretion and amortization” expense in the condensed consolidated statements of operations.

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 natural gas liquid (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 September 30, 2017 and December 31, 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 September 30, 2017 and December 31, 2016, the Company had approximately $4.7 million and $1.3 million, respectively, of such revenue proceeds recorded in accrued liabilities.

Major Customers

During the three and nine months ended September 30, 2017 and 2016, the Company’s major customers as a percentage of total revenue consisted of the following:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Texican Natural Gas Company		86	%		50	%		83	%		68	%
Energy Transfer Partners, L.P.		14	%		13	%		15	%		12	%
Noble Energy		0	%		17	%		0	%		11	%
Others below 10%		0	%		20	%		2	%		9	%
		100	%		100	%		100	%		100	%

Other Property and Equipment, net

Other property and equipment consist principally of property and equipment with finite useful lives (subject to depreciation and amortization). The Company accounts for other property and equipment at cost. The Company may impair this property and equipment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be fully recoverable. Recoverability is measured by comparing the carrying amount of an asset to the expected undiscounted future net cash flows generated by the asset. If it is determined that the asset may not be recoverable, and if the carrying amount of an asset exceeds its estimated fair value, an impairment charge is recognized to the extent of the difference.

Loss Per Share

Basic loss per share was calculated by dividing loss applicable to common shareholders by the weighted average number of common shares outstanding during the periods presented. The weighted average common shares outstanding include issued and outstanding shares of common stock and shares issuable for little or no consideration. The calculation of diluted loss per share includes the weighted average common shares outstanding plus the potential dilutive impact of shares issuable upon the conversion of debt or preferred stock, unvested restricted stock and exercise of warrants and options during the period (common stock equivalents), unless their effect is anti-dilutive.

For the three and nine months ended September 30, 2017 and 2016, common stock equivalents including shares underlying conversion of the term loan, restricted stock units, restricted stock, options, warrants and preferred stock have been excluded from the diluted share calculations as they were anti-dilutive as a result of net losses incurred as follows:

	2017		2016
Stock Options		7,369,000		3,488,333
Restricted Stock Units		9,999		159,583
Series B Preferred Stock		-		18,478,788
Stock Purchase Warrants ⁽¹⁾		12,523,045		12,533,574
Conversion of Term Loan		13,186,584		-
		33,088,628		34,660,278

⁽¹⁾

Excludes warrants exercisable for 2,840,912 shares of common stock at an exercise price of $0.01 for the three and nine months ended September 30, 2016 since these warrants are not anti-dilutive. There were no warrants exercisable at $0.01 per share for the three and nine months ended September 30, 2017.

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 derivatives position as accounting hedges. The Company may consider designating certain derivatives 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 September 30, 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 will adopt this ASU at its effective date. The Company expects the adoption of this ASU would only impact future 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 will adopt this ASU at its effective date, 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 will adopt this ASU at effective date and expects the adoption of this ASU to affect only the consolidated statement of cash flows. As of September 30, 2017, the Company has no restricted cash.

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 will adopt this ASU at the effective date. The Company expects the adoption of this ASU to affect only the consolidated statement of cash flows.

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 September 30, 2017, none of the four employees who have non-qualified stock options have exercised their vested options. During the three months ended September 30, 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 will be 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 separately from the debt instrument.

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 September 30, 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 plans to adopt 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 is currently reviewing the terms of each of its contracts and believes that the preponderance of its revenue transactions are standard oil and gas sales contracts where revenue will be recognized when control passes to the purchaser, similar to current practices. Although the Company will be revising its policies with respect to gas balancing arrangements, the Company currently does not have any gas balancing transactions. The Company will conduct its contract review process throughout the remainder of 2017 and make appropriate changes to business and control processes to support recognition and disclosure under the new standard. Based on the Company’s evaluation to date, the adoption of the ASU 2014-09 is not expected to have a material impact on its consolidated financial statements because existing contractual performance obligations, which determine when and how revenue is recognized, are not materially changed under the new standard. Additionally, the Company is also working on the expanded disclosures related to revenue recognition as required by the new standard.

NOTE 3 - OIL AND NATURAL GAS PROPERTIES & OIL AND NATURAL GAS PROPERTY ACQUISITIONS AND DIVESTITURES

The following table sets forth a summary of oil and natural gas property costs (net of divestitures) not being amortized at September 30, 2017 and December 31, 2016:

	September 30,			December 31,
	2017			2016
	(In thousands)
Unproved unevaluated acreage:
Beginning balance	$	24.461		$	-
Lease purchases		23,085			546
Assets acquired		-			23,915
Total unproved acreage	$	47,546		$	24,461

Wells in progress:
Beginning balance	$	7,453		$	-
Additions		26,458			7,453
Reclassification to evaluated properties		(14,649	)		-
Total wells in progress not subject to DD&A	$	19,262		$	7,453

During the three and nine months ended September 30, 2017 and 2016, no impairment was recorded on the Company’s oil and natural gas properties.

Depreciation, depletion and amortization expense related to proved properties was approximately $1.4 million and $3.9 million for the three and nine months ended September 30, 2017, respectively, and $0.6 million and $1.2 million for the three and nine months ended September 30, 2016, respectively.

Divestiture of DJ Basin 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 7 - 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.

NOTE 4 - 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 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 and unpaid 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 to 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 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. On April 26, 2017, the embedded derivatives were recorded as a derivative liability at a fair value of approximately $36.7 million and approximately $39.6 million as of June 30, 2017. At September 30, 2017, the fair value of the derivative liabilities associated with the Loan conversion features was approximately $33.3 million. As a result, for the three and nine months ended September 30, 2017, the Company recorded an unrealized gain of $6.4 million and $3.5 million, respectively, on the 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 previously issued on January 8, 2015 to settle a disagreement regarding the fair value change pursuant to 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 nine months ended September 30, 2017. For the three and nine months ended September 30, 2016, the Company recorded approximately $0.04 million and $0.04 million, respectively, of unrealized losses 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 SOSV Investment LLC (“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. For the three and nine months ended September 30, 2017, the Company incurred an unrealized gain of approximately $0.1 million and an unrealized loss of approximately $0.06 million, respectively, on the SOS warrant liability. For the three and nine months ended September 30, 2016, the Company incurred an unrealized loss of approximately $0.3 million on the SOS warrant liability.

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 nine months ended September 30, 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.

The following table provides a summary of the recurring fair values of assets and liabilities measured at fair value (in thousands):

September 30, 2017	Level 1		Level 2		Level 3			Total
Recurring fair value measurements:
Warrant liabilities	$	-	$	-	$	(199	)	$	(199	)
Second Lien Term Loan conversion features		-		-		(33,276	)		(33,276	)
Total recurring fair value measurements	$	-	$	-	$	(33,475	)	$	(33,475	)

December 31, 2016	Level 1		Level 2		Level 3			Total
Recurring fair value measurements:
Warrant liabilities	$	-	$	-	$	(1,400	)	$	(1,400	)
Total recurring fair value measurements	$	-	$	-	$	(1,400	)	$	(1,400	)

The following table provides a summary of changes in fair value of the Company’s Level 3 financial assets and liabilities during the nine months ended September 30, 2017 and 2016 (in thousands):

	Second Lien Term Loan Conversion Features			Bristol/ Heartland/SOS Warrant Liabilities			Total

Balance at January 1, 2017	$	-		$	(1,400	)	$	(1,400	)
Issuance		(36,741	)		-			(36,741	)
Cashless exercise of warrants		-			371			371
Change in fair value of derivative liabilities		3,465			830			4,295
Balance at September 30, 2017	$	(33,276	)	$	(199	)	$	(33,475	)

	Convertible Debenture Derivative Liability			Bristol/ Heartland/SOS Warrant Liabilities			Incentive Bonus			Total

Balance at January 1, 2016	$	(6	)	$	(56	)	$	(223	)	$	(285	)
Reversal of accrued bonus		-			-			616			616
Additional liability		-			(164	)		(393	)		(557	)
Converted to equity		43			-			-			43
Change in fair value of derivative liabilities		(37	)		(498	)		-			(535	)
Balance at September 30, 2016	$	-		$	(718	)	$	-		$	(718	)

Assets and liabilities measured at fair value on a nonrecurring basis. Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis, but are subject to fair value adjustments in certain circumstances. These assets and liabilities can include proved and unproved oil and natural gas properties and other long-lived assets that are written down to fair value when they are impaired or held for sale.

The Company did not have any transfers of assets or liabilities between Level 1, Level 2 or Level 3 of the fair value measurement hierarchy during the nine months ended September 30, 2017 and 2016.

NOTE 5 - LONG-TERM DEBTS

	September 30,			December 31,
	2017			2016
	(In thousands)
Term Loans (see table below):
6% Senior Secured Term Loan, due 2019, net of debt issuance costs	$	-		$	29,214
6% Bridge Loan associated with the amended First Lien Term Loan, net of debt issuance costs		15,183			-
8.25% Second Lien Term Loan, net of debt issuance costs and debt discount		49,526			-
6% note payable to SOS Investment, LLC, due 2019		1,000			1,000
Notes payable - other		15			29
Total long-term debts:		65,724			30,243
Less: current portion		(14	)		(17	)
Total long-term debts, net of current portion:	$	65,710		$	30,226

At September 30, 2017 and December 31, 2016, the carrying amounts of the Term Loans were as follows:

	Principal Amount		Paid-in- kind Interest		Unamortized Debt Issuance Costs & Debt Discount			Carrying Amount
September 30, 2017:
Bridge Loan associated with the amended First Lien Term Loan, due September 2019	$	15,000	$	395	$	(212	)	$	15,183
Second Lien Term Loan, due April 2021		80,000		2,863		(33,337	)		49,526
Total:	$	95,000	$	3,258	$	(33,549	)	$	64,709

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 “Existing 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 Existing 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 Existing Term Loan. As a result, for the nine months ended September 30, 2017, the Company fully amortized approximately $1.5 million 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, the Company entered into the first, second, and third 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 “Bridge Loan”). The 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 Existing Term Loan.

On April 26, 2017, in connection with the closing of the Second Lien Credit Agreement, the Company paid off the Existing Term Loan in full including accrued and unpaid interest thereon.

The First Lien Credit Agreement, as amended by the First Lien Amendments, provides that the unpaid principal of the Bridge Loan will bear cash interest at a rate per annum of (i) 6% for the first six months after the execution of the Amendment and (ii) thereafter, so long as any Bridge Loan is outstanding, a rate of 10%. Additionally, the unpaid principal of the Bridge Loan will bear interest at a rate per annum of 6% compounded quarterly in arrears and payable only in-kind. The Bridge Loan matures on October 21, 2018, and may be repaid in whole or part at any time by the Company, subject to payment of certain specified prepayment premiums. The Bridge Loan is 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.

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.

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, 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 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, below, 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 convertible Second Lien Term Loan. The debt discount is amortized over the term of the Second Lien Term Loan using effective interest rate.

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 for the year ended December 31, 2016.

Interest Expense

The components of interest expense are as follows (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016

Interest on term loans	$	229	$	-	$	1,086	$	217
Interest on notes payable		17		91		36		101
Interest on convertible notes and debentures ⁽¹⁾		-		63		-		944
Paid-in-kind interest on term loans		1,917		-		3,258		-
Amortization of debt financing costs on term loans		51		-		1,673		220
Amortization of discount on term loans		1,442		463		5,031		2,738
Total:	$	3,656	$	617	$	11,084	$	4,220

(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.

NOTE 6 - DERIVATIVES

As discussed in Note 5, the Second Lien Term Loan contains conversion features that are exercisable at the option of the Lead Lender or the borrower. 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 three and nine months ended September 30, 2017. The Company recorded a derivative liability associated with the Second Lien Term Loan at fair value of approximately $36.7 million at issuance date on April 26, 2017 and approximately $39.5 million as of June 30, 2017. As of September 30, 2017, the fair value of the derivative liability was approximately $33.3 million. As a result, the Company recognized unrealized gains of approximately $6.4 million and approximately $3.5 million in its consolidated statement of operations for the three and nine months ended September 30, 2017. There were no derivative liabilities associated with convertible debt instruments for the three and nine months ended September 30, 2016. In addition, as of September 30, 2017 and December 31, 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 $0.3 million, respectively.

NOTE 7 - RELATED PARTY TRANSACTIONS

During the nine months ended September 30, 2017 and 2016, the Company was engaged in the following transactions with related parties:

		Nine Months Ended September 30,
Related Party	Transactions	2017		2016
		($ in thousands)
More than 5% Shareholder:
Pierre Caland (Wallington Investment Holdings, Ltd)	Participated in Series B Preferred Stock offering in 2016 and converted into common stock during the nine months ended September 30, 2017.	$	273	$	250
	Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017. These notes were fully converted into common stock upon closing of the Brushy merger on June 23, 2016.		-		300
	Converted the holdings of Debentures entered into on December 29, 2015 into common stock upon the closing of the Brushy merger on June 23, 2016.		-		2,090
	Converted shares of Series A Preferred Stock into common stock upon the closing of the Brushy merger on June 23, 2016.		-		125
	Participated in private placement transaction on February 28, 2017		1,100		-
	Total:	$	1,373	$	2,765

		Nine Months Ended September 30,
Related Party	Transactions	2017		2016

Bryan Ezralow	Participated in Series B Preferred Stock offering in 2016 and converted into common stock during the nine months ended September 30, 2017.	$	628	$	1,300
	Participated in the September 29, 2016 $50 million credit facility		-		1,450
	Converted the holdings of Debentures entered into on December 29, 2015 into common stock through EZ Colony Partners, LLC owned by Bryan Ezralow upon the closing of the Brushy merger on June 23, 2016.		-		1,540
	Warrants exercised at $0.01 per share during the nine months ended September 30, 2017.		21		-
	Participated in private placement transaction on February 28, 2017		1,400		-
	Total:	$	2,049	$	4,290

Mark Ezralow	Participated in Series B Preferred Stock offering in 2016 and converted into common stock during the nine months ended September 30, 2017.	$	574	$	-
	Participated in the September 29, 2016 $50 million credit facility		-		950
	Warrants exercised at $0.01 per share during the nine months ended September 30, 2017.		18		-
	Participated in private placement transaction on February 28, 2017.		1,200		-
	Total:	$	1,792	$	950

J. Steven Emerson	Participated in Series B Preferred Stock offering in 2016 and converted into common stock during the nine months ended September 30, 2017.	$	1,639	$	-
	Warrants exercised at $0.01 per share during the nine months ended September 30, 2017.		31		-
	Participated in private placement transaction on February 28, 2017		2,500		-
	Total:	$	4,170	$	-

Steve B. Dunn and Laura Dunn Revocable Trust dated 10/28/10	Converted the holdings of Debentures entered into on December 29, 2015 into common stock upon the closing of the Brushy merger on June 23, 2016.	$	-	$	1,020
	Total:	$	-	$	1,020

Rosseau Asset Management Ltd	Participated in Series B Preferred Stock offering in 2016 and converted into common stock during the nine months ended September 30, 2017.	$	2,185	$	-
	Warrants exercised at $0.01 per share during the nine months ended September 30, 2017.		2		-
	Total:	$	2,187	$	-

Investor Company	Participated in Series B Preferred Stock offering in 2016 and converted into common stock during the nine months ended September 30, 2017.	$	4,318	$	-
	Participated in the amendment to the Company’s first lien credit facility in April 2017 by reinvesting its principal amount that was paid down in the form of bridge loan including paid and accrued interests		2,105		-
	Warrants exercised at $0.01 per share during the nine months ended September 30, 2017.		23		-
	Total:	$	6,446	$	-

LOGiQ Capital (Front Street)	Participated in Series B Preferred Stock offering in 2016 and converted into common stock during the nine months ended September 30, 2017.	$	3,199	$	-
	Warrants exercised at $0.01 per share during the nine months ended September 30, 2017.		1		-
	Total:	$	3,200	$	-

		Nine Months Ended September 30,
Related Party	Transactions	2017		2016

Directors and Officers:
G. Tyler Runnels, (Director)	Received advisory fee for Series B Preferred Stock offering fees and warrants to purchase up to 452,724 shares of common stock, at an exercise price of $1.30 per share, exercisable on or after September 17, 2016 through T.R. Winston & Company, LLC (“TRW”) ⁽¹⁾.	$	-	$	500
	Reinvested advisory fee for 150 shares of Series B Preferred Stock and 68,182 warrants at exercise price of $2.50 per share through TRW.		-		150
	Converted shares of Series A Preferred Stock into common stock upon the closing of the Brushy merger on June 23, 2016 through TRW and Runnels Family Trust DTD 1-11-2000⁽²⁾.		-		779
	Cash paid for advisory fee on Convertible Notes which was reinvested in 350 shares of Series B Preferred Stock through TRW.		-		350
	Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 through TRW, which were fully converted into common stock upon closing of the Brushy merger on June 23, 2016.		-		400
	Participated in Series B Preferred Stock offering in 2016 through TRW and Runnels Family Trust DTD 1-11-2000 and converted into common stock during the nine months ended September 30, 2017.		520		-
	Participated in private placement transaction on February 28, 2017 through TRW and Runnels Family Trust DTD 1-11-2000.		796		-
	Warrants exercised at $0.10 per share during the nine months ended September 30, 2017 through Runnels Family Trust DTD 1-11-2000 and TRW Capital Growth Fund, LP⁽³⁾.		17		-
	Sublet office space through TRW in New York to the Company for rent of $10,000 per month from January 1, 2017 through October 31, 2017.		90		-
	Total:	$	1,423	$	2,179

Nuno Brandolini (Director)	Participated in Convertible Notes maturing on September 30, 2016 and April 1, 2017. These notes were fully converted into common stock upon closing of the Brushy merger on June 23, 2016.	$	-	$	250
	Converted shares of Series A Preferred Stock into common stock upon the closing of the Brushy merger on June 23, 2016.		-		100
	Warrants exercised at $0.10 per share during the nine months ended September 30, 2017.		4		-
	Total:	$	4	$	350

General Merrill McPeak (Director)	Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017. These notes were fully converted into common stock upon closing of the Brushy merger on June 23, 2016.	$	-	$	250
	Converted shares of Series A Preferred Stock into common stock upon the closing of the Brushy merger on June 23, 2016.		-		250
	Total:	$	-	$	500

R. Glenn Dawson (Director)	Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017. These notes were fully converted into common stock upon closing of the Brushy merger on June 23, 2016.	$	-	$	50
	Participated in Series B Preferred Stock offering in 2016 and converted into common stock during the nine months ended June 30, 2017.		130		125
	Total:	$	130	$	175

		Nine Months Ended September 30,
Related Party	Transactions	2017		2016

Mark Christensen (Director)	Participated in the Company’s upsize of the first lien facility in February 2017 through Trace Capital Inc. (“Trace Capital”) ⁽⁴⁾	$	1,600	$	-
	Participated in private placement transaction on February 28, 2017 through Trace Capital.		1,000		-
	Participated in the amendment to the Company’s first lien credit facility in April 2017 through Trace Capital by reinvesting its principal amount that was paid down in the form of bridge loans plus paid and accrued interest		1,526		-
	Exercise of warrants		1		-
	Received fees through KES 7 Capital Inc. ⁽⁵⁾for acting as an advisor on certain of the Company’s financing transactions.		552		-
	Total:	$	4,679	$	-

Ronald D. Ormand (Executive Chairman)	Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 through the Bruin Trust.⁽⁶⁾These notes were fully converted into common stock upon closing of the Brushy merger on June 23, 2016.	$	-	$	1,150
	Participated in Series B Preferred Stock offering in 2016 and converted into common stock in 2017 through Perugia Investment LP⁽⁷⁾during the nine months ended September 30, 2017.		1,093		1,000
	Exercise of warrants		4		-
	Converted shares of Series A Preferred Stock into common stock through Perugia Investment LP upon the closing of the Brushy merger on June 23, 2016.		-		500
	Accounts receivable due for tax withholding on vested restricted shares. This amount was paid on October 11, 2017.		194		-
	Total:	$	1,291	$	2,650

Abraham Mirman (former Chief Executive Officer and Director)	Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 through The Bralina Group, LLC.⁽⁸⁾These notes were fully converted into common stock upon closing of the Brushy merger on June 23, 2016.	$	-	$	750
	Participated in Series B Preferred Stock offering in 2016 and converted into common stock in 2017 through the Bralina Group, LLC.		1,803		1,650
	Converted shares of Series A Preferred Stock into common stock upon the closing of the Brushy merger on June 23, 2016.		-		250
	Total:	$	1,803	$	2,650

Brennan Short (Chief Operating Officer)	Consulting fees paid to MMZ Consulting, Inc. which is owned by Mr. Short. Mr. Short is the sole member of the corporation.	$	282	$	-
	Golf tournament charges billed by MMZ Consulting, Inc and other personal expenses claimed through expense reports.		3		-
	Total:	$	285	$	-

		Nine Months Ended September 30,
Related Party	Transactions	2017		2016

Kevin Nanke (former Chief Financial Officer)	Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017. These notes were converted into the Company’s common stock upon the closing of the Brushy merger on June 23, 2016.	$	-	$	100
	Participated in Series B Preferred Stock offering in 2016 and converted into common stock in 2017 through KKN Holdings LLC during the nine months ended September 30, 2017.		219		200
	Warrants exercised at $0.01 per share during the nine months ended September 30, 2017.		4		-
	Purchased the DJ Basin properties from the Company through Nanke Energy, LLC on January 31, 2017.		2,000		-
	Total:	$	2,223	$	300

⁽¹⁾	Mr. Runnels has sole voting and dispositive power over all securities held by T.R. Winston & Company, LLC.
⁽²⁾	Mr. Runnels acts as a trustee with Jasmine N. Runnels for the Runnels Family Trust DTD 1-11-2000 and has shared voting and dispositive power.
⁽³⁾	Mr. Runnels has sole voting and dispositive power over all securities held by TRW Capital Growth Fund, LP.
⁽⁴⁾	Trace Capital Inc. is an entity controlled by Mr. Christensen’s wife, who has sole voting and dispositive power over the securities held by Trace Capital Inc.
⁽⁵⁾	Mr. Christensen has sole voting and dispositive power over all securities held by KES 7 Capital Inc.
⁽⁶⁾	An irrevocable trust managed by Jerry Ormand, Mr. Ormand's brother, as trustee and whose beneficiaries are the adult children of Ronald Ormand.
⁽⁷⁾	Mr. Ormand has sole voting and dispositive power over the securities held by Perugia Investment LP.
⁽⁸⁾	Mr. Mirman has shared voting and dispositive power over the securities held by The Bralina Group, LLC with Susan Mirman.

NOTE 8 - SHAREHOLDERS’ EQUITY

Authorized Shares of Common Stock

On May 2, 2017, the Board of Directors authorized the amendment of the Company’s certificate of incorporation to increase the number of authorized shares of common stock by 50 million from the prior level of 100 million. This amendment was also approved by the Company’s shareholders on July 13, 2017. There was no change in the stated par value of the shares as a result of this amendment.

Conditionally Redeemable 6% Preferred Stock

In August 2014, the Company designated 2,000 shares of its authorized preferred stock as Conditionally Redeemable 6% Preferred Stock, or (the “Redeemable Preferred”). All 2,000 shares of Redeemable Preferred were issued in September 2014, pursuant to the Settlement Agreement with Hexagon, LLC (f/k/a Hexagon Investments, LLC) (“Hexagon”). The Redeemable Preferred had a par value and stated value $1,000 per share and were not convertible into common stock or any other securities of the Company. Except as otherwise required by law, holders of the Redeemable Preferred were not entitled to voting rights.

Effective as of April 24, 2017, the Company redeemed, in full, the Company’s Redeemable Preferred. In accordance therewith, the Company and Hexagon, the only holder of the Redeemable Preferred, entered into a Settlement and Release Agreement (the “Settlement Agreement”), which sets forth the terms of the redemption. In addition, the Settlement Agreement resolves certain other issues related to liability reimbursements on certain oil and natural gas properties that had previously been alleged by Hexagon. Accordingly, all prior issues with Hexagon have been resolved and the Redeemable Preferred has been redeemed in full.

Series B 6% Convertible Preferred Stock

On June 15, 2016, the Company entered into a purchase agreement for the private placement of 20,000 shares of its Series B 6% Convertible Preferred Stock (the “Series B Preferred Stock”), along with detachable warrants to purchase up to 9,090,926 shares of common stock, at an exercise price of $2.50 per share, for aggregate gross proceeds of $20 million. The Series B Preferred Stock was converted in full as of June 30, 2017, as described below.

Each share of Series B Preferred Stock was convertible, at the option of the holder, subject to adjustment under certain circumstances into shares of common stock of the Company at a conversion price of $1.10. Except as otherwise required by law, holders of the Series B Preferred Stock were not entitled to voting rights. The Series B Preferred Stock was convertible at any time, subject to certain conditions, at the option of the holders, or at the Company’s discretion when the Company’s common stock traded above $10.00 (subject to any reverse or forward stock splits and the like) for ten consecutive days. In addition, the Company had the right to redeem the shares of Series B Preferred Stock, along with any accrued and unpaid dividends, at any time, subject to certain conditions set forth in the Certificate of Designation. The holders of the Series B Preferred Stock were entitled to receive a dividend payable (subject to certain conditions set forth in the Certificate of Designation), in cash or shares of common stock of the Company, at the election of the Company, at a rate of 6% per annum.

On April 25, 2017, the Company entered into a Series B 6.0% Convertible Preferred Stock Conversion Agreement (the “Conversion Agreement”), with all of the holders of the outstanding Series B Preferred Stock (the “Series B Holders”) to convert any outstanding shares of Series B Preferred Stock including an increase in the stated value of to reflect dividends that would have accrued through December 31, 2017 in the amount of approximately 14.3 million shares of common stock. On the same date, the Series B Holders further agreed to adopt the Amended and Restated Certificate of Designation of Preferences, Rights and Limitations of Series B 6% Convertible Preferred Stock (“A&R COD”) in order to remove certain restrictions contained therein with respect to beneficial ownership limitations, a condition of the Conversion Agreement. The A&R COD became effective on April 26, 2017, resulting in the automatic conversion of all outstanding Series B Preferred Stock. As a result of the automatic conversion, the Company recognized $4.6 million of dividends and deemed dividends on the Series B Preferred Stock during the nine months ended September 30, 2017.

The Conversion Agreement contained customary representations and warranties by the Series B Holders and other agreements and obligations of the parties.

Private Placement

On February 28, 2017, the Company entered into a Securities Subscription Agreement (the “Subscription Agreement”) with certain institutional and accredited investors in connection with a private placement the (“March 2017 Private Placement”) to sell 5.2 million units, consisting of approximately 5.2 million shares of common stock and warrants to purchase approximately an additional 2.6 million shares of common stock. Each unit consists of one share of common stock and a warrant to purchase 0.50 shares of common stock (each, a “Unit”), at a price per unit of $3.85. Each warrant has an exercise price of $4.50 and may be subject to redemption by the Company, upon prior written notice, if the price of the Company’s common stock closes at or above $6.30 for twenty trading days during a consecutive thirty trading day period. As of September 30, 2017, the Company has received aggregate gross proceeds of $20.0 million and issued 5,194,821 shares of common stock and warrants to purchase 2,597,420 shares of common stock.

Warrants

The following table provides a summary of warrant activity for the nine months ended September 30, 2017:

	Warrants			Weighted- Average Exercise Price
Outstanding at January 1, 2017		15,915,511		$	3.34
Warrants issued in connection with private placement		2,597,420		$	4.50
Warrants issued to Heartland		160,714		$	3.50
Exercised		(6,128,100	)		(0.30	)
Forfeited or expired		(22,500	)	$	(25.00	)
Outstanding at September 30, 2017		12,523,045		$	4.59

NOTE 9 - SHARE BASED AND OTHER COMPENSATION

The Company’s stock-based compensation consisted of the following (dollars in thousands):

	Nine Months Ended September 30, 2017						Nine Months Ended September 30, 2016
	Stock Options		Restricted Stock		Total		Stock Options		Restricted Stock		Total
Stock-based compensation expensed	$	6,550	$	7,927	$	14,477	$	2,289	$	1,263	$	3,552
Unrecognized stock-based compensation costs	$	5,217	$	1,133	$	6,350	$	2,720	$	1,400	$	4,120
Weighted average amortization period remaining (in years)		0.75		0.68		-		1.74		1.18		-

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 nine months ended September 30, 2017 is presented below:

	Number of Shares			Weighted Average Grant Date Price
Outstanding at January 1, 2017		1,068,305		$	1.55
Granted		1,488,845		$	4.54
Vested and issued		(1,426,684	)	$	(2.73	)
Forfeited or cancelled		(448,424	)	$	(3.78	)
Outstanding at September 30, 2017		682,042		$	2.86

Restricted Stock Units

A summary of restricted stock unit grant activity pursuant to the 2012 Plan and the 2016 Plan for the nine months ended September 30, 2017 is presented below.

	Number of Shares			Weighted Average Grant Date Price
Outstanding at January 1, 2017		149,584		$	10.56
Vested and issued		(139,585	)	$	(4.77	)
Outstanding at September 30, 2017		9,999		$	6.57

Stock Options

A summary of stock option activity pursuant to the 2012 Plan and the 2016 Plan for the nine months ended September 30, 2017 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, 2017		5,956,833		$	2.04			2,208,757		9.7
Granted		3,240,000		$	4.73
Exercised		(236,896	)	$	(1.34	)
Forfeited or cancelled		(1,590,937	)	$	(3.06	)
Outstanding at September 30, 2017		7,369,000		$	3.74			3,552,944		9.2

During the nine months ended September 30, 2017, options to purchase 3,240,000 shares of the Company’s common stock were granted under the 2016 Plan. The weighted average fair value of these options was $2.62. The fair values were determined using the Black-Scholes-Merton option valuation method assuming no dividends, a risk-free interest rate ranging from 1.21% to 1.45%, a weighted average expected life of 2 years and weighted-average volatility of 100.5%.

The options to purchase 3,240,000 shares of the Company’s common stock include the following:

	(i)	Options granted to employees of the Company to purchase 2,490,000 shares of the Company’s common stock during the nine months ended September 30, 2017; and
	(ii)	On June 16, 2017, the Company cancelled 250,000 of the options granted in June 2016 and all of the 500,000 options granted in December 2016 to an executive due to option grants that were in excess of the 2016 Plan individual limits. Additional options to purchase 750,000 shares of the Company’s common stock, 389,657 restricted shares and cash in an amount of $87,922 were awarded and paid to the executive to replace the cancelled option grants. The Company accounted for the replacement award as a modification of the terms of the cancelled award in accordance with ASC 718-20-35-8 “Cancellation of an award accompanied by the concurrent grant of (or offer to grant) a replacement award or other valuation consideration.” As a result, during the nine months ended September 30, 2017, the Company recorded incremental compensation of approximately $1.6 million which was the excess of the fair value of the vested replacement award over the fair value of the cancelled awards. The incremental fair value of the unvested replacement awards was to be amortized over the remaining vesting period. As a result of the resignation of the executive in August 2017, the remaining unvested replacement awards were fully vested and expensed totaling approximately $3.2 million during the three and nine months ended September 30, 2017.

As of September 30, 2017, total unrecognized compensation costs relating to the outstanding options was approximately $5.2 million, which is expected to be recognized over the remaining weighted average vesting period of approximately 0.75 years.

NOTE 10 - SUPPLEMENTAL NON-CASH TRANSACTIONS

The following table presents the supplemental disclosure of cash flow information for the nine months ended September 30, 2017 and 2016:

	Nine Months Ended September 30,
	2017		2016
	($ 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	$	14,865	$	-
Common stock issued for Brushy’s common stock		-		6,942
Common stock issued for Series A Preferred Stock and accrued dividends		-		8,221
Common stock issued for convertible debentures and accrued interest		-		8,121
Common stock issued for convertible notes and accrued interest		-		11,106
Warrants issued for fees associated with Series B 6% Preferred Stock		-		1,590
Loss on extinguishment of Series A Preferred Stock		-		540
Warrants issued with Series B Preferred Stock issuance and recorded as deemed dividend		-		7,880
Commitment fees offset by issuance of common stock for Private Placement		250		-
Fair value of warrants issued and repriced as debt discount		1,031		1,479
Cashless exercise of warrants		371		-
Issuance of common stock for director fees		-		85
Issuance of common stock for drilling services		97		-
Deemed dividends on Series B 6% Convertible Preferred Stock associated with beneficial conversion features		3,767		-
Change in capital expenditures for drilling costs in accrued liabilities		5,632		-
Asset retirement established on newly drilled wells		8		1,479

NOTE 11 - COMMITMENTS AND CONTINGENCIES

Revenue Contract

On August 10, 2017, the Company entered into a long-term agreement with Lucid Energy Group (“Lucid”) relating to gas gathering, processing and associated services to support the Company’s production operations. Pursuant to the agreement, Lucid will receive, gather and process the Company’s gas production from certain production areas located in Lea County, New Mexico and Loving and Winkler counties, Texas. The agreement secures incremental midstream capacity for the Company in the production areas committed to the new agreement. We currently expect to commence services with Lucid on our New Mexico and Texas properties in November and December 2017, respectively. Prior to the February 1, 2018 termination of our current gathering arrangement, we have negotiated the ability to deliver certain quantities of curtailed gas to Lucid upon connection to the Lucid system.

Departure of Chief Executive Officer and Director

On August 3, 2017, Abraham Mirman notified the Company of his resignation as Chief Executive Officer, and as a member of the Company’s Board of Directors (the “Board”), effective as of August 4, 2017 (the “Separation Date”). Mr. Mirman also resigned from all positions held with the Company’s subsidiaries. Mr. Mirman’s decision to resign was not the result of any disagreement with the Company, the Board, or management, or any matter relating to the Company’s operations, policies or practices. In connection with Mr. Mirman’s resignation, the Company entered into a Separation and Consulting Agreement with Mr. Mirman on August 3, 2017 (the “Mirman Agreement”), setting forth the terms of Mr. Mirman’s separation from the Company and his prospective consulting services.

Pursuant to the terms of the Mirman Agreement, in satisfaction of any and all obligations under his employment agreement, Mr. Mirman received the following severance payments, subject to applicable employer and employee withholding by the Company: (1) accrued benefits (including base salary, vacation pay and reimbursements) that are unpaid as of the Separation Date, (2) a lump-sum cash payment of $1.0 million, (3) premium payments for continuing COBRA coverage for eighteen months or until Mr. Mirman obtains alternative coverage, whichever is earlier, and (4) reimbursement of reasonable attorneys’ fees incurred in connection with his separation. Any unvested shares of restricted stock or unvested stock options which were previously awarded to Mr. Mirman vested on August 12, 2017.

The Mirman Agreement also provides for the engagement of Mr. Mirman as an independent consultant to provide consulting or advisory services as the Company may reasonably request with respect to its business. Mr. Mirman’s consultancy commenced on August 5, 2017 and will terminate on August 5, 2018, unless terminated earlier or extended by mutual agreement in accordance with the terms of the Agreement. In consideration for his consulting services, the Company will pay Mr. Mirman a monthly consulting fee of $41,661.

The Mirman Agreement contains other standard provisions contained in agreements of this nature, including restrictive covenants concerning confidentiality, non-competition, non-solicitation and non-disparagement, and a general release of any and all claims Mr. Mirman may have against the Company, its directors, officers and associated persons.

Environmental and Governmental Regulation

At September 30, 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 September 30, 2017, 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 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.

NOTE 12 - SUBSEQUENT EVENTS

Lease Acquisition Agreement

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 will acquire from KEW undeveloped net acres in Winkler County, Texas for an aggregate purchase price of up to $47.0 million pursuant to the terms set forth in the Acquisition Agreement (collectively, the “Leases”). If KEW acquires additional acreage during the time period between the execution of the Acquisition Agreement until closing that exceeds the $47.0 million aggregate purchase price threshold (calculated on a per-net-acre basis), the Company has the option, but not the obligation, to acquire any additional oil and natural gas leases that are acquired by KEW that meet the specifications set forth in the Acquisition Agreement.

The Acquisition Agreement contains terms and conditions customary to transactions of the type including title due diligence provisions and representations and warranties regarding the Leases, including, but not limited to, those regarding taxes, liens, litigation, preferential rights to purchase and consents.

The Company expects to fund the purchase price for the Leases with borrowings drawn under the Delayed Draw Term Loans pursuant to the Second Lien Credit Agreement and cash on hand, which includes proceeds drawn under the First Lien Credit Agreement as described below.

On November 9, 2017, the Company closed on the initial settlement of approximately 3,200 net acres in Winkler County, Texas for approximately $35.8 million and expects to complete the close of the remaining net acreage in early December 2017.

Amendment No. 1 to the Second Lien Credit Agreement

On October 3, 2017, the Company, the Guarantors, the Agent and the Lenders, including the Lead Lender, 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 $45.0 million Delayed Draw Term Loans under the Second Lien Credit Agreement and to provide for the funding of such Delayed Draw Term Loans upon the signing of the Acquisition Agreement. The Company borrowed the full $45.0 million of the availability under the Delayed Draw Terms Loans on October 4, 2017.

Pursuant to Amendment No. 1 to the Second Lien Credit Agreement, if the Company does not use any portion of the Delayed Draw Term Loans for the acquisitions contemplated by the Acquisition Agreement or such other acquisitions as may be approved by the Lead Lender within a specified time period ending not later than January 10, 2018, the Company will be required to prepay such unused portion of the Delayed Draw Terms Loans, together with accrued and unpaid interest and a prepayment premium equal to a 20% annualized rate on such amount (but without the make-whole amount otherwise payable on repayment of loans under the Second Lien Credit Agreement), within two business days after the end of such specified period. Any portion of the Delayed Draw Term Loans so repaid may be later re-borrowed by the Company, subject to the terms of the Second Lien Credit Agreement.

Amendment No. 4 to the First Lien Credit Agreement

On October 19, 2017, the Company entered into a fourth amendment to the First Lien Credit Agreement (“Amendment No. 4 to the First Lien Credit Agreement”). Pursuant to Amendment No. 4 to the First Lien Credit Agreement, among other things, certain lenders identified therein joined the existing lenders as lenders under the First Lien Credit Agreement, and the lenders made further extensions of credit, in addition to the existing loans under the First Lien Credit Agreement (the “Existing Bridge Loans”), in the form of an additional, incremental bridge loan in an aggregate principal amount of $15.0 million (the “Incremental Bridge Loan”, and together with the Existing Bridge Loans, the “First Lien Loans”). The First Lien Loans, including the Incremental Bridge Loan, were fully drawn as of October 19, 2017.

The First Lien Credit Agreement, as amended by Amendment No 4. to the First Lien Credit Agreement, (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.

Amendment No. 2 to the Second Lien Credit Agreement

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.

Amendment No. 3 to the Second 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. As previously disclosed, in October 2017, the Company borrowed the full $45 million of Delayed Draw Term Loans available under the Second Lien Credit Agreement prior to Amendment No. 3 to the Second Lien Credit Agreement. The additional $25.0 million of delayed draw term loans is undrawn as of November 14, 2017 and will be available for borrowing by the Company in one or more drawings of $5.0 million or more from time to time on or before February 28, 2019, subject to certain conditions. Proceeds of the additional loans may be used to fund oil and gas property acquisitions, subject to certain limitations, or drilling and completions costs or for other general corporate purposes.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December 31, 2016, as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in these forward-looking statements as a result of various factors including those set forth under “Forward-Looking Statements” above and Item 1A (Risk Factors) in our Annual Report on Form 10-K for the year ended December 31, 2016.

Overview

We are an upstream independent oil and natural gas company engaged in the acquisition, development and production of unconventional oil and natural gas properties. Our primary focus is drilling horizontal wells in the Delaware Basin of west Texas, which we believe will provide attractive returns on a majority of our acreage positions. Our goal is to grow our company through generating cash flow from new production of oil, natural gas and NGLs, as well as through de-risking the development profile of our portfolio of properties in order to add overall value. Our drilling program utilizes the development of new horizontal wells across several potentially productive formations in the Delaware Basin, but initially targeting the Wolfcamp formation. We drilled our first horizontal well in late 2016 and completed it in January 2017.

On June 23, 2016, we completed a merger transaction with Brushy Resources, Inc. (“Brushy”). The merger resulted in the acquisition of our properties in the Delaware Basin as well as the majority of our current operating activity. This contiguous acreage position is offset by RSP Permian, Inc., Matador Resources Company, Devon Energy Corporation, Royal Dutch Shell PLC, Anadarko Petroleum Corp., and XTO Energy Inc., among other operators. Since entering the Delaware Basin in June 2016, we have grown our acreage position approximately 340% from approximately 3,500 net acres to approximately 15,400 net acres primarily in our Delaware Basin-Core area.

Our Business

As of November 10, 2017, we have accumulated approximately 15,400 net acres in what we believe to be the core of the Delaware Basin in Reeves, Winkler and Loving Counties, Texas and Lea County, New Mexico. Our leasehold position is largely contiguous, allowing us to maximize development efficiency and manage full cycle finding costs. In addition, approximately 38% of our acreage position is held by production, and we are the named operator on 100% of our producing acreage. These two characteristics give us control over the pace of development and the ability to design a more efficient and profitable drilling program that maximizes recovery of hydrocarbons. We expect that the remainder of our 2017 and our 2018 capital expenditure budget will be focused on the development and expansion of our Delaware Basin acreage and operations. We also plan to continue to selectively and opportunistically pursue strategic acreage acquisitions in the Delaware Basin.

We generate the majority of our revenues from sales of oil, natural gas and natural gas liquids (NGLs). The prices of these products are critical factors to our success and volatility in the prices of oil and natural gas could impact our results of operations. In addition, our business requires substantial capital to acquire properties and develop our non-producing properties. Declines in these prices would reduce our revenues and result in lower cash inflow which would make it more difficult for us to pursue our plans to acquire new properties and develop existing properties. The declines in oil and natural gas prices may also adversely affect our ability to obtain additional funding.

On August 10, 2017, we entered into a long-term agreement with Lucid Energy Group (“Lucid”) relating to gas gathering, processing and associated services to support our production operations. Pursuant to the agreement, Lucid will receive, gather and process our gas production from certain production areas located in Lea County, New Mexico and in Loving and Winkler counties, Texas. The agreement secures incremental midstream capacity for us in the production areas committed to the new agreement. This agreement is expected to tie in our New Mexico production in mid-November 2017 with our Texas production commencing in early December 2017 providing a long-term solution to the curtailment issues which we are currently experiencing with our production.

Liquidity

We have reported a net operating loss during the quarter and year-to-date ended September 30, 2017 and for the past five years. As a result, we funded our operations in 2016 and the merger with Brushy through a combination of debt and equity financing. On September 29, 2016, we entered into a new first lien credit agreement that provided for a three-year, senior, secured term loan with initial aggregate principal commitments of $31 million and a maximum facility size of $50 million (the “First Lien Credit Agreement”). The initial commitment on the term loan was funded with $25 million collected as of September 30, 2016 and an additional $6 million collected as of November 11, 2016. We have funded our operations during the nine months ended September 30, 2017 through cash flows from operations, additional debt and equity financing. On February 7, 2017, we completed the drawdown of an incremental $7.1 million under our first lien credit agreement, and on March 1, 2017, we completed a private placement that raised net proceeds of approximately $18.7 million (the “March 2017 Private Placement”). Net proceeds of $17.9 million were received in March 2017 and $0.6 million were received in May 2017.

As described below, in April 2017, we amended our First Lien Credit Agreement and closed on a new $125 million, four-year convertible, second lien term loan facility earning paid-in-kind interest (the “Second Lien Credit Agreement”). This resulted in approximately $56.6 million of combined net proceeds and our option for a delayed-draw tranche under the Second Lien Credit Agreement with maximum additional capacity of $45 million for certain pre-approved leasing and acquisition activity (the “Delayed Draw Term Loan”). We additionally refinanced $38.1 million in principal under our then existing first lien term loan (the “First Lien Term Loan”), paid accrued and unpaid interest thereon, and redeemed and converted all of our preferred stock. On October 3, 2017 we entered into a lease acquisition agreement to acquire up to $47 million in additional acreage. On October 4, 2017, we amended the Second Lien Term Loan (as defined below) and borrowed the full $45 million available under the Delayed Draw Term Loan, proceeds of which will be used to fund the majority of the purchase price due at closing of the Acquisition Agreement. (See Note 12 – Subsequent Events). As of November 8, 2017, we have approximately $62.0 million of cash on hand. On November 10, 2017, we entered into a third amendment to the Second Lien Credit Agreement to increase the Delayed Draw Term Loan by $25.0 million. The additional $25.0 million delayed draw term loans are undrawn as of November 14, 2017 and will be available for borrowing by the us in one or more drawings of $5.0 million or more from time to time prior to February 28, 2019, subject to certain conditions. Proceeds of these delayed draw term loans will be used to fund oil and gas property acquisitions, subject to certain limitations, or drilling and completions costs or for other general corporate purposes.

As a result of our financing, drilling and completion operations and the other liquidity events outlined herein that occurred subsequent to September 30, 2017, we believe that we will have sufficient capital to operate over the next 12 months. However, it is possible that we could seek to raise additional debt and equity capital depending on the pace of our drilling and leasing activity. If we need to obtain new debt or equity financing in the future, the terms and availability of such financing may be impacted by economic and financial market conditions, as well as our financial condition and results of operations at the time we seek additional financing. There can be no assurance that financing will be available in amounts or on terms acceptable to us, if at all.

Amendments to First Lien Credit Agreement and Second Lien Credit Agreement

On April 24, 2017, and subsequently on April 26, 2017 and July 25, 2017, we entered into three amendments to First Lien Credit Agreement and into the Second Lien Credit Agreement. Under the amendments to our existing credit facility, among other things, we received approximately $14.7 million in net proceeds from a new, $15 million, 18-month, first lien term loan (“Bridge Loan”). On April 26, 2017, we entered into the Second Lien Credit Agreement which was structured as an $80 million, four-year term loan that funded at closing (the “Second Lien Term Loan”), and a $45 million Delayed Draw Term Loan that may be used to fund acreage leasing activity and acquisitions under certain conditions. We received approximately $56.6 million in combined net proceeds from the Bridge Loan and the Second Lien Credit Agreement, following repayment of $38.1 million in principal outstanding under the then existing first lien term loan, which was subsequently terminated, plus accrued interest.

The structure of the Delayed Draw Term Loans, which was drawn in full on October 4, 2017, is otherwise identical to the $80 million Second Lien Term Loan that funded at closing. The conversion price under both the Second Lien Term Loan and the Delayed Draw Term Loan is $5.50, subject to adjustment under a conversion formula and customary anti-dilution provisions. At conversion, 70% of the total conversion amount, including a make whole payment, will convert to equity, and 30% will convert into a three-year term loan bearing cash interest.

The First and Second Lien Credit Agreements contain certain customary representations and warranties and affirmative and negative covenants, including covenants relating to: the 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, as applicable. Each of the First and Second Lien Credit Agreements 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 each of the First and Second Lien Credit Agreements could be accelerated and become due and payable upon an event of default.

Pursuant to the terms of the Second Lien Credit Agreement, Värde Partners, Inc. (the “Lead Lenders”) have the right to appoint up to two members to the Board upon conversion of the Second Lien Term Loan, based on the percentage of outstanding common stock held by the Lead Lenders at the time of conversion. On August 12, 2017, we and the Lead Lenders entered into a letter agreement pursuant to which we granted the Lead Lenders the right to appoint one member to the Board, who shall be reasonably acceptable to us, effective immediately upon execution of the letter agreement. The letter agreement provides that, to the fullest extent permitted by law, until the conversion of the Second Lien Term Loan, we will include in the slate of nominees recommended by the Board at any meeting of stockholders called for the purpose of electing directors the person designated by the Lead Lenders to serve on the Board pursuant to the appointment right set forth in the letter agreement. The letter agreement was entered into in connection with an acknowledgment and consent by the Lenders related to the resignation and replacement of our Chief Executive Officer, among other matters. On September 6, 2017, pursuant to the terms of the letter agreement, Mark Christensen was appointed to our Board of Directors.

Redemption of Conditionally Redeemable 6% Preferred Stock

On April 24, 2017, we redeemed, in full, our 6% Redeemable Preferred Stock for cash consideration of $2.0 million, including accumulated dividends of $0.3 million. In accordance therewith, we and Hexagon, the only holder of the 6% Redeemable Preferred Stock, entered into a Settlement and Release Agreement (the “Settlement Agreement”), which sets forth the terms of the redemption. In addition, the Settlement Agreement resolved certain other issues related to liability reimbursements on certain oil and natural gas properties that had previously been alleged by Hexagon. Accordingly, all prior issues with Hexagon were resolved and the 6% Redeemable Preferred Stock was redeemed in full.

Series B 6% Convertible Preferred Stock Conversion

On April 25, 2017, we entered into a Series B 6.0% Convertible Preferred Stock Conversion Agreement (the “Conversion Agreement”), with all of the holders of the outstanding Series B 6% Convertible Preferred Stock (the “Series B Holders”) to convert any outstanding shares of Series B Preferred Stock including an increase in the stated value of to reflect dividends that would have accrued through December 31, 2017 in the amount of approximately 14.3 million shares of common stock. Approximately 2.3 million shares of common stock were issued to Series B Holders who converted their shares of Series B Preferred Stock prior to April 25, 2017. On the same date, we and the Series B Holders further agreed to adopt the Amended and Restated Certificate of Designation of Preferences, Rights and Limitations of Series B 6% Convertible Preferred Stock (“A&R COD”) in order to remove certain restrictions contained therein with respect to beneficial ownership limitations, a condition of the Conversion Agreement. The A&R COD became effective on April 26, 2017, resulting in the automatic conversion of all outstanding Series B Preferred Stock.

Drilling Program

We have a drilling program of up to 11 gross Delaware Basin wells (9 net) that is contingent upon our access to sufficient capital to fully execute. In the first half of 2017, we completed five wells and one well close to completion. As of September 30, 2017, we had drilled a sixth well, which was waiting on completion, and had begun drilling a seventh well. We expect our 2017 horizontal drilling program will be focused almost exclusively on the Wolfcamp zone of the Delaware Basin, with lateral lengths ranging from approximately 4,000’ laterals to 7,000’ laterals.

Results of Operations

We have executed a new midstream agreement and arranged for optionality with our existing midstream provider in an effort to increase our natural gas production takeaway, resulting in the increased ability to produce and provide capacity for our expanding production base. During the three months ended September 30, 2017, we successfully brought online our fifth Wolfcamp B horizontal well the Wildhog BWX State Com #1H. Located in Lea County New Mexico, the Wildhog BWX State Com #1H is our most geologically eastern well and is the closest well to the Central Basin Platform in our current acreage position. As of September 30, 2017, we have production flowing from our five horizontal wells and 17 legacy vertical wells with an estimated productive capacity of approximately 2,750 net BOE per day, on a combined equivalent oil, NGL and natural gas basis. Our production for the three months ended September 30, 2017 and thereafter, however, has been temporarily impacted by curtailments resulting from operational issues and midstream infrastructure constraints pursuant to our current gathering and processing arrangement. Primarily as a result of this midstream constraint, our productive capacity has been curtailed by approximately 40%. Accordingly, our average realized production for the quarter was approximately 1,675 BOE per day for the three months ended September 30, 2017 as compared to our full wellhead capacity of 2,750 BOE per day. To resolve the curtailment issues, we entered into a long-term gas gathering processing and purchase agreement with Lucid that would secure incremental midstream capacity for us in the production areas. Additionally, on November 10, 2017, we executed a gas gathering and processing agreement with our existing gas gathering provider to extend their services on certain vertical wellbores upon expiration of the original contract on February 1, 2018 to further increase our capacity. Adding the Lucid midstream solution should permanently resolve our midstream constraints, improving our ability to produce to operational capacity. We expect to be connected and selling gas in Southeast New Mexico from both the Wildhog BWX State Com #1H and the Prizehog BWX State Com #1H under the Lucid contract in November. The Lucid system should be operational in Texas by December 15, 2017 and we should have maximum production potential on the Lucid system by mid-January 2018. Additionally, upon connection to the Lucid system, we should be able to deliver additional quantities of gas in Texas to Lucid in the event that we continue to experience curtailment issues with our current gas gatherer from December 2017 through February 2018.

The results of operations of Brushy are included with those of Lilis commencing on June 23, 2016. As a result, results of operations for the nine months ended September 30, 2017 are not necessarily comparable to the nine-month period in 2016. Additionally, all discussion related to historical representations of common stock, unless otherwise noted, gives retroactive effect to the reverse split for all periods presented.

The following table compares production volumes and average prices for the three and nine months ended September 30, 2017 and 2016:

	Three Months Ended September 30,
	2017		2016		Variance		%
Product
Oil (Bbls)-net production		97,824		21,892		75,932		347	%
Oil (Bbls)-average realized price	$	44.75	$	40.05	$	4.70		12	%

Natural gas (Mcf)-net production		215,930		99,030		116,900		118	%
Natural gas (MCFE)-average realized price	$	2.74	$	2.35	$	0.39		17	%

Natural gas liquids (Bbls)-net production		20,266		3,381		16,886		499	%
Natural gas liquids (Bbls)-average realized price	$	20.74	$	14.12	$	6.62		47	%

Barrels of oil equivalent (BOE)		154,078		41,778		112,301		269	%
Average daily net production (BOE/day)		1,675		459		1,216		265	%
Average price per BOE	$	34.98	$	27.71	$	7.27		26	%

	Nine Months Ended September 30,
	2017		2016		Variance		%
Product
Oil (Bbls)-net production		243,369		44,711		198,658		444	%
Oil (Bbls)-average realized price	$	45.36	$	37.03	$	8.33		22	%

Natural gas (Mcf)-net production		574,486		183,337		391,148		213	%
Natural gas (MCFE)-average realized price	$	2.84	$	2.37	$	0.47		20	%

Natural gas liquids (Bbls)-net production		54,743		6,259		48,485		775	%
Natural gas liquids (Bbls)-average realized price	$	20.23	$	14.24	$	6.00		42	%

Barrels of oil equivalent (BOE)		393,859		81,525		312,334		383	%
Average daily net production (BOE/day)		1,443		299		1,144		383	%
Average price per BOE	$	34.98	$	26.74	$	8.24		31	%

The following table compares revenues for the three and nine months ended September 30, 2017 and 2016:

	Three Months Ended September 30,
	2017		2016		Variance		%
	(In Thousands)
Revenue:
Oil	$	4,378	$	877	$	3,501		399	%
Natural gas		592		233		359		154	%
Natural gas liquids		420		48		372		775	%
	$	5,390	$	1,158	$	4,232		365	%

Total revenue was approximately $5.4 million for the three months ended September 30, 2017 as compared to approximately $1.2 million for the three months ended September 30, 2016, representing an increase of approximately $4.2 million or 365%. The changes were associated primarily with an increase in production from the Delaware Basin wells. Oil revenues increased 399% due to an increase in volumes of 347% and realized price increases of 12%. Natural gas revenues increased 154% due to an increase in volumes of 118% and realized price increases of 17%. NGL revenues increased 775% due to an increase in volumes of 499%, partially offset by realized price decrease of 47%.

BOE production during the three months ended September 30, 2017 increased by more than 269% as compared to the three months ended September 2016 due to additional wells completed and in production.

	Nine Months Ended September 30,
	2017		2016		Variance		%
	(In Thousands)
Revenue:
Oil	$	11,040	$	1,655	$	9,385		567	%
Natural gas		1,631		436		1,195		274	%
Natural gas liquids		1,108		89		1,019		1,145	%
	$	13,779	$	2,180	$	11,599		532	%

Total revenue was approximately $13.8 million for the nine months ended September 30, 2017 as compared to approximately $2.2 million for the nine months ended September 30, 2016, representing an increase of approximately $11.6 million or 532%. As mentioned above, the increase in revenue is attributed primarily with an increase in production from and an increase in the number of producing Delaware Basin wells. Oil revenues increased 567% due to an increase in volumes of 444% and realized price increases 22%. Natural gas revenues increased 274% due to an increase in volumes of 213% and realized price increases of 20%. NGL revenues increased 1,145% due to an increase in volumes of 775% and realized price increases of 42%.

Production during the nine months ended September 30, 2017 increased by more than 383% as compared to the nine months ended September 2016. During the nine months ended September 30, 2017, we completed five wells that have started production.

Oil and Natural Gas Production Costs, Production Taxes, Depreciation, Depletion and Amortization

The following table shows a comparison of production volumes and average prices:

	Three Months Ended September 30,
	2017		2016		Variance			%
	(In Thousands)
Production costs per BOE	$	11.77	$	14.67	$	(2.90	)		-62	%
Production taxes per BOE		1.88		1.46		0.42			29	%
Depreciation, depletion, and amortization per BOE		9.36		14.37		(5.01	)		-35	%
Total operating costs per BOE	$	23.01	$	30.50	$	(7.49	)		-25	%

	Three Months Ended September 30,
	2017		2016		Variance		%
	(In Thousands)
Costs and expenses:
Production costs	$	1,814	$	613	$	1,201		196	%
Production taxes		290		61		229		375	%
General and administrative		10,943		4,582		6,361		139	%
Depreciation, depletion, amortization and accretion		1,443		601		842		140	%
Total operating expenses	$	14,490	$	5,857	$	8,633		147	%

Production Costs

Production costs were approximately $1.8 million for the three months ended September 30, 2017, compared to approximately $0.6 million for the three months ended September 30, 2016, an increase of approximately $1.2 million, or 196%. The increase in production costs was primarily due to increased production volumes associated with the producing wells in the Delaware basin during the three months ended September 30, 2017. Production costs per BOE decreased to $11.77 for the three months ended September 30, 2017 from $14.67 for the three months ended September 30, 2016, a decrease of $2.90 per BOE, or 20%. The decrease in production costs per BOE was primarily due to increased production volumes associated with the producing wells in the Delaware basin during the three months ended September 30, 2017, as compared to production volumes associated with the Denver-Julesburg basin and legacy wells.

Production Taxes

Production taxes were approximately $0.3 million for the three months ended September 30, 2017, compared to approximately $0.06 million for the three months ended September 30, 2016, an increase of approximately $0.2 million, or 375%. Currently, ad valorem, severance and conservation taxes range from 1% to 13% based on the state and county from which production is derived. The increase in production taxes corresponds to the increase in production revenues during the three months ended September 30, 2016.

General and Administrative Expenses

General and administrative expenses were approximately $10.9 million during the three months ended September 30, 2017, compared to approximately $4.6 million during the three months ended September 30, 2016, an increase of approximately $6.4 million, or 139%. The increase of $6.4 million is primarily attributed to the increase in payroll of approximately $1.8 million due to severance payment made to a former senior executive of approximately $1.1 million, an approximate $2.2 million increase in stock based compensation and an increase of approximately $2.4 million in other general and administrative expenses during the three months ended September 30, 2017. General and administrative expenses for the three months ended September 30, 2017 included stock based compensation expense of $5.1 million as compared to $2.9 million in the comparable period in 2016 and severance payments of $1.1 million which were not incurred in the prior period. For the three months ended September 30, 2017, payroll included approximately $1.4 million of recurring base payroll, and approximately $0.4 million in payroll taxes and other benefits. Excluding severance, stock based compensation and unexpected charges, we expect normal recurring general and administrative expenses to be between $2.5 million and $4.5 million per quarter.

Depreciation, Depletion, and Amortization

Depreciation, depletion, and amortization (“DD&A”) was approximately $1.4 million during the three months ended September 30, 2017, compared to $0.6 million during the three months ended September 30, 2016, an increase of approximately $0.8 million, or 140%. Our DD&A rate decreased to $9.37 per BOE during the three months ended September 30, 2017 from $14.39 per BOE during the three months ended September 30, 2016. Our DD&A expense increased primarily due to an increase in volumes produced by 112,301 BOE or 269% from 41,778 BOE during the three months ended September 30, 2016.

	Nine Months Ended September 30,
	2017		2016		Variance			%
	(In Thousands)
Production costs per BOE	$	10.61	$	12.00	$	(1.39	)		-12	%
Production taxes per BOE		1.80		1.42		0.38			27	%
Depreciation, depletion, and amortization per BOE		10.02		14.26		(4.24	)		-30	%
Total operating costs per BOE	$	22.43	$	27.68	$	(5.25	)		-19	%

	Nine Months Ended September 30,
	2017		2016		Variance		%
	(In Thousands)
Costs and expenses:
Production costs	$	4,178	$	978	$	3,200		327	%
Production taxes		710		115		595		517	%
General and administrative		36,273		9,741		26,532		272	%
Depreciation, depletion, amortization and accretion		3,946		1,162		2,784		240	%
Total operating expenses	$	45,107	$	11,996	$	33,111		276	%

Production Costs

Production costs were approximately $4.2 million for the nine months ended September 30, 2017, compared to approximately $1.0 million for the nine months ended September 30, 2016, an increase of approximately $3.2 million, or 327%. The increase in production costs was primarily due to increased production volumes associated with the producing wells in the Delaware basin during the nine months ended September 30, 2017. Production costs per BOE decreased to $10.61 for the nine months ended September 30, 2017 from $12.00 for the nine months ended September 30, 2016, a decrease of approximately $1.39 per BOE, or 12%. The decrease in production costs per BOE was primarily due to increased reserves during the nine months ended September 30, 2017. The decrease in production costs per BOE was primarily due to increased production volumes associated with the producing wells in the Delaware basin during the nine months ended September 30, 2017, as compared to production volumes associated with the Denver-Julesburg basin and legacy wells.

Production Taxes

Production taxes were approximately $0.7 million for the nine months ended September 30, 2017, compared to approximately $0.1 million for the nine months ended September 30, 2016, an increase of approximately $0.6 million, or 517%. Currently, ad valorem, severance and conservation taxes range from 1% to 13% based on the state and county from which production is derived. Production taxes per BOE increased to $1.80 per BOE during the nine months ended September 30, 2017 from $1.42 during the nine months ended September 30, 2016. As discussed above, the increase in production taxes corresponds to the increase in production revenues during the nine months ended September 30, 2017.

General and Administrative Expenses

General and administrative expenses were approximately $36.3 million during the nine months ended September 30, 2017, compared to approximately $9.7 million during the nine months ended September 30, 2016, an increase of approximately $26.5 million, or 272%. The $26.5 million increase was primarily due to an increase in payroll of approximately $11.5 million, an approximate $10.9 million increase in stock based compensation and an approximate $4.1 million increase in other general and administrative expenses during the nine months ended September 30, 2017. For the nine months ended September 30, 2017, payroll included approximately $4.2 million of recurring base payroll, approximately $7.8 million in bonus payments, approximately $1.1 million in severance pay and approximately $3.2 million in stock based compensation to former executives and approximately $0.9 million in payroll taxes and other benefits.

Depreciation, Depletion, and Amortization

DD&A was approximately $3.9 million during the nine months ended September 30, 2017, compared to approximately $1.2 million during the nine months ended September 30, 2016, an increase of $2.8 million, or 240%. Our DD&A rate decreased to $10.02 per BOE during the nine months ended September 30, 2017 from $14.26 per BOE during the nine months ended September 30, 2016. The DD&A expense increased primarily due to an increase in volumes produced by 312,334 BOE or 383% from 81,525 BOE during the nine months ended September 30, 2016.

	Three Months Ended September 30,
	2017			2016			Variance			%
	(In Thousands)
Other income (expense):
Other income (expense)	$	151		$	51		$	100			196	%
Inducement expense		-			(3,180	)		3,180			100	%
Gain on modification of convertible debentures		-			602			(602	)		-100	%
Change in fair value of derivative instruments		6,368			(438	)		6,806			-1554	%
Change in fair value of conditionally redeemable 6% preferred stock		-			134			(134	)		-100	%
Interest expense		(3,656	)		(617	)		(3,039	)		-493	%
Total other income (expense)	$	2,863		$	(3,448	)	$	6,311			183	%

Interest Expense

Interest expense for the three months ended September 30, 2017 was approximately $3.7 million compared to $0.6 million, for the three months ended September 30, 2016. For the three months ended September 30, 2017, we incurred interest expense of approximately $0.3 million for quarterly interest payments on notes payable and term loans, approximately $1.9 million of paid-in-kind interest and approximately $1.4 million of amortized debt issuance costs associated with the $15 million drawn under the Bridge Loan and debt discount associated with the $80 million drawn under the Second Lien Term Loan. During the three months ended September 30, 2016, we incurred approximately $0.1 million of interest expense and approximately $0.5 million of non-cash interest relating to amortized debt issuance costs on debentures and convertible notes.

Change in Fair Value of Derivative Instruments

The change in fair values of derivative instruments comprised a gain of approximately $6.4 million during the three months ended September 30, 2017, as compared to a loss of approximately $0.4 million during the three months ended September 30, 2016, and is as follows:

Second Lien Term Loan Derivative Liability. On April 26, 2017, we entered into the Second Lien Term Loan, which included a make-whole premium and a conversion feature, which is required to be recorded as an embedded derivative and bifurcated from its host contract. These features are therefore recorded as a derivative liability at fair value each reporting period based upon values determined through the use of the discounted lattice model. On April 26, 2017, the embedded derivatives were recorded as a derivative liability at a fair value of approximately $36.7 million and approximately $39.6 million as of June 30, 2017. As of September 30, 2017, the fair value of the embedded derivatives was $33.3 million. As a result, the Company recorded an unrealized gain of $6.3 million recorded for the three months ended September 30, 2017.

SOSV Investments LLC Warrant Liability. On June 23, 2016, in conjunction with the merger with Brushy in June 2016, we issued to SOSV Investments LLC (“SOS”) a warrant to purchase up to 200,000 shares of our common stock at an exercise price of $25.00. The warrant contains a price protection feature that will automatically reduce the exercise price if we enter into another agreement pursuant to which warrants are issued with a lower exercise price. For the three months ended September 30, 2017 and 2016, we recorded an unrealized gain in the fair value of the derivative liability related to the warrant of approximately $0.1 million and an unrealized loss of $0.3 million, respectively.

Inducement Expense

During the three months ended September 30, 2016, inducement expense of approximately $3.2 million was incurred as a result of debt and equity restructuring in connection with the Brushy merger. There was no inducement expense incurred during the three months ended September 30, 2017.

	Nine Months Ended September 30,
	2017			2016			Variance			%
	(In Thousands)
Other income (expense):
Other income	$	19		$	297		$	(278	)		-94	%
Gain on modification of convertible debentures		-			602			(602	)		-100	%
Inducement expense		-			(8,307	)		8,307			-100	%
Change in fair value of derivative instruments		4,295			(535	)		4,830			-903	%
Change in fair value of conditionally redeemable 6% preferred stock		(41	)		(644	)		603			-94	%
Interest expense		(11,084	)		(4,220	)		(6,864	)		163	%
Total other income (expense)	$	(6,811	)	$	(12,807	)	$	5,996			47	%

Interest Expense

Interest expense for the nine months ended September 30, 2017 was approximately $11.1 million compared to approximately $4.2 million, for the nine months ended September 30, 2016. For the nine months ended September 30, 2017, we incurred interest expense of approximately $1.1 million for quarterly interest payments on notes payable and term loans, approximately $3.3 million of paid-in-kind interest and approximately $6.7 million of amortized debt issuance costs for the First Lien Term Loan, Bridge Loan and the Second Lien Term Loan as compared to the nine months ended September 30, 2016, when we incurred approximately $1.2 million of interest expense and approximately $3.9 million of non-cash interest relating to amortized debt issuance costs on debentures, convertible notes and non-convertible notes.

Change in Fair Value of Derivative Instruments

The change in fair values of derivative instruments comprised a gain of approximately $4.3 million during the nine months ended September 30, 2017, as compared to a loss of approximately $0.5 million during the nine months ended September 30, 2016, and is as follows:

Second Lien Term Loan Derivative Liability. On April 26, 2017, we entered into the Second Lien Term Loan, which included a make-whole premium and a conversion feature, which is required to be recorded as an embedded derivative and bifurcated from its host contract. These features are therefore recorded as a derivative liability at fair value each reporting period based upon values determined through the use of the discounted lattice model. On April 26, 2017, the embedded derivatives were recorded as a derivative liability at a fair value of approximately $36.7 million and approximately $39.6 million as of June 30, 2017. As of September 30, 2017, the fair value of the embedded derivatives was $33.3 million. As a result, we recorded an unrealized gain of $3.5 million recorded for the nine months ended September 30, 2017.

Heartland Warrant Liability. On January 8, 2015, we entered into the Heartland Credit Agreement. In connection with the Heartland Credit Agreement, we issued a warrant to purchase up to 22,500 shares of our 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 we 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, we and Heartland executed an amended and restated warrant agreement whereby we issued a warrant to purchase 160,714 of common stock at an exercise price of $3.50 to replace the original warrant to purchase 22,500 shares of common stock previously issued on January 8, 2015 to settle a disagreement regarding the fair value change pursuant to the anti-dilution provisions in the original warrant. The amended and restated warrant agreement no longer contains the same anti-dilution provisions. As a result of the reissuance of the warrants, we recorded approximately $0.04 million realized gain and approximately $0.04 million unrealized loss on the Heartland warrant liability during the nine months ended September 30, 2017 and 2016, respectively.

	·	SOS Warrant Liability. On June 23, 2016, in conjunction with the merger with Brushy in June 2016, we issued to SOS a warrant to purchase up to 200,000 shares of our common stock at an exercise price of $25.00. The warrant contains a price protection feature that will automatically reduce the exercise price if we enter into another agreement pursuant to which warrants are issued with a lower exercise price. For the nine months ended September 30, 2017 and 2016, we incurred an unrealized gain in fair value of the derivative liability related to the warrant of approximately $0.05 million and approximately $0.3 million, respectively.

	·	Bristol Warrant Liability. On September 2, 2014, we entered into a consulting agreement with Bristol Capital, LLC (“Bristol”), pursuant to which we issued Bristol a warrant to purchase up to 100,000 shares of our 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 of the warrant if we 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, we 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 nine months ended September 30, 2017 and decreasing the Bristol derivative liability to $0.4 million. As a result of the cashless exercise, we reclassified the $0.4 million of Bristol derivative liability to additional paid-in capital as of March 31, 2017. For the nine months ended September 30, 2016, we recorded approximately $0.2 million of unrealized loss on the Bristol warrant.

Inducement Expense

During the nine months ended September 30, 2016, inducement expense of approximately $8.3 million was incurred as a result of debt and equity restructuring in connection with the Brushy merger. There was no inducement expense incurred during the nine months ended September 30, 2017.

Liquidity and Capital Resources

Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions and investors, the sale of equity and equity derivative securities and asset dispositions. Our primary uses of capital have been for the acquisition, development, exploration and exploitation of oil and natural gas properties, in addition to refinancing of debt instruments.

Based upon current commodity price expectations for 2017 and 2018, we believe that our cash flow from operations, in addition to financing activity that occurred subsequent to September 30, 2017 (see Note 12 – Subsequent Events), will be sufficient to fund our drilling and completion operations over the next 12 months, including working capital requirements. However, our Board has not approved an operational capital expenditure program for the year ending December 31, 2018. In addition, future cash flows are subject to a number of variables, including uncertainty in forecasted production volumes and commodity prices. We are the operator for 100% of our 2017 operational capital program and, as a result, the amount and timing of a substantial portion of our capital expenditures is discretionary. We expect that our 2018 capital program will also provide us with discretion in the pace and scale of spending. Accordingly, we may determine it prudent to curtail drilling and completion operations due to capital constraints or reduced returns on investment as a result of commodity price weakness.

Information about our cash flows for the nine months ended September 30, 2017 and 2016 are presented in the following table ($ in thousands):

	Nine Months Ended September 30,
	2017			2016
Cash provided by (used in):
Operating activities	$	(7,610	)	$	(6,517	)
Investing activities		(63,689	)		(3,970	)
Financing activities		77,381			31,366
Net change in cash	$	6,082		$	20,879

Operating activities. For the nine months ended September 30, 2017, net cash used in operating activities was $7.6 million, compared to $6.5 million for the same period in 2016. The increase of $1.1 million in cash used in operating activities was primarily attributable to the increase in operating costs, which corresponds with higher producing activities and supporting general and administrative costs.

Investing activities. For the nine months ended September 30, 2017, net cash used in investing activities was $63.7 million compared to $4.0 million for the same period in 2016. The $62.4 million in cash used in investing activities was primarily attributable to the following:

A $39.7 million increase in drilling and completion costs on the six wells of which five were completed in the Delaware Basin during the nine months ended September 30, 2017. There were minimal drilling activities in the DJ Basin during the nine months ended September 30, 2016;

	·	A $2.2 million increase in workover costs associated with producing wells;

	·	A $23.1 million increase in acquisition of additional working interests on leases of which $15.5 million related to leases in Winkler and Lea Counties, Texas and $7.6 million related to leases in Reeves County, Texas; and

Offset by net proceeds of $1.3 million received from the divestiture of the DJ Basin properties and non-operated properties.

Financing activities. For the nine months ended September 30, 2017, net cash provided by financing activities was $77.4 million compared to cash provided by financing activities of $31.4 million during the same period in 2016. The $77.4 million in net cash provided by financing activities included the following:

$14.7 million increase in net proceeds from the Bridge Loan under the amended First Lien Term Loan financing transactions;

$80.0 million increase in net proceeds from the Second Lien Term Loan financing transactions;

$0.4 million of proceeds from the exercise of warrants and stock options;

$18.4 million of proceeds from the March 2017 Private Placement, net of financing costs; and

$6.7 million of proceeds from exercise of accordion features under the First Lien Term Loan, net of financing costs.

Offset by:

$2.3 million repayment of conditionally redeemable 6% preferred stock including dividends;

$38.1 million repayment of the First Lien Term Loan; and

$2.4 million relating to payment of tax withheld on stock based compensation

Off-Balance Sheet Arrangements

We do not have any material off-balance sheet arrangements.

Recently Issued Accounting Pronouncements

For a discussion of recently issued accounting pronouncements see Note 2 – “Summary of Significant Accounting Policies and Estimates” to our condensed consolidated financial statements in Item 1 of this Quarterly Report.

Subsequent Events

Lease Acquisition Agreement

On October 3, 2017, we entered into a lease acquisition agreement (the “Acquisition Agreement”) with KEW Drilling, a Delaware limited partnership (“KEW”), pursuant to which we will acquire from KEW undeveloped net acres in Winkler County, Texas for an aggregate purchase price of up to $47.0 million for additional pursuant to the terms set forth in the Acquisition Agreement (collectively, the “Leases”). If KEW acquires additional acreage during the time period between the execution of the Acquisition Agreement until closing that exceeds the $47.0 million aggregate purchase price threshold (calculated on a per-net-acre basis), we have the option, but not the obligation, to acquire any additional oil and natural gas leases that are acquired by KEW that meet the specifications set forth in the Acquisition Agreement.

We expect to fund the purchase price for the Leases with borrowings under the Delayed Draw Term Loans available pursuant to its Second Lien Credit Agreement and cash on hand, which includes proceeds drawn under the First Lien Credit Agreement as described below.

On November 9, 2017, we closed on the initial settlement of approximately 3,200 net acres in Winkler County, Texas for approximately $35.8 million and expect to complete the close of the remaining net acreage in early December 2017.

Amendment No. 1 to Second Lien Credit Agreement

On October 3, 2017, 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 the Lead Lender, 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 $45.0 million Delayed Draw Term Loans under the Second Lien Credit Agreement and to provide for the funding of such Delayed Draw Term Loans upon the signing of the Acquisition Agreement. We borrowed the full $45.0 million of the availability under the Delayed Draw Terms Loans on October 4, 2017.

Pursuant to Amendment No. 1 to the Second Lien Credit Agreement, if we do not use any portion of the Delayed Draw Term Loans for the acquisitions contemplated by the Acquisition Agreement or such other acquisitions as may be approved by the Lead Lender within a specified time period ending not later than January 10, 2018, we will be required to prepay such unused portion of the Delayed Draw Term Loans, together with accrued and unpaid interest and a prepayment premium equal to a 20% annualized rate on such amount (but without the make-whole amount otherwise payable on repayment of loans under the Second Lien Credit Agreement), within two business days after the end of such specified period. Any portion of the Delayed Draw Term Loans so repaid may be later re-borrowed by the Company, subject to the terms of the Second Lien Credit Agreement. The Delayed Draw Term Loan was drawn in full on October 4, 2017.

Amendment No. 4 to the First Lien Credit Agreement

On October 19, 2017, we entered into a fourth amendment to the First Lien Credit Agreement (“Amendment No. 4 to the First Lien Credit Agreement”). Pursuant to the Amendment No. 4 to the First Lien Credit Agreement, among other things, certain lenders identified therein joined the existing lenders as lenders under the First Lien Credit Agreement, and the lenders made further extensions of credit, in addition to the currently existing loans under the First Lien Credit Agreement (the “Existing 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 Existing Bridge Loans, the “First Lien Loans”). The First Lien Loans, including the Incremental Bridge Loan, were fully drawn as of October 19, 2017.

The First Lien Credit Agreement, as amended by the Amendment No 4. to the First Lien Credit Agreement, (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 $175,000,000. The First Lien Loans mature on October 21, 2018 and may be repaid in whole or part at any time at our option, 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 our right to reinvest the net proceeds of asset sales and casualty events within 180 days.

Amendment No. 2 to the Second Lien Credit Agreement

On October 19, 2017, we 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 us to incur the Incremental Bridge Loan under the First Lien Credit Agreement.

Amendment No. 3 to the Second Lien Credit Agreement

On November 10, 2017, we entered into a third amendment to the Second Lien Credit Agreement (“Amendment No. 3 to the Second Lien Credit Agreement”), by and among us, the Guarantors, the Agent and the Lenders, including the Lead Lender. Amendment No. 3 to the Second Lien Credit Agreement increased by $25 million the amount of delayed draw term loans available for borrowing under the Second Lien Credit Agreement. As previously disclosed, in October 2017, we borrowed the full $45 million of Delayed Draw Term Loans available under the Second Lien Credit Agreement prior to Amendment No. 3 to the Second Lien Credit Agreement. The additional $25.0 million of delayed draw term loans is undrawn as of November 14, 2017 and will be available for borrowing by us in one or more drawings of $5.0 million or more from time to time on or before February 28, 2019, subject to certain conditions. Proceeds of the additional loans may be used to fund oil and gas property acquisitions, subject to certain limitations, or drilling and completions costs or for other general corporate purposes.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Not applicable

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), at the end of the period we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Our CEO and CFO have determined that disclosures controls and procedures were ineffective as of September 30, 2017 as the changes described below are still being evaluated.

Changes in Internal Control over Financial Reporting

The Company made significant changes and improvements in internal control over financial reporting as its remediation plan will address the material weakness disclosed in our previous filing. Specifically, the following measures were implemented to remediate the material weakness related to accounting for complex transactions, namely: use of comprehensive checklists to identify and review complex accounting issues, additional guidance obtained from an expert accounting technical consultant with respect to the appropriate application of GAAP on non-routine and complex transactions. Management believes these changes should be sufficient to remediate the material weakness previously identified. However, management is continuing to validate the operating effectiveness of these new controls over an appropriate period of time prior to concluding that the material weakness has been remediated.

There were no other changes in our internal control over financial reporting during our most recent fiscal quarter that materially affected, or were reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

None

ITEM 1A. RISK FACTORS.

We are a smaller reporting company as defined by Rule 12b-2 under the Exchange Act and are not required to provide the information under this item.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

None, except as previously disclosed in our Current Reports on Form 8-K.

ITEM 4. MINE SAFETY DISCLOSURES

ITEM 5. OTHER INFORMATION

ITEM 6. EXHIBITS.

Exhibit Number		Exhibit Description
2.1*		Lease Acquisition Agreement, dated October 3, 2017 by and among the Company and KEW Drilling.
3.1		Amended and Restated Articles of Incorporation of Recovery Energy, Inc., dated as of October 10, 2011 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on October 20, 2011).
3.2		Certificate of Amendment to the Amended and Restated Articles of Incorporation of Recovery Energy, Inc., dated as of November 18, 2013 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on November 19, 2013).
3.3		Certificate of Amendment to the Company’s Articles of Incorporation (incorporated herein by reference to Annex A of the Company’s Definitive Proxy Statement on Schedule 14A, filed on June 19, 2017)
3.4		Certificate of Designation of Preferences, Rights, and Limitations of Series A 8% Convertible Preferred Stock, dated as of May 30, 2014 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 4, 2014).
3.5		Amendment to Certificate of Designation of Preferences, Rights, and Limitations of Series A 8% Convertible Preferred Stock, dated as of June 12, 2014 (incorporated herein by reference to Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, filed on June 17, 2014).
3.6		Certificate of Designation of Preferences, Rights and Limitations of 6% Redeemable Preferred Stock, dated as of August 29, 2014 (incorporated herein by reference to Exhibit 3.3 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2014, filed on November 26, 2014).
3.7		Certificate of Designation of Preferences, Rights and Limitations of Series B 6% Convertible Preferred Stock, dated as of June 15, 2016 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 16, 2016).
3.8		Certificate of Change of Lilis Energy, Inc., dated as of June 21, 2016 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 28, 2016).
3.9		Amended and Restated Certificate of Designations of Preferences, Rights and Limitations of Series B 6% Convertible Preferred Stock, dated April 25, 2017 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on April 27, 2017).
3.10		Amended and Restated Bylaws (incorporated herein by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed on June 18, 2010).
10.1		Third Amendment to Credit and Guarantee Agreement, dated July 25, 2017 by and among the Company, Brushy Resources, Inc., ImPetro Operating, LLC, ImPetro Resources, LLC, Lilis Operating Company, LLC, the Lenders party thereto and Deans Knight Capital Management Ltd., as collateral agent (incorporated herein by reference to Exhibit 10.3 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2017 filed on August 14, 2017).
10.2		Second Amendment to the Company’s 2016 Omnibus Incentive Plan, dated July 13, 2017 (incorporated herein by reference to Annex A of the Company’s Definitive Proxy Statement on Schedule 14A, filed on June 19, 2017).
10.3†		Separation and Consulting Agreement, dated August 3, 2017, by and between Lilis Energy, Inc. and Abraham Mirman (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on August 4, 2017)
10.4†		First Amendment of Executive Employment Agreement, dated August 4, 2017, by and between Lilis Energy, Inc. and Jim Linville (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on August 4, 2017)
10.5*		Gas Gathering, Processing and Purchase Agreement, dated August 10, 2017 by and among the Company and Lucid Energy Delaware. Specific items in this exhibit have been redacted, as marked by two asterisks (**), because confidential treatment for those items has been requested. The redacted material has been separately filed with the SEC.
10.6		Letter Agreement dated August 12, 2017 between the Company and Värde Partners, Inc. (incorporated herein by reference to Exhibit 10.14 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2017 filed on August 14, 2017)
10.7		Amendment No. 1 to Second Lien Credit Agreement, dated October 3, 2017 by and among Lilis Energy, Inc., the Guarantors party thereto, the Lenders party thereto and Wilmington Trust, National Association, as administrative agent (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 3, 2017).
10.8		Amendment No. 4 and Joinder to Credit and Guarantee Agreement, dated October 19, 2017 by and among the Company, the Guarantors party thereto, the Lenders party thereto and Deans Knight Capital Management Ltd., as collateral agent (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 24, 2017).
10.9		Amendment No. 2 to Second Lien Credit Agreement, dated October 19, 2017 by and among Lilis Energy, Inc., the Guarantors party thereto, the Lenders party thereto and Wilmington Trust, National Association, as administrative agent (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on October 24, 2017).
10.10		Amendment No. 3 to Second Lien Credit Agreement, dated November 10, 2017 by and among Lilis Energy, Inc., the Guarantors party thereto, the Lenders party thereto and Wilmington Trust, National Association, as administrative agent (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on November 14, 2017).

Exhibit Number		Exhibit Description
31.1*		Certification of the Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).
31.2*		Certification of the Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act.
32.1*		Certification of the Chief Executive Officer pursuant to Rule 13a-14(b)/15d-14(b) of the Exchange Act, and 18 U.S.C. Section 1350.
32.2*		Certification of the Chief Financial Officer pursuant to Rule 13a-14(b)/15d-14(b) of the Exchange Act, and 18 U.S.C. Section 1350.
101.INS*		XBRL Instance Document
101.SCH*		XBRL Taxonomy Schema
101.CAL*		XBRL Taxonomy Calculation Linkbase
101.DEF*		XBRL Taxonomy Definition Linkbase
101.LAB*		XBRL Taxonomy Label Linkbase
101.PRE*		XBRL Taxonomy Presentation Linkbase

*	Filed herewith
†	Indicates management contract or compensatory plan.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized

LILIS ENERGY, INC.

Signature		Title	Date

By:	/s/ James (Jim) L. Linville	Chief Executive Officer	November 14, 2017
	James (Jim) L. Linville	(Principal Executive Officer)

By:	/s/ Joseph C. Daches	Executive Vice President, Chief Financial Officer and Treasurer	November 14, 2017
	Joseph C. Daches	(Principal Financial and Accounting Officer)

EXHIBIT INDEX

Exhibit Number		Exhibit Description
2.1*		Lease Acquisition Agreement, dated October 3, 2017 by and among the Company and KEW Drilling.
3.1		Amended and Restated Articles of Incorporation of Recovery Energy, Inc., dated as of October 10, 2011 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on October 20, 2011).
3.2		Certificate of Amendment to the Amended and Restated Articles of Incorporation of Recovery Energy, Inc., dated as of November 18, 2013 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on November 19, 2013).
3.3		Certificate of Amendment to the Company’s Articles of Incorporation (incorporated herein by reference to Annex A of the Company’s Definitive Proxy Statement on Schedule 14A, filed on June 19, 2017)
3.4		Certificate of Designation of Preferences, Rights, and Limitations of Series A 8% Convertible Preferred Stock, dated as of May 30, 2014 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 4, 2014).
3.5		Amendment to Certificate of Designation of Preferences, Rights, and Limitations of Series A 8% Convertible Preferred Stock, dated as of June 12, 2014 (incorporated herein by reference to Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, filed on June 17, 2014).
3.6		Certificate of Designation of Preferences, Rights and Limitations of 6% Redeemable Preferred Stock, dated as of August 29, 2014 (incorporated herein by reference to Exhibit 3.3 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2014, filed on November 26, 2014).
3.7		Certificate of Designation of Preferences, Rights and Limitations of Series B 6% Convertible Preferred Stock, dated as of June 15, 2016 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 16, 2016).
3.8		Certificate of Change of Lilis Energy, Inc., dated as of June 21, 2016 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 28, 2016).
3.9		Amended and Restated Certificate of Designations of Preferences, Rights and Limitations of Series B 6% Convertible Preferred Stock, dated April 25, 2017 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on April 27, 2017).
3.10		Amended and Restated Bylaws (incorporated herein by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed on June 18, 2010).
10.1		Third Amendment to Credit and Guarantee Agreement, dated July 25, 2017 by and among the Company, Brushy Resources, Inc., ImPetro Operating, LLC, ImPetro Resources, LLC, Lilis Operating Company, LLC, the Lenders party thereto and Deans Knight Capital Management Ltd., as collateral agent (incorporated herein by reference to Exhibit 10.3 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2017 filed on August 14, 2017).
10.2		Second Amendment to the Company’s 2016 Omnibus Incentive Plan, dated July 13, 2017 (incorporated herein by reference to Annex A of the Company’s Definitive Proxy Statement on Schedule 14A, filed on June 19, 2017).
10.3†		Separation and Consulting Agreement, dated August 3, 2017, by and between Lilis Energy, Inc. and Abraham Mirman (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on August 4, 2017)
10.4†		First Amendment of Executive Employment Agreement, dated August 4, 2017, by and between Lilis Energy, Inc. and Jim Linville (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on August 4, 2017)
10.5*		Gas Gathering, Processing and Purchase Agreement, dated August 10, 2017 by and among the Company and Lucid Energy Delaware. Specific items in this exhibit have been redacted, as marked by two asterisks (**), because confidential treatment for those items has been requested. The redacted material has been separately filed with the SEC.
10.6		Letter Agreement dated August 12, 2017 between the Company and Värde Partners, Inc. (incorporated herein by reference to Exhibit 10.14 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2017 filed on August 14, 2017)
10.7		Amendment No. 1 to Second Lien Credit Agreement, dated October 3, 2017 by and among Lilis Energy, Inc., the Guarantors party thereto, the Lenders party thereto and Wilmington Trust, National Association, as administrative agent (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 3, 2017).
10.8		Amendment No. 4 and Joinder to Credit and Guarantee Agreement, dated October 19, 2017 by and among the Company, the Guarantors party thereto, the Lenders party thereto and Deans Knight Capital Management Ltd., as collateral agent (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 24, 2017).
10.9		Amendment No. 2 to Second Lien Credit Agreement, dated October 19, 2017 by and among Lilis Energy, Inc., the Guarantors party thereto, the Lenders party thereto and Wilmington Trust, National Association, as administrative agent (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on October 24, 2017).
10.10		Amendment No. 3 to Second Lien Credit Agreement, dated November 10, 2017 by and among Lilis Energy, Inc., the Guarantors party thereto, the Lenders party thereto and Wilmington Trust, National Association, as administrative agent (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on November 14, 2017).

Exhibit Number		Exhibit Description
31.1*		Certification of the Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).
31.2*		Certification of the Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act.
32.1*		Certification of the Chief Executive Officer pursuant to Rule 13a-14(b)/15d-14(b) of the Exchange Act, and 18 U.S.C. Section 1350.
32.2*		Certification of the Chief Financial Officer pursuant to Rule 13a-14(b)/15d-14(b) of the Exchange Act, and 18 U.S.C. Section 1350.
101.INS*		XBRL Instance Document
101.SCH*		XBRL Taxonomy Schema
101.CAL*		XBRL Taxonomy Calculation Linkbase
101.DEF*		XBRL Taxonomy Definition Linkbase
101.LAB*		XBRL Taxonomy Label Linkbase
101.PRE*		XBRL Taxonomy Presentation Linkbase

*	Filed Herewith
†	Indicates management contract or compensatory plan.

LILIS ENERGY, INC. - FORM 10-Q - November 14, 2017

Attached files

LILIS ENERGY, INC. Reports