Quarterly Report (10-q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q



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

For the quarterly period ended September 30, 2019



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

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.)

201 Main St, Suite 700, Fort Worth, TX 76102

(Address of principal executive offices, including zip code)

(817) 585-9001

(Registrant's telephone number including area code)

Securities registered pursuant to Section 12(b) of the Act



Title of each Class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, $0.0001 par value	LLEX	NYSE American

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 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 ý No ¨

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company, or emerging growth company (as defined in Rule 12b-2 of the Act):



Large accelerated filer	¨	Accelerated filer	ý	Non-accelerated filer	¨
Smaller reporting company	ý	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 ý

As of November 6, 2019, 91,736,516 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, 2019 and December 31, 2018	4
	Unaudited Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2019 and 2018	6
	Unaudited Condensed Consolidated Statements of Changes in Stockholders' Equity (Deficit) for the Three and Nine Months Ended September 30, 2019 and 2018	7
	Unaudited Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2019 and 2018	9
	Notes to the Unaudited Condensed Consolidated Financial Statements	10
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	38
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	51
Item 4.	Controls and Procedures	53

PART II - OTHER INFORMATION

Item 1.	Legal Proceedings	54
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	54
Item 3.	Defaults Upon Senior Securities	55
Item 4.	Mine Safety Disclosures	55
Item 5.	Other information	55
Item 6.	Exhibits	56

SIGNATURES		57

Forward-Looking Statements

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. The statements contained in this report that are not historical facts are forward-looking statements that represent management's beliefs and assumptions based on currently available information. Forward-looking statements include information concerning our possible or assumed future results of operations, business strategies, financing needs, competitive position, and potential growth opportunities. Our forward-looking statements do not consider the effects of future legislation or regulations. Forward-looking statements include all statements that are not historical facts and can be identified by the use of forward-looking terminology such as the words "believes," "intends," "may," "should," "anticipates," "expects," "could," "plans," "estimates," "projects," "targets," or comparable terminology or by discussions of strategy or trends. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we cannot give any assurances that these expectations will prove to be correct. Such statements by their nature involve risks and uncertainties that could significantly affect expected results, and actual future results could differ materially from those described in such forward-looking statements.

Among the factors that could cause actual future results to differ materially are the risks and uncertainties discussed in this Quarterly Report on Form 10-Q and in the other documents we file with the Securities and Exchange Commission, including in our Annual Report on Form 10-K for the year ended December 31, 2018. There may also be other risks and uncertainties that we are unable to predict at this time or that we do not now expect to have a material adverse impact on our business. Should our underlying assumptions prove incorrect or the consequences of the aforementioned risks worsen, actual results could differ materially from those expected. Forward-looking statements speak only as to the date hereof. All such forward-looking statements and any subsequent written or oral forward-looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the statements contained herein or referred to in this section and any other cautionary statements that may accompany such forward-looking statements. Except as otherwise required by applicable law, we disclaim any intention or obligation to update publicly or revise such statements whether as a result of new information, future events or otherwise.

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

Lilis Energy, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(Unaudited)

(In thousands, except share and per share data)



	September 30, 2019		December 31, 2018
ASSETS
Current assets:
Cash and cash equivalents	$	4,339	$	21,137
Accounts receivable, net of allowance of $11 and $25, respectively	23,565		20,546
Derivative instruments	2,388		2,551
Prepaid expenses and other current assets	2,707		1,851
Total current assets	32,999		46,085
Property and equipment:
Oil and natural gas properties, full cost method of accounting, net	426,420		430,379
Other property and equipment, net	443		524
Total property and equipment, net	426,863		430,903
Right-of-use assets	10,635		—
Other assets	4,184		3,785
Total assets	$	474,681	$	480,773
LIABILITIES, MEZZANINE EQUITY AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	10,033	$	47,112
Accrued liabilities and other	28,461		14,794
Revenue payable	8,955		14,546
Derivative instruments	2,855		515
Total current liabilities	50,304		76,967
Asset retirement obligations	2,709		2,433
Long-term debt	105,000		157,804
Long-term derivative instruments and other non-current liabilities	3,293		4,699
Long-term deferred revenue and other long-term liabilities	79,333		52,513
Total liabilities	240,639		294,416
Commitments and Contingencies (Note 20)
Mezzanine equity:
10,000,000 shares of preferred stock authorized
Series C-1 9.75% Participating Preferred Stock, 100,000 shares issued and outstanding with a stated value of $1,175 and $1,093, per share, as of September 30, 2019 and December 31, 2018, respectively	77,582		106,774
Series C-2 9.75% Participating Preferred Stock, 25,000 shares issued and outstanding with a stated value of $1,101 and $1,024, per share, as of September 30, 2019 and December 31, 2018, respectively	18,186		25,522
Series D 8.25% Participating Preferred Stock, 39,254 shares issued and outstanding with a stated value of $1,085 and $1,021, per share, as of September 30, 2019 and December 31, 2018, respectively	28,202		40,729
Series E 8.25% Convertible Participating Preferred Stock, 60,000 shares issued and outstanding with a stated value of $1,048, per share, as of September 30, 2019	64,988		—
Series F 9.00% Participating Preferred Stock, 55,000 shares issued and outstanding with a stated value of $1,052, per share, as of September 30, 2019	49,559		—



Stockholders' equity (deficit):
Common stock, $0.0001 par value per share; 150,000,000 shares authorized 91,796,964 and 71,182,016 issued and outstanding as of September 30, 2019 and December 31, 2018, respectively.	9			7
Additional paid-in capital	349,315			321,753
Treasury stock, 253,598 shares at cost	(997		)	(997		)
Accumulated deficit	(352,802		)	(307,431		)
Total stockholders' equity (deficit)	(4,475		)	13,332
Total liabilities, mezzanine equity and stockholders' equity (deficit)	$	474,681		$	480,773

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

Lilis Energy, Inc. and Subsidiaries

Condensed Consolidated Statements of Operations

(Unaudited)

(In thousands, except share and per share data)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Revenues:
Oil sales	$	10,206		$	15,976		$	44,890		$	42,819
Natural gas sales	694			1,538			2,570			3,572
Natural gas liquid sales	697			1,968			3,408			4,969
Total revenues	11,597			19,482			50,868			51,360
Operating expenses:
Production costs	4,243			3,184			12,866			9,431
Gathering, processing and transportation	942			963			3,355			2,297
Production taxes	543			1,034			2,568			2,705
General and administrative	4,852			6,838			23,913			24,682
Depreciation, depletion, amortization and accretion	5,420			7,172			22,762			17,572
Impairment of oil and gas properties	16,580			—			16,580			—
Total operating expenses	32,580			19,191			82,044			56,687
Operating income (loss)	(20,983		)	291			(31,176		)	(5,327		)
Other income (expense):
Loss on early extinguishment of debt	(1,299		)	—			(1,299		)	—
Gain (loss) from commodity derivatives	3,943			(4,811		)	(3,733		)	(9,383		)
Change in fair value of financial instruments	—			10,612			(335		)	19,499
Interest expense	(2,186		)	(8,949		)	(8,859		)	(26,609		)
Other income	116			1			31			2
Total other income (expense)	574			(3,147		)	(14,195		)	(16,491		)
Net loss before income taxes	(20,409		)	(2,856		)	(45,371		)	(21,818		)
Income tax expense	—			—			—			—
Net loss	(20,409		)	(2,856		)	(45,371		)	(21,818		)
Paid-in-kind dividends on preferred stock	(7,185		)	(2,410		)	(18,385		)	(6,527		)
Net loss attributable to common stockholders	$	(27,594	)	$	(5,266	)	$	(63,756	)	$	(28,345	)

Net loss per common share-basic and diluted: (Note 17)
Basic	$	(0.30	)	$	(0.08	)	$	(0.74	)	$	(0.47	)
Diluted	$	(0.30	)	$	(0.09	)	$	(0.74	)	$	(0.47	)

Weighted average common shares outstanding:
Basic	91,349,994			64,572,104			86,734,449			60,082,902
Diluted	91,349,994			88,710,081			86,734,449			60,082,902

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

Lilis Energy, Inc. and Subsidiaries

Condensed Consolidated Statements of Changes in Stockholders' Equity (Deficit)

(Unaudited)

(In thousands, except share data)

For the Three Months Ended September 30, 2019 and 2018:



	Common Shares				Additional Paid-In Capital			Treasury Shares					Accumulated Deficit			Total
	Shares		Amount		Additional Paid-In Capital			Shares		Amount			Accumulated Deficit			Total
Balance, June 30, 2019	91,451,836		$	9	$	356,210		(253,598	)	$	(997	)	$	(332,393	)	$	22,829
Stock-based compensation	—		—		332			—		—			—			332
Common stock for restricted stock	422,789		—		—			—		—			—			—
Common stock withheld for taxes on stock-based compensation	(77,661	)	—		(42		)	—		—			—			(42		)
Dividends on preferred stock	—		—		(7,185		)	—		—			—			(7,185		)
Net loss	—		—		—			—		—			(20,409		)	(20,409		)
Balance, September 30, 2019	91,796,964		$	9	$	349,315		(253,598	)	$	(997	)	$	(352,802	)	$	(4,475	)



	Common Shares				Additional Paid-In Capital			Treasury Shares					Accumulated Deficit			Total
	Shares		Amount		Additional Paid-In Capital			Shares		Amount			Accumulated Deficit			Total
Balance, June 30, 2018	64,045,923		$	6	$	300,336		(253,598	)	$	(997	)	$	(322,250	)	$	(22,905	)
Stock-based compensation	—		—		2,100			—		—			—			2,100
Common stock for restricted stock	335,000		—		—			—		—			—			—
Common stock withheld for taxes on stock-based compensation	(181,204	)	—		(542		)	—		—			—			(542		)
Exercise of warrants	1,127,517		—		—			—		—			—			—
Exercise of stock options	441,672		—		1,555			—		—			—			1,555
Dividends on Series C convertible preferred stock	—		—		(2,410		)	—		—			—			(2,410		)
Net income	—		—		—			—		—			(2,856		)	(2,856		)
Balance, September 30, 2018	65,768,908		$	6	$	301,039		(253,598	)	$	(997	)	$	(325,106	)	$	(25,058	)

For the Nine Months Ended September 30, 2019 and 2018:



	Common Shares				Additional Paid-In Capital			Treasury Shares					Accumulated Deficit			Total
	Shares		Amount		Additional Paid-In Capital			Shares		Amount			Accumulated Deficit			Total
Balance, December 31, 2018	71,182,016		$	7	$	321,753		(253,598	)	$	(997	)	$	(307,431	)	$	13,332
Stock-based compensation	—		—		6,333			—		—			—			6,333
Common stock for restricted stock	3,260,275		—		—			—		—			—			—
Common stock withheld for taxes on stock-based compensation	(286,965	)	—		(452		)	—		—			—			(452		)
Common stock issued for extinguishment of debt	17,641,638		2		32,988			—		—			—			32,990
Gain on extinguishment of debt	—		—		7,078			—		—			—			7,078
Dividends on preferred stock	—		—		(18,385		)	—		—			—			(18,385		)
Net loss	—		—		—			—		—			(45,371		)	(45,371		)
Balance, September 30, 2019	91,796,964		$	9	$	349,315		(253,598	)	$	(997	)	$	(352,802	)	$	(4,475	)



	Common Shares				Additional Paid-In Capital			Treasury Shares					Accumulated Deficit			Total
	Shares		Amount		Additional Paid-In Capital			Shares		Amount			Accumulated Deficit			Total
Balance, December 31, 2017	53,368,331		$	5	$	272,335		—		$	—		$	(303,288	)	$	(30,948	)
Stock-based compensation	—		—		7,654			—		—			—			7,654
Common stock for restricted stock	802,860		—		—			—		—			—			—
Common stock withheld for taxes on stock-based compensation	(315,439	)	—		(1,051		)	—		—			—			(1,051		)
Common stock for acquisition of oil and gas properties	6,940,722		1		24,777			—		—			—			24,778
Exercise of warrants	3,975,957		—		1,051			—		—			—			1,051
Exercise of stock options	996,477		—		2,577			—		—			—			2,577
Reclassification of warrant derivative liabilities	—		—		223			—		—			—			223
Purchase of treasury stock	—		—		—			(253,598	)	(997		)	—			(997		)
Dividends on Series C convertible preferred stock	—		—		(6,527		)	—		—			—			(6,527		)
Net income	—		—		—			—		—			(21,818		)	(21,818		)
Balance, September 30, 2018	65,768,908		$	6	$	301,039		(253,598	)	$	(997	)	$	(325,106	)	$	(25,058	)

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

Lilis Energy, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(Unaudited)

(In thousands)



	Nine Months Ended September 30,
	2019			2018
Cash flows from operating activities:
Net income (loss)	$	(45,371	)	$	(21,818	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Stock-based compensation	6,333			7,654
Bad debt recovery	(14		)	(14		)
Amortization of debt issuance cost and accretion of debt discount	2,295			13,023
Payable in-kind interest	1,590			9,810
Loss on early extinguishment of debts	1,299			—
Loss from commodity derivatives, net	3,733			7,250
Net settlements received (paid) on commodity derivatives	(2,594		)	2,133
Change in fair value of financial instruments	335			(19,499		)
Impairment of oil and gas properties	16,580			—
Depreciation, depletion, amortization and accretion	22,762			17,572
Operating lease ROU amortization	12			—
Changes in operating assets and liabilities:
Accounts receivable	(3,769		)	(7,818		)
Prepaid expenses and other assets	(670		)	(1,707		)
Accounts payable and accrued liabilities	(47,406		)	27,093
Proceeds from options associated with future midstream services	2,500			50,000
Net cash provided by (used in) operating activities	(42,385		)	83,679
Cash flows from investing activities:
Acquisition of oil and natural gas properties	—			(61,416		)
Proceeds from the sale of assets	16,911			—
Capital expenditures	(55,628		)	(129,490		)
Net cash provided by (used in) investing activities	(38,717		)	(190,906		)
Cash flows from financing activities:
Proceeds from term loans, net of financing costs	—			44,960
Proceeds from revolving credit agreement, net of financing costs	47,126			—
Repayment of term loans and notes payable	—			(31,821		)
Repayment of revolving credit agreement	(18,000		)	—
Proceeds from the issuance of Series C Preferred Stock	—			100,000
Proceeds from the Värde financing arrangement, net of transaction costs	38,230			—
Partial repayment of the Värde financing arrangement	(2,600		)	—
Repurchase of common stock	—			(997		)
Proceeds from exercise of warrants and stock options	—			3,628
Payment for tax withholding on stock-based compensation	(452		)	(1,051		)
Net cash provided by financing activities	64,304			114,719
Net increase (decrease) in cash and cash equivalents	(16,798		)	7,492
Cash and cash equivalents at beginning of period	21,137			17,462
Cash and cash equivalents at end of period	$	4,339		$	24,954
Supplemental disclosure:
Cash paid for interest	$	4,829		$	3,776

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

Lilis Energy, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

NOTE 1 - ORGANIZATION

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

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND ESTIMATES

Principles of Consolidation and Presentation

The accompanying unaudited condensed consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, Brushy Resources, Inc., ImPetro Operating, LLC, ImPetro Resources, LLC, Lilis Operating Company, LLC, and Hurricane Resources LLC. All significant intercompany accounts and transactions have been eliminated in consolidation. The unaudited condensed consolidated financial statements included herein reflect all adjustments (consisting only of normal, recurring adjustments) which are, in our opinion, necessary for a fair presentation of the information as of and for the periods presented. These unaudited condensed consolidated interim financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America ("GAAP") for interim financial information and the instructions to Quarterly Report on Form 10-Q and Article 8 of Regulation S-X. Accordingly, they do not include all disclosures required under GAAP for complete consolidated financial statements.

These unaudited condensed consolidated financial statements should be read in conjunction with our Annual Report on Form 10–K for the year ended December 31, 2018, as filed with the Securities and Exchange Commission (the "SEC") on March 7, 2019 (the "Annual Report").

Use of Estimates

The accompanying condensed consolidated financial statements are prepared in conformity with GAAP which requires the Company to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities; disclosure of contingent assets and liabilities at the date of the financial statements; the reported amounts of revenues and expenses during the reporting period; and the quantities and values of proved oil, natural gas and natural gas liquid ("NGL") reserves used in calculating depletion and assessing impairment of its oil and natural gas properties. The most significant estimates pertain to the evaluation of unproved properties for impairment, proved oil and natural gas reserves and related cash flow estimates used in the depletion and impairment of oil and natural gas properties; the timing and amount of transfers of our unevaluated properties into our amortizable full cost pool; the fair value of embedded derivatives and commodity derivative contracts, accrued oil and natural gas revenues and expenses, valuation of options and warrants, and common stock; and the allocation of general administrative expenses. Actual results could differ significantly from these estimates.

Reclassifications

Certain reclassifications have been made to the prior year comparative financial statements to conform to the 2019 presentation. These reclassifications have no effect on the Company's previously reported results of operations, shareholders' equity or cash flows.

Recently Adopted Accounting Standards

In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update (ASU) No. 2016-02, Leases (Topic 842), a standard on lease accounting requiring a lessee to recognize assets and liabilities on the balance sheet for leases with lease terms greater than 12 months. This standard was effective for annual and interim periods beginning after December 15, 2018. We adopted this standard effective January 1, 2019, utilizing a modified retrospective transition approach. We chose to use the effective date as our date of initial application. Consequently, financial information was not updated and the disclosures required under the new standard were not provided for dates and periods before January 1, 2019.

The standard includes optional transition practical expedients intended to simplify its adoption. We elected to adopt the package of practical expedients, which allowed us to retain the historical lease classification, including treatment for land easements, determined under legacy GAAP as well as a relief from reviewing expired or existing contracts to determine if they contain leases. This standard does not apply to the Company's leases that provide the right to explore for minerals, oil, or natural gas resources.

Upon adoption, we recognized operating lease liabilities totaling approximately $7.5 million, with corresponding right of use assets totaling $7.4 million. The liabilities were calculated as the present value of the remaining minimum rental payments for existing operating leases. This standard did not materially impact our consolidated net earnings and had no impact on our cash flows (see Note 10 - Leases).

Accounting Standards Not Yet Adopted

In June 2016, the FASB issued ASU 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which replaces the currently required incurred loss methodology with an expected loss methodology. This new methodology requires that a financial asset measured at amortized cost be presented at the net amount expected to be collected. The update is intended to provide financial statement users with more useful information about expected credit losses on financial instruments. The amended standard is effective for the Company on January 1, 2023, with early adoption permitted, and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. Historically, the Company's credit losses on oil and natural gas sales receivables and any joint interest receivables have not been significant, and the Company is evaluating the impact the adoption of ASU 2016-13 will have on its consolidated financial statements.

Accrued Liabilities and Other

At September 30, 2019 and December 31, 2018, the Company's accrued liabilities consisted of the following:



	September 30, 2019		December 31, 2018
	(In thousands)
Accrued personnel costs	$	900	$	2,300
Accrued drilling and completion costs	10,720		2,849
Drilling advances	2,311		5,001
Accrued production expenses	3,810		2,926
Other accrued liabilities	2,508		1,718
Short-term operating lease liabilities	8,212		—
	$	28,461	$	14,794

NOTE 3 - LIQUIDITY

As of October 31, 2019, we were fully drawn against the borrowing base under our Revolving Credit Agreement (as defined in Note 11 - Long-Term Debt), with $115 million of indebtedness outstanding under our Revolving Credit Agreement. Our next borrowing base redetermination, scheduled to occur on or about November 1, 2019, is expected to occur in mid-November 2019. If the borrowing base is reduced by the lenders in connection with this redetermination, we will be required to repay borrowings in excess of the borrowing base or eliminate the borrowing base deficiency by pledging additional oil and gas properties to secure our obligations under the Revolving Credit Agreement. Under the Revolving Credit Agreement, we have the option to affect such repayment either in full within 30 days after the redetermination or in monthly installments over a six-month period after the redetermination. We are currently considering alternative secured financing to replace the current revolving credit facility under our Revolving Credit Agreement.

As of September 30, 2019, the Company was in compliance with the Current Ratio covenant (as defined and described in Note 11 - Long-Term Debt) under the Revolving Credit Agreement but was not in compliance with the Leverage Ratio covenant (as defined and described in Note 11 - Long-Term Debt). Pursuant to the Fourth Amendment (as defined in Note 11 - Long-Term Debt), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio covenant as of September 30, 2019. The Fourth Amendment also amended the Leverage Ratio with respect to certain future periods, as described in Note 11 - Long-Term Debt. The Company was not in compliance with the Leverage Ratio covenant as of September 30, 2019 due to the Company voluntarily shutting-in wells across our properties to begin testing and implementing certain natural gas and crude oil treating systems, in addition to shutting-in certain wells during the third quarter while flare permits were being extended.

and gas to sales compared to previous periods. We expect, with those measures providing a more consistent flow of oil and gas to sales, the continuing ability to execute cost reduction measures, the ability to sell non-core assets and the ability to access other sources of capital, will allow us to meet our financial covenants and maintain sufficient liquidity in future periods. However, our future cash flows, and consequently our EBITDAX, are subject to a number of variables, including uncertainty in forecasted production volumes and commodity prices, and we may not be able to complete sales of non-core assets or access other sources of capital on acceptable terms or at all.

Our ability to fund our future operations, including drilling and completion capital expenditures, over the next year and one day, post issuance of these consolidated financial statements, will largely be dependent upon our active management of our drilling and completion budget, and, if necessary, the reduction or continued suspension of our drilling plans until we are able to identify and access further sources of liquidity. We are currently considering alternative secured financing to replace the current revolving credit facility under our Revolving Credit Agreement. We are the operator of 100% of our 2019 operational capital program and we expect to operate a substantial majority of wells we may drill in the near future, and, as a result, we have had, and expect to continue to have, the discretion to control the amount and timing of a substantial portion of our capital expenditures. The Company has recently elected to temporarily suspend current drilling operations to focus on production and facilities optimization while the results and performance of the new wells are evaluated. The Company expects to begin drilling operations again in the first quarter of 2020. We may in the future, however, determine it prudent to extend the current suspension or temporarily suspend further drilling and completion operations due to capital constraints, shortage of liquidity, or reduced returns on investment as a result of commodity price weakness. The Company believes it is probable the above plans will be implemented and will provide the funds necessary to meet our obligations over the next year and one day, post issuance of these consolidated financial statements.

NOTE 4 - REVENUE

Revenue is recognized when control passes to the purchaser, which generally occurs when production is transferred to the purchaser. The Company measures revenue as the amount of consideration it expects to receive in exchange for the commodities transferred. All of the Company's revenues from contracts with customers represent products transferred at a point in time as control is transferred to the customer.

The Company records revenue based on consideration specified in its contracts with its customers. The amounts collected on behalf of third parties are recorded in revenue payable. The Company recognizes revenue in the amount that reflects the consideration it expects to receive in exchange for transferring control of those goods to the customer. The contract consideration in the Company's variable price contracts is typically allocated to specific performance obligations in the contract according to the price stated in the contract. Payment is generally received one or two months after the sale has occurred.

Crude Oil Revenues

Crude oil from our operated properties is produced and stored in field tanks. The Company recognizes crude oil revenue when control passes to the purchaser. Effective January 1, 2019 through February 28, 2019, the Company's crude oil was sold under a single short-term contract. The purchaser's commitment included all quantities of crude oil from the leases that were covered by the contract, with no quantity-based restrictions or variable terms. Pricing was based on posted indexes for crude oil of similar quality, less a negotiable fees deduction of $5.15 per barrel.

Effective March 1, 2019, the Company's crude oil is sold under a single long-term contract with a term that extends to at least December 31, 2024. The purchaser's commitment has a quantity-based limit set forth in the contract, measured in barrels per day, with the minimum quantity commitment increasing at periodic intervals over the life of the contract to coincide with the Company's expected growth in production. During the three month period ended September 30, 2019, the Company did not meet its required minimum quantity commitment under the contract due to a temporary production outage. The purchaser declined to enforce any make whole provisions and production has been restored. (See Note 12 - Long-Term Deferred Revenue Liabilities and Other Long-Term Liabilities and Note 20 - Commitments and Contingencies)

Pursuant to the long-term contract, pricing is based on posted indexes for crude oil of similar quality, with a differential based on pipeline delivery to Houston, as opposed to the previous contract differential based on truck delivery to Midland-Cushing, along with a differential basis reduction of $9.25 per barrel that is effective from March 1, 2019 through June 30, 2019, which decreases to $6.50 per barrel for the period of July 1, 2019 through June 30, 2020, and then to $4.95 per barrel for the period from July 1, 2020 through December 31, 2024. The posted index prices and differentials change monthly based on the average of daily index price points for each sales month. The purchaser's affiliate shipper also charges a tariff fee of $0.75 as a deduction from the received price (see Note 12 - Long-Term Deferred Revenue Liabilities and Other Long-Term Liabilities).

Natural Gas and NGL Revenues

Natural gas from our properties is produced and transported via pipelines to gas processing facilities. NGLs are extracted from the natural gas at the processing facilities and processed natural gas and NGLs are marketed and sold separately on the Company's behalf after processing. All of our operated natural gas production is sold under one of two natural gas contracts, both of which are long-term in nature; however, one of these natural gas contracts includes 30-day cancellation provisions, and the Company therefore classifies such contract as short-term. The processor's commitment to sell on the Company's behalf includes all quantities of natural gas and NGLs produced from specific wellbores or dedicated acreage as defined in the contract, with no quantity-based restrictions or variable terms. Pricing under the gas contracts is generally market-based pricing less adjustments for transportation and processing fees. A portion of natural gas delivered to the processing plants is used as fuel at the processing plant without reimbursement. The Company recognizes revenue for natural gas and NGLs when control passes at the tailgate of the processing plant.

Gathering, Processing and Transportation

Natural gas must be transported to a gas processing plant facility for treatment and to extract NGLs, then the final residue gas and liquid products are marketed for sale to end users at the tailgate of the plant. As a result of these activities, the Company incurs costs that are contractually passed to it from the gatherer per customary industry practice. Such costs include fees for gathering the gas and moving it from wellhead to plant inlet, plant electricity usage, inlet compression, carbon dioxide and hydrogen sulfide treatments, processing tax, fuel usage, and marketing at the tailgate. Gathering, processing and transportation costs are presented as operating expenses in the condensed consolidated statement of operations.

Imbalances

Natural gas imbalances occur when the Company sells more or less than its entitled ownership percentage of total natural gas production. Any amount received in excess of its share is treated as a liability. If the Company receives less than its entitled share, the under production is recorded as a receivable. The Company did not have any significant natural gas imbalance positions as of September 30, 2019 and December 31, 2018.

The following table disaggregates the Company's revenue by contract type (in thousands) for the three and nine months ended September 30, 2019:



Three Months Ended September 30, 2019	Short-term contracts		Long-term contracts		Total
Crude oil	$	—	$	10,206	$	10,206
Natural gas	18		676		694
NGLs	6		691		697



Nine Months Ended September 30, 2019	Short-term contracts		Long-term contracts		Total
Crude oil	$	9,711	$	35,179	$	44,890
Natural gas	136		2,434		2,570
NGLs	113		3,295		3,408

Customer Credit Risk

Our principal exposure to credit risk is through receivables from the sale of our oil and natural gas production of approximately $6.9 million and $8.2 million at September 30, 2019 and December 31, 2018, respectively, and through actual and accrued receivables from our joint interest partners of approximately $16.7 million and $11.4 million at September 30, 2019 and December 31, 2018, respectively. We are subject to credit risk due to the concentration of our oil and natural gas receivables with our most significant customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

Major Customers

During the three and nine months ended September 30, 2019, 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,
	2019		2018		2019		2018
Texican Crude & Hydrocarbon, LLC	—	%	80	%	16	%	84	%
ARM Energy Management, LLC	89	%	—	%	74	%	—	%
Lucid Energy Delaware, LLC	11	%	17	%	10	%	12	%
ETC Field Services LLC	—	%	2	%	—	%	3	%
Other below 10%	—	%	1	%	—	%	1	%
	100	%	100	%	100	%	100	%

Due to availability of other purchasers, we do not believe the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations.

NOTE 5 - OIL AND NATURAL GAS PROPERTIES

The Company uses the full cost method of accounting for oil and natural gas operations. Under this method, costs related to the exploration, non-production related development and acquisition of oil and natural gas reserves are capitalized. Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling, costs of developing and completing productive wells, and other costs directly related to acquisition and exploration activities. Proceeds from property sales are generally applied as a credit against our 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 our proved reserves.

Depletion of exploration and development costs and depreciation of wells and tangible production assets are computed using the units-of-production method based upon estimated proved oil and natural gas reserves. Costs included in the depletion base to be amortized include (a) all proved capitalized costs, including capitalized asset retirement costs net of estimated salvage values, less accumulated depletion, and (b) estimated future development costs to be incurred in developing proved reserves that are not otherwise included in capitalized costs.

Under the full cost method of accounting, capitalized oil and natural gas property costs less accumulated depletion (net of deferred income taxes) may not exceed an amount equal to the sum of the present value, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves and the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are not subject to amortization. Should capitalized costs exceed this ceiling, an impairment expense is recognized. The present value of estimated future net cash flows was computed by applying a flat oil price to forecast revenues from estimated future production of proved oil and natural gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves (assuming the continuation of existing economic conditions), less any applicable future taxes. For the three and nine months ended September 30, 2019, low commodity prices primarily contributed to the excess of net book value of our oil and natural gas properties over the ceiling resulting in the recognition of an impairment charge of $16.6 million. As of September 30, 2019, the ceiling value of the Company's reserves was calculated based upon SEC pricing of $57.77 per barrel for oil and $2.83 per MMBtu for natural gas.

The costs of unproved oil and gas properties are excluded from amortization until the properties are evaluated. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved oil and natural gas reserves are established or if impairment is determined. Unproved oil and gas properties are assessed periodically (at least annually) to determine whether impairment has occurred. The assessment considers the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, the economic viability of development if proved reserves were assigned and other current market conditions. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.

During the nine months ended September 30, 2019, and 2018, impairments of $15.3 million and $11.1 million, respectively, were recorded on the Company's unproved oil and natural gas properties and transferred to the full cost pool due to title defects on certain leases. During the three months ended September 30, 2019 an impairment of $3.9 million were transferred to the full cost pool. There were no unproved property impairments during the three months ended September 30, 2018. For the three months ended September 30, 2019 and 2018, depreciation, depletion, amortization and accretion expense related to proved properties were $5.4 million and $7.2 million, respectively. For the nine months ended September 30, 2019 and 2018, depreciation, depletion, amortization and accretion expense related to proved properties were $22.8 million and $17.6 million, respectively.

The following table sets forth a summary of oil and natural gas property costs (net of divestitures) at September 30, 2019 and December 31, 2018:



	September 30, 2019			December 31, 2018
	(In thousands)
Oil and natural gas properties:
Proved	$	413,065		$	358,858
Unproved	150,652			169,863
Total oil and natural gas properties	563,717			528,721
Accumulated depletion, depreciation, amortization and impairment	(137,297		)	(98,342		)
Oil and natural gas properties, net	$	426,420		$	430,379

NOTE 6 - ACQUISITIONS AND DIVESTITURES

Divestitures During 2019

On July 31, 2019, the Company entered into two agreements with Winkler Lea Royalty, L.P. ("WLR") and Winkler Lea WI, L.P. ("WLWI") for the sale of an overriding royalty interest and a non-operated working interest in undeveloped assets, respectively, for combined cash proceeds of $39.0 million, including WLWI's drilling advance (the "Asset Sales"). WLR and WLWI are affiliates of Värde Partners, Inc., a related party (see Note 13 - Related Party Transactions).

The Company entered into a Purchase and Sale Agreement with WLR (the "ORRI Agreement"), pursuant to which the Company sold to WLR an overriding royalty interest (the "ORRI") in approximately 1,446 net royalty acres in Winkler and Loving Counties, Texas, and Lea County, New Mexico. The ORRI is equal to the positive difference, if any, between 25% and existing royalties and other burdens, subject to proportionate reduction and the other terms and conditions set forth in the instrument of conveyance. The ORRI Agreement provides the Company with a right to repurchase all, but not less than all, of the ORRI for a period of three years and an obligation, at WLR's election only upon a change of control, to repurchase all, but not less than all, of the ORRI, and also includes certain limitations on WLR's right to transfer the ORRI during such three year period without the consent of the Company. The repurchase price for the first two years of the repurchase period is 1.5 times the purchase price paid by WLR, less the proportionate share of production paid by the Company. For the third year, the repurchase price is the same with the multiplier increased to 1.75. After the third year, the repurchase period expires.

The Company entered into a Purchase and Sale Agreement with WLWI (the "WI Agreement"), pursuant to which the Company sold an undivided 49% of its right, title and interest in certain undeveloped assets located in Winkler and Loving Counties, Texas, consisting of approximately 749 net acres. The WI Agreement provides that the Company must drill, complete and equip five commitment wells after closing. Contemporaneously with the purchase, WLWI paid a drilling advance which funded its proportionate share of the development costs to drill, complete and equip such commitment wells. Any drilling cost overruns or costs incurred below estimated costs are the responsibility of the Company. The WI Agreement provides the Company with a right to repurchase all, but not less than all, of the interest for a period of three years and an obligation, at WLWI's election only upon a change of control, to repurchase all, but not less than all, of the interest, and also includes certain limitations on WLWI's right to transfer the interest during such three year period without the consent of the Company. The repurchase price is 1.5 times the consideration paid by WLWI plus additional capital expenditures of WLWI. The repurchase period expires after three years.

As a result of the repurchase rights, the agreements with WLR and WLWI do not meet the criteria for a conveyance or sale of assets under ASC 932 and are accounted for as a financing arrangement under ASC 470. The net proceeds of the transaction of $39.0 million are included in long-term deferred revenue and other long-term liabilities on the Company's condensed consolidated balance sheet as of September 30, 2019. WLR's proportionate share of production of $0.1 million for the three and nine months ended September 30, 2019 are included in interest expense on the Company's condensed consolidated statements of operations. None of the properties included in the WI Agreement were producing as of September 30, 2019.

On August 16, 2019, we sold approximately 513 noncontiguous net acres in New Mexico for net cash proceeds of $16.6 million, which was recorded as a reduction to the full cost pool. The Company repurchased certain overriding royalty interests in the acreage previously sold to WLR under the ORRI Agreement for $2.6 million, resulting in a $1.3 million loss on extinguishment of a portion of the financing arrangement and is included in loss on early extinguishment of debt on the Company's condensed consolidated statements of operations.

Acquisitions During 2018

During the nine months ended September 30, 2018, the Company acquired the following oil and natural gas properties:

•

Certain leasehold acreage in the Delaware Basin in Lea County, New Mexico from OneEnergy Partners Operating, LLC for $40.0 million in cash and 6,940,722 shares of the Company's common stock valued at approximately $24.9 million, for total consideration of approximately $64.9 million. Transaction costs associated with this acquisition were approximately $1.1 million. The transaction was recorded as an asset acquisition.


•	Certain leasehold interests and other oil and natural gas assets in Loving and Winkler Counties, Texas from VPD Texas, L.P. for total cash consideration of approximately $11.1 million, including approximately $0.5 million of related acquisition costs. The transaction was recorded as an asset acquisition.


•	Certain leasehold interests and other oil and natural gas assets in Loving and Winkler Counties, Texas from Anadarko for total cash consideration of $7.1 million. The transaction was recorded as an asset acquisition.


•	Certain leasehold interests and other oil and natural gas assets in Lea County, New Mexico from Ameradev II, LLC for total cash consideration of $7.2 million and was recorded as an adjustment to the full cost pool.


•	Certain leasehold interests and other oil and natural gas assets in Loving and Winkler Counties, Texas from Felix Energy Holdings II, LLC for total cash consideration of $0.4 million and was recorded as an adjustment to the full cost pool.

NOTE 7 - ASSET RETIREMENT OBLIGATIONS

The Company's asset retirement obligations ("ARO") represent the present value of the estimated cash flows expected to be incurred to plug, abandon and remediate producing properties, excluding salvage values, at the end of their productive lives in accordance with applicable laws. Revisions in estimated liabilities during the period relate primarily to changes in estimates of asset retirement costs. Revisions in estimated liabilities can also include, but are not limited to, revisions of estimated inflation rates, changes in property lives and expected timing of settlement.

The following table summarizes the changes in the Company's ARO for the nine months ended September 30, 2019 and the year ended December 31, 2018:



	September 30, 2019			December 31, 2018
	(In thousands)
ARO, beginning of period	$	2,444		$	952
Additional liabilities incurred	152			374
Accretion expense	244			85
Liabilities settled	(78		)	(87		)
Revision in estimates	(42		)	1,120
ARO, end of period	2,720			2,444
Less: current portion of ARO	(11		)	(11		)
ARO, non-current	$	2,709		$	2,433

NOTE 8 - FAIR VALUE OF FINANCIAL INSTRUMENTS

The Company measures the fair value of its financial assets on a three-tier value hierarchy, which prioritizes the inputs used in the valuation methodologies in measuring fair value:



	●	Level 1 - Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.



	●	Level 2 - Other inputs that are directly or indirectly observable in the marketplace.



	●	Level 3 - Unobservable inputs which are supported by little or no market activity.

The fair value hierarchy also requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

Determination of the fair values of our derivative contracts incorporates various factors, including not only the impact of our non-performance risk on our liabilities, but also the credit standing of the counterparties involved. The Company utilizes counterparty rate of default values to assess the impact of non-performance risk when evaluating both our liabilities to, and receivables from, counterparties.

Recurring Fair Value Measurements



	Fair Value Measurement Classification
	Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total
	(In thousands)
As of September 30, 2019
Oil and natural gas derivative instruments:
Oil and natural gas derivative swap contracts	$	—	$	(1,343	)	$	—		$	(1,343	)
Oil and natural gas derivative collar contracts	—		2,355			—			2,355
Total	$	—	$	1,012		$	—		$	1,012
As of December 31, 2018
Oil and natural gas derivative instruments:
Oil and natural gas derivative swap contracts	$	—	$	(2,923	)	$	—		$	(2,923	)
Oil and natural gas derivative collar contracts	—		4,047			—			4,047
Embedded derivative instruments:
Second Lien Term Loan conversion features	—		—			(1,965		)	(1,965		)
Total	$	—	$	1,124		$	(1,965	)	$	(841	)

Derivative assets and liabilities include unsettled amounts related to commodity derivative positions, including swaps and collars, as of September 30, 2019 and December 31, 2018. The fair value of the Company's derivatives is based on third-party pricing models which utilize inputs that are either readily in the public market or which can be corroborated from active markets of broker quotes. Swaps and collars generally have observable inputs and these instruments are measured using Level 2 inputs.

The Company's derivative liabilities as of December 31, 2018 also include embedded derivatives associated with the Second Lien Term Loan (as defined in Note 11 - Long-Term Debt). These instruments have fewer observable inputs from objective sources and are therefore measured using Level 3 inputs.

NOTE 9 - DERIVATIVES

The Company's derivative instruments as of September 30, 2019 and December 31, 2018, include the following:



	September 30, 2019			December 31, 2018
	(In thousands)
Derivative assets (liabilities):
Derivative assets - current	$	2,388		$	2,551
Derivative assets - non-current⁽¹⁾	2,155			1,822
Derivative liabilities - current	(2,855		)	(515		)
Derivative liabilities - non-current⁽²⁾⁽³⁾	(676		)	(4,699		)
Total derivative liabilities, net	$	1,012		$	(841	)

⁽¹⁾The non-current derivative assets are included in other assets in the consolidated balance sheets.

⁽²⁾The non-current derivative liabilities are included in long-term derivative instruments and other non-current liabilities in the consolidation balance sheets.

⁽³⁾Includes $2.0 million of embedded derivatives associated with Second Lien Term Loan and $2.7 million associated with commodity derivatives as of December 31, 2018.

Embedded Derivatives

As discussed in Note 11 - Long-Term Debt, the Second Lien Term Loan contained conversion features that were exercisable at the option of the lead lender thereunder or, in certain circumstances, the Company. The conversion features have been identified as embedded derivatives which (i) contain economic characteristics that are not clearly and closely related to the host contract, the Second Lien Term Loan, and (ii) are separate, stand-alone instruments with similar terms that would qualify as derivative instruments. As such, the conversion features were bifurcated and accounted for separately from the Second Lien Term Loan. The conversion features are recorded at fair value for each reporting period with changes in fair value included in the Company's condensed consolidated statement of operations for each reporting period.

As of December 31, 2018, the derivative liabilities associated with the Second Lien Term Loan were approximately $2.0 million. On March 5, 2019, the embedded derivative associated with the Second Lien Term Loan was written off against the gain on extinguishment of debt following the extinguishment of the Second Lien Term Loan on March 5, 2019, pursuant to the provisions of the 2019 Transaction Agreement (as defined in Note 11 - Long-Term Debt).

Commodity Derivatives

To reduce the impact of fluctuations in oil and natural gas prices on the Company's revenues and to protect the economics of property acquisitions, the Company periodically enters into derivative contracts with respect to a portion of its projected oil and natural gas production through various transactions that fix or modify the future prices to be realized. The derivative contracts may include fixed-for-floating price swaps (whereby, on the settlement date, the Company will receive or pay an amount based on the difference between a pre-determined fixed price and a variable market price for a notional quantity of production), put options (whereby the Company pays a cash premium in order to establish a fixed floor price for a notional quantity of production and, on the settlement date, receives the excess, if any, of the fixed floor price over a variable market price), and costless collars (whereby, on the settlement date, the Company receives the excess, if any, of a variable market price over a fixed floor price up to a fixed ceiling price for a notional quantity of production).

Our hedging activities are intended to support oil and natural gas prices at targeted levels and manage exposure to oil and natural gas price fluctuations, as well as to meet our obligations under our Revolving Credit Agreement (as defined in Note 11 - Long-Term Debt). It is our policy to enter into derivative contracts only with counterparties that are creditworthy and competitive market makers. All of our derivatives are designated as unsecured. Certain of our derivative counterparties may require the posting of cash collateral under certain conditions. The Company does not enter into derivative contracts for speculative trading purposes.

All of our derivatives are accounted for as mark-to-market activities. Under Accounting Standard Codification ("ASC") Topic 815, "Derivatives and Hedging," these instruments are recorded on the Company's condensed consolidated balance sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. The Company nets derivative assets and liabilities by commodity for counterparties where a legal right to such offset exists. Because the Company

has elected not to designate its current derivative contracts as cash flow hedges for accounting purposes, changes in the fair values of the derivatives are recognized in current earnings.

The following table presents the Company's derivative position for the production periods indicated as of September 30, 2019:



Description		Notional Volume (Bbls/d)	Production Period	Weighted Average Price ($/Bbl)
Oil Positions
Oil Swaps		173	October 2019 - December 2019	$	58.80
Oil Swaps		1,028	January 2020 - December 2020	$	56.28
Oil Swaps		370	January 2021 - December 2021	$	53.07

Basis Swaps ⁽¹⁾		1,500	October 2019 - December 2019	$	(5.62	)
Basis Swaps ⁽¹⁾		1,500	January 2020 - December 2020	$	(5.62	)

3 Way Collar	Floor sold price (put)	1,500	October 2019 - December 2019	$	45.00
3 Way Collar	Floor purchase price (put)	1,500	October 2019 - December 2019	$	55.00
3 Way Collar	Ceiling sold price (call)	1,500	October 2019 - December 2019	$	70.47

Oil Collar	Floor purchase price (put)	500	October 2019 - December 2019	$	50.00
Oil Collar	Ceiling sold price (call)	500	October 2019 - December 2019	$	58.00
Oil Collar	Floor purchase price (put)	512	January 2020 - December 2020	$	49.50
Oil Collar	Ceiling sold price (call)	512	January 2020 - December 2020	$	63.87
Oil Collar	Floor purchase price (put)	742	January 2021 - December 2021	$	50.00
Oil Collar	Ceiling sold price (call)	742	January 2021 - December 2021	$	59.70

Description		Notional Volume (MMBtus/d)	Production Period	Weighted Average Price ($/MMBtu)
Natural Gas Positions
Gas Swaps		4,807	October 2019 - December 2019	$	2.53
Gas Swaps		4,557	January 2020 - December 2020	$	2.57
Gas Swaps		4,184	January 2021 - March 2021	$	2.77

Gas Collar	Floor purchase price (put)	6,921	November 2019 - December 2019	$	2.80
Gas Collar	Ceiling sold price (call)	6,921	November 2019 - December 2019	$	3.06
Gas Collar	Floor purchase price (put)	2,748	January 2020 - December 2020	$	2.55
Gas Collar	Ceiling sold price (call)	2,748	January 2020 - December 2020	$	3.07
Gas Collar	Floor purchase price (put)	4,464	January 2021 - December 2021	$	2.20
Gas Collar	Ceiling sold price (call)	4,464	January 2021 - December 2021	$	2.97


⁽¹⁾	The weighted average price under these basis swaps is the fixed price differential between the index prices of the Midland WTI and the Cushing WTI.

The table below summarizes the Company's net gain (loss) on commodity derivatives for the three and nine months ended September 30, 2019 and 2018:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(in thousands)						(in thousands)
Unrealized gain (loss) on unsettled derivatives	$	4,383		$	(4,008	)	$	(112	)	$	(7,250	)
Net settlements paid on derivative contracts	(233		)	(611		)	(3,414		)	(1,941		)
Net settlements receivable (payable) on derivative contracts	(207		)	(192		)	(207		)	(192		)
Net gain (loss) on commodity derivatives	$	3,943		$	(4,811	)	$	(3,733	)	$	(9,383	)

The following information summarizes the gross fair values of derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Company's condensed consolidated balance sheets as of September 30, 2019 and as of December 31, 2018:



	As of September 30, 2019
	Gross Amount of Recognized Assets and Liabilities			Gross Amounts Offset in the Condensed Consolidated Balance Sheets			Net Amounts Presented in the Condensed Consolidated Balance Sheets
	(In thousands)
Offsetting Derivative Assets:
Current assets	$	2,750		$	(362	)	$	2,388
Long-term assets	2,227			(72		)	2,155
Total assets	$	4,977		$	(434	)	$	4,543
Offsetting Derivative Liabilities:
Current liabilities	$	(3,217	)	$	362		$	(2,855	)
Long-term commodity derivative liabilities	(748		)	72			(676		)
Total liabilities	$	(3,965	)	$	434		$	(3,531	)



	As of December 31, 2018
	Gross Amount of Recognized Assets and Liabilities			Gross Amounts Offset in the Condensed Consolidated Balance Sheets			Net Amounts Presented in the Condensed Consolidated Balance Sheets
	(In thousands)
Offsetting Derivative Assets:
Current assets	$	4,122		$	(1,571	)	$	2,551
Long-term assets	1,854			(32		)	1,822
Total assets	$	5,976		$	(1,603	)	$	4,373
Offsetting Derivative Liabilities:
Current liabilities	$	(2,086	)	$	1,571		$	(515	)
Long-term commodity derivative liabilities	(2,766		)	32			(2,734		)
Long-term embedded derivative liabilities	(1,965		)	—			(1,965		)
Total liabilities	$	(6,817	)	$	1,603		$	(5,214	)

NOTE 10 - LEASES

Lease Recognition

The Company has entered into contractual lease arrangements to rent office space, compressors, drilling rigs and other equipment from third-party lessors. Right-of-use ("ROU") assets represent the Company's right to use an underlying asset for the lease term and lease liabilities represent the Company's obligation to make future lease payments arising from the lease. Operating lease ROU assets and liabilities are recorded at commencement date based on the present value of lease payments over the lease term. Lease payments included in the measurement of the lease liability include fixed payments and termination penalties or extensions that are reasonably certain to be exercised. Variable lease costs associated with leases are recognized when incurred and generally represent maintenance services provided by the lessor, allocable real estate taxes and local sales and business taxes. Leases with an initial term of 12 months or less are not recorded on the balance sheet. The Company recognizes lease expense on a straight-line basis over the lease term. The Company does not account for lease components separately from the non-lease components. The Company uses the implicit interest rate when readily determinable; however, most of the Company's lease agreements do not provide an implicit interest rate. As such, at implementation and for new or modified leases subsequent to January 1, 2019, the Company uses its incremental borrowing rate based on the information available at commencement date of the contract in determining the present value of future lease payments. The incremental borrowing rate is calculated using a risk-free interest rate adjusted for the Company's risk. Operating lease ROU assets also include any lease incentives received in the recognition of the present value of future lease payments. Certain of the Company's leases may also include escalation clauses or options to extend or terminate the lease. These options are included in the present value recorded for the leases when it is reasonably certain that the Company will exercise that option. Lease expense for lease payments is recognized on a straight-line basis over the lease term.

The Company determines if an arrangement is or contains a lease at inception of the contract and records the resulting operating lease asset on the condensed consolidated balance sheets as an asset, with offsetting liabilities recorded as a liability. The Company recognizes a lease in the consolidated financial statements when the arrangement either explicitly or implicitly involves property or equipment, the contract terms are dependent on the use of the property or equipment, and the Company has the ability or right to operate the property or equipment or to direct others to operate the property or equipment and receives greater than 10% of the economic benefits of the assets. As of September 30, 2019, the Company does not have any financing leases.

The Company has adopted the modified retrospective method for the new lease recognition rule. Therefore, prior periods are not presented as prior period amounts have not been adjusted under the modified retrospective. Refer to Note 2 - Summary of Significant Accounting Policies and Estimates for additional information.

As of September 30, 2019, the Company's ROU assets and operating lease liabilities were included in the condensed consolidated balance sheets as follows (in thousands):



Right of use assets:
Right of use assets - long-term⁽¹⁾	$	10,635

Lease liabilities:
Lease liabilities - current ⁽²⁾	$	8,212
Lease liabilities - long-term ⁽³⁾	2,617
Total lease liabilities	$	10,829

⁽¹⁾Right of use assets - long-term are included in other assets on the condensed consolidated balance sheets.

⁽²⁾Lease liabilities - current are included in accrued liabilities and other on the condensed consolidated balance sheets.

⁽³⁾ Lease liabilities - long-term are included in long-term derivatives instruments and other on the condensed consolidated balance sheets.

During the second quarter of 2019, the Company canceled a long-term drilling rig lease, within the terms of the agreement, which resulted in the write-off of the related lease liability and ROU asset of $5.4 million, respectively.

During the third quarter of 2019, the Company entered into a new long-term drilling rig lease which resulting in a lease liability and ROU asset of $10.8 million, respectively.

Lease costs represent the straight line lease expense of ROU assets, short-term leases, and variable lease costs. For the three and nine months ended September 30, 2019, the components of lease cost were classified as follows (in thousands):



	Three Months Ended September 30, 2019		Nine Months Ended September 30, 2019
Fixed lease costs	$	1,249	$	4,085
Short-term lease costs	120		329
Variable lease costs	508		626
Total lease costs	$	1,877	$	5,040



Lease Cost included in the Condensed Consolidated Financial Statements	Nine Months Ended September 30, 2019
Oil and natural gas properties, full cost method of accounting, net⁽¹⁾	$	4,417
Total lease costs capitalized	4,417

Production costs	312
General and administrative	311
Total lease costs expensed	623
Total lease costs	$	5,040

⁽¹⁾Represents short-term lease capital expenditures related to drilling rigs for the nine months ended September 30, 2019.

During the nine months ended September 30, 2019, the following cash activities were associated with the Company's leases as follows (in thousands):



Cash paid for amounts included in the measurement of operating lease liabilities:
Operating cash flows from operating leases	$	115
Investing cash flows from operating leases	$	3,767

As of September 30, 2019, the weighted average lease term and discount rate related to the Company's remaining leases were as follows:



Lease term and discount rate
Weighted-average remaining lease term (years)	1.26
Weighted-average discount rate	5.6	%

As of September 30, 2019, minimum future payments, including imputed interest, for long-term operating leases under the scope of ASC Topic 842, "Leases", are as follows (in thousands):



Year	Amount
2019	$	2,168
2020	9,007
2021	79
2022	—
2023	—
After 2023	—
Less: the effects of discounting	(425		)
Present value of lease liabilities	$	10,829

As of December 31, 2018, minimum future payments, including imputed interest, for long-term operating leases under the scope of ASC Topic 840, "Leases", are as follows (in thousands):



Year	Amount
2019	$	7,586
2020	66
2021	—
2022	—
2023	—
After 2023	—
Total lease commitment	$	7,652

NOTE 11 - LONG-TERM DEBT



	September 30, 2019		December 31, 2018
	(In thousands)
8.25% Second Lien Term Loan, due 2021, net of debt issuance costs and debt discount	$	—	$	82,804
Revolving Credit Agreement, due October 2023	105,000		75,000
Total long-term debt	$	105,000	$	157,804

Revolving Credit Agreement

On October 10, 2018, the Company entered into a five-year, $500.0 million senior secured revolving credit agreement by and among the Company, as borrower, certain subsidiaries of the Company, as guarantors (the "Guarantors"), BMO Harris Bank, N.A., as administrative agent, and the lenders party thereto (the "Revolving Credit Agreement"). The Revolving Credit Agreement provides for a senior secured reserve based revolving credit facility with an initial borrowing base of $95.0 million. The borrowing base is subject to semiannual re-determinations in May and November of each year. In December 2018, the borrowing base was increased to $108.0 million in connection with our scheduled borrowing base re-determination. On March 5, 2019, the Company's borrowing base under the Revolving Credit Agreement was increased from $108.0 million to $125.0 million, as the result of an acceleration of the scheduled May 2019 borrowing base redetermination pursuant to the First Amendment (as defined below). As provided in the Third Amendment (as defined below) and as a result of the Asset Sales (as defined in Note 6 - Acquisitions and Divestitures), in July 2019, the borrowing base was decreased to $115.0 million. The redetermination of the borrowing base in the Third Amendment was the scheduled July redetermination, and we expect the next redetermination, scheduled to occur on or about November 1, 2019, to occur in mid-November 2019.

Borrowings under the Revolving Credit Agreement bear interest at a floating rate of either LIBOR or a specified base rate plus a margin determined based upon the usage of the borrowing base. The Company is required to pay a commitment fee of 0.5% per annum on any unused portion of the borrowing base. The Company's obligations under the Revolving Credit Agreement are secured by first priority liens on substantially all of the Company's and the Guarantors' assets and are unconditionally guaranteed by each of the Guarantors.

As of September 30, 2019, outstanding borrowings under the Revolving Credit Agreement were $105.0 million, leaving $10.0 million available for future borrowing. Future borrowings may be used to fund working capital requirements, including for the acquisition, exploration and development of oil and gas properties, and for general corporate purposes. The Revolving Credit Agreement also provides for issuance of letters of credit in an aggregate amount of up to $5.0 million. As of October 31, 2019, we were fully drawn against the borrowing base under our Revolving Credit Agreement, with $115 million of indebtedness outstanding under our Revolving Credit Agreement.

The Company capitalizes certain direct costs associated with the debt issuance under the Revolving Credit Agreement and amortizes such costs over the term of the debt instrument. The deferred financing costs related to the Revolving Credit Agreement are classified in assets. For the three and nine months ended September 30, 2019, the Company amortized debt issuance costs associated with the Revolving Credit Agreement of $0.3 million and $0.6 million, respectively. As of September 30, 2019, the Company had $0.6 million and $1.9 million of unamortized deferred financing costs in other current assets and non-current assets, respectively. As of December 31, 2018, the Company has $0.5 million and $1.7 million of unamortized deferred financing costs in other current assets and non-current assets, respectively. The Company did not have a revolving credit agreement in place

during the nine months ended September 30, 2018.

The Revolving Credit Agreement matures on October 10, 2023. Borrowings under the Revolving Credit Agreement are subject to mandatory repayment in certain circumstances, including upon certain asset sales and debt incurrences or if a borrowing base deficiency occurs. The Company also may voluntarily repay borrowings from time to time and, subject to the borrowing base limitation and other customary conditions, may re-borrow amounts that are voluntarily repaid. Mandatory and voluntary repayments generally will be made without premium or penalty.

The Revolving Credit Agreement contains certain customary representations and warranties and affirmative and negative covenants, including covenants relating to: maintenance of books and records; financial reporting and notification; compliance with laws; maintenance of properties and insurance; and limitations on incurrence of indebtedness, liens, fundamental changes, international operations, asset sales, certain debt payments and amendments, restrictive agreements, investments, dividends and other restricted payments and hedging. It also requires the Company to maintain a ratio of Total Debt to EBITDAX (each as defined in the Revolving Credit Agreement) (the "Leverage Ratio") of not more than 4.00 to 1.00 and a ratio of Current Assets to Current Liabilities (each as defined in the Revolving Credit Agreement) (the "Current Ratio") of not less than 0.85 to 1.00 as of September 30, 2019 and not less than 1.00 to 1.00 as of the last day of each fiscal quarter thereafter.

As of September 30, 2019, the Company was in compliance with the Current Ratio covenant under the Revolving Credit Agreement but was not in compliance with the Leverage Ratio covenant under the Revolving Credit Agreement. Pursuant to the Fourth Amendment (as defined below), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio covenant as of September 30, 2019. The Company was not in compliance with the Leverage Ratio covenant as of September 30, 2019 due to the Company voluntarily shutting-in wells across its properties to begin testing and implementing certain natural gas and crude oil treating systems, in addition to shutting-in certain wells during the third quarter while flare permits were being extended.

Compliance with the Leverage Ratio covenant in future periods depends on our ability to keep wells online and consistently flowing to sales, commodity prices, our ability to control costs, and if necessary, our ability to complete sales of non-core assets or access other sources of capital to reduce indebtedness. During the third quarter of 2019, the necessary flaring permits were renewed and extended, and, therefore, we expect wells will not need to be shut-in for flaring regulations in the foreseeable future. Additionally, we expect the field treating installed across our properties will help to ensure consistent, uninterrupted flow of oil and gas to sales compared to previous periods. We expect, with those measures providing a more consistent flow of oil and gas to sales, the continuing ability to execute cost reduction measures, the ability to sell non-core assets and the ability to access other sources of capital, will allow us to meet our financial covenants and maintain sufficient liquidity in future periods. However, our future cash flows, and consequently our EBITDAX, are subject to a number of variables, including uncertainty in forecasted production volumes and commodity prices, and we may not be able to complete sales of non-core assets or access other sources of capital on acceptable terms or at all.

The Revolving Credit Agreement also provides for events of default, including failure to pay any principal, interest or other amounts when due, failure to perform or observe covenants, cross-default on certain outstanding debt obligations, inaccuracy of representations and warranties, certain ERISA events, change of control, the security documents or guaranty ceasing to be effective, and bankruptcy or insolvency events, subject to customary cure periods. Amounts owed by the Company under the Revolving Credit Agreement could be accelerated and become immediately due and payable following the occurrence of an event of default.

The Revolving Credit Agreement also provides for the Company to have and maintain Swap Agreements (as defined in the Revolving Credit Agreement) in respect of crude oil and natural gas, on not less than 50% of the projected production from the proved reserves classified as Developed Producing Reserves attributable to the oil and natural gas properties of the Company as reflected in the most recently delivered reserve report for a period through at least 24 months after the end of each applicable quarter. Pursuant to the Third Amendment, commencing with the fiscal quarter ending September 30, 2019, the Company will be required to maintain Swap Agreements on not less than 75% of the projected production from proved reserves classified as "Developed Producing Reserves" attributable to the oil and natural gas properties of the Company, as reflected in the most recently delivered reserve report, for a period through at least 24 months after the end of each applicable quarter. For further information on our hedges, see Note 9 - Derivatives.

First Amendment and Waiver to Revolving Credit Agreement

On March 1, 2019, the Company entered into a First Amendment and Waiver (the "First Amendment") to the Revolving Credit Agreement. Among other matters, the First Amendment provided for the acceleration of the scheduled May 2019 redetermination of the borrowing base described above, which became effective on March 5, 2019 upon closing of the transactions contemplated by the 2019 Transaction Agreement (as defined below), including the satisfaction in full, as described below, of the Second Lien Term Loan under the Second Lien Credit Agreement (as defined below). The First Amendment also provides for the July 2019 scheduled redetermination of the borrowing base described above.

In addition, the First Amendment provided for a limited waiver of compliance by the Company with the Leverage Ratio covenant in the Revolving Credit Agreement as of December 31, 2018. Further, in connection with the satisfaction in full of the Second Lien Term Loan and the termination of the Second Lien Credit Agreement, the First Amendment amended the maturity date provisions of the Revolving Credit Agreement to eliminate any springing maturity under the Revolving Credit Agreement tied to the maturity of the Second Lien Credit Agreement, resulting in a fixed maturity date under the Revolving Credit Agreement of October 10, 2023. The First Amendment also effected certain other ministerial and conforming amendments to the Revolving Credit Agreement related to the transactions contemplated by the 2019 Transaction Agreement and required payment by the Company to the lenders of customary fees.

Second Amendment and Waiver to Revolving Credit Agreement

On May 6, 2019, the Company entered into a Second Amendment and Waiver (the "Second Amendment") to the Revolving Credit Agreement, pursuant to which the requisite lenders under the Revolving Credit Agreement waived compliance by the Company with the Current Ratio covenant as of March 31, 2019 in exchange for a customary consent fee. Additionally, the Second Amendment provided for a 25-basis point increase in the interest rate margin applicable to loans under the Revolving Credit Agreement if the Company's Leverage Ratio is equal to or greater than 3.00 to 1.00. The Second Amendment also provides that if the Company has available cash and cash equivalents (subject to certain carveouts) in excess of $10 million for a period of at least five consecutive business days, then it must prepay the loans under the Revolving Credit Agreement in the amount of such excess.

Third Amendment and Waiver to Revolving Credit Agreement

On July 26, 2019, the Company entered into a Third Amendment (the "Third Amendment") to the Revolving Credit Agreement, pursuant to which the requisite required lenders under the Revolving Credit Agreement agreed to reduce the borrowing base to $115 million from $125 million as a part of the scheduled July 1, 2019 redetermination and as a result of the Asset Sales; to give pro forma effect to the Asset Sales for the calculation of EBITDAX, Total Debt, and Current Liabilities at June 30, 2019; and, subject to the consummation of the Asset Sales completed on July 31, 2019 and the required use of the proceeds, to amend the Current Ratio to be not less than 0.85 to 1.00 on September 30, 2019, rather than the minimum Current Ratio of 1.00 to 1.00 required otherwise. Additionally, the Third Amendment provides for, among other things, an increase in the required amount hedged to 75% of projected production from proved reserves classified as "Developed Producing Reserves". The Third Amendment also effected certain other ministerial changes to the Revolving Credit Agreement and required payment by the Company to the lenders of customary fees.

Fourth Amendment and Waiver to Revolving Credit Agreement

On November 5, 2019, the Company entered into a Fourth Amendment and Waiver (the "Fourth Amendment") to the Revolving Credit Agreement, pursuant to which, among other matters, the requisite lenders under the Revolving Credit Agreement waived compliance by the Company with the Leverage Ratio covenant as of September 30, 2019 in exchange for a customary consent fee. Additionally, the Fourth Amendment modified the Leverage Ratio for future periods by modifying the manner in which EBITDAX is calculated for the periods ending December 31, 2019, March 31, 2020 and June 30, 2020 such that EBITDAX is calculated on an annualized basis for those periods, excluding quarterly periods ended prior to December 31, 2019. The Fourth Amendment also (1) requires the Company to use 100% of net cash proceeds from dispositions to repay borrowings until completion of the scheduled November 1, 2019 redetermination or during a borrowing base deficiency, (2) added completion of the scheduled November 1, 2019 redetermination as a condition precedent to future borrowings and (3) limits certain exceptions to certain of the negative covenants under the Revolving Credit Agreement during the period from the date of the Fourth Amendment to the date on which annual financial statements for the fiscal year ending December 31, 2019 are delivered.

Second Lien Credit Agreement

On April 26, 2017, the Company entered into a second lien credit agreement (the "Second Lien Credit Agreement"), by and among the Company, certain subsidiaries of the Company, as guarantors, Wilmington Trust, National Association, as administrative agent, and the lenders party thereto, consisting of certain private funds affiliated with Värde Partners, Inc. ("Värde"). The Second Lien Credit Agreement provided for convertible loans in an aggregate initial principal amount of up to $125 million in two tranches (together, the "Second Lien Term Loan"). The first tranche consisted of an $80 million term loan, which was fully drawn and funded on April 26, 2017. The second tranche consisted of up to $45 million in delayed-draw term loans, which was fully drawn and funded in October 2017. In November 2017, the Second Lien Credit Agreement was amended to increase the amount available for borrowing under the second tranche of the Second Lien Term Loan by $25 million, and the additional $25 million was fully drawn and funded in November 2017.

Prior to the satisfaction in full of the Second Lien Term Loan and the termination of the Second Lien Credit Agreement on March 5, 2019, as described below, the Second Lien Term Loan bore interest at a rate per annum of 8.25%, compounded quarterly in arrears and payable only in-kind by increasing the principal amount of the loan by the amount of the interest due on each interest payment date, and had a maturity date of April 26, 2021.

Each tranche of the Second Lien Term Loan was separately convertible at any time, in full and not in part, at the option of Värde, as lead lender, as follows: (i) 70% of the principal amount, together with accrued and unpaid interest and the make-whole premium on such principal amount, would convert into a number of shares of the Company's common stock determined by dividing the total of such principal amount, accrued and unpaid interest and make-whole premium by $5.50 (subject to certain customary adjustments, the "Conversion Price"); and (ii) 30% of the principal amount, together with accrued and unpaid interest and the make-whole premium on such principal amount, would convert on a dollar for dollar basis into a new term loan. Additionally, if the closing price of the Company's common stock on the principal exchange on which it was traded had been at least 150% of the Conversion Price then in effect for at least 20 of the 30 immediately preceding trading days, the Company had the option to convert the Second Lien Term Loan, in whole or in part, into a number of shares of its common stock determined by dividing the principal amount to be converted, together with accrued and unpaid interest on such principal amount, by the Conversion Price.

On October 10, 2018, the Company entered into a transaction agreement (the "2018 Transaction Agreement") by and among the Company and certain private funds affiliated with Värde that were lenders under the Second Lien Credit Agreement (collectively, the "Värde Parties"), pursuant to which, among other matters, the Company issued to the Värde Parties (i) an aggregate of 5,952,763 shares of its common stock and (ii) 39,254 shares of a newly created series of preferred stock of the Company, designated as "Series D 8.25% Convertible Participating Preferred Stock", as consideration for the reduction by approximately $56.3 million of the outstanding principal amount of the Second Lien Term Loan under the Second Lien Credit Agreement, together with accrued and unpaid interest and the make-whole amount thereon totaling approximately $11.9 million.

On March 5, 2019, the Company entered into a transaction agreement (the "2019 Transaction Agreement") by and among the Company and the Värde Parties pursuant to which, among other matters, the Company issued to the Värde Parties shares of two new series of its preferred stock and shares of its common stock, as consideration for the termination of the Second Lien Credit Agreement and the satisfaction in full, in lieu of repayment in cash, of the Second Lien Term Loan. Specifically, in exchange for satisfaction of the outstanding principal amount of the Second Lien Term Loan, accrued and unpaid interest thereon and the make-whole amount totaling approximately $133.6 million (the "Second Lien Exchange Amount"), the Company issued to the Värde Parties:


•	an aggregate of 55,000 shares of a newly created series of preferred stock of the Company, designated as "Series F 9.00% Participating Preferred Stock" (the "Series F Preferred Stock"), corresponding to $55 million of the Second Lien Exchange Amount based on the aggregate initial Stated Value (as defined in Note 14 - Preferred Stock) of the shares of Series F Preferred Stock;


•	an aggregate of 60,000 shares of a newly created series of preferred stock of the Company, designated as "Series E 8.25% Convertible Participating Preferred Stock" (the "Series E Preferred Stock"), corresponding to $60 million of the Second Lien Exchange Amount based on the aggregate initial Stated Value (as defined in Note 14 - Preferred Stock) of the shares of Series E Preferred Stock; and


•	9,891,638 shares of common stock, corresponding to approximately $18.6 million of the Second Lien Exchange Amount, based on the closing price of the Company's common stock on the NYSE American on March 4, 2019 of $1.88.

Subsequent to this transaction, the Company's long-term debt consists solely of borrowings under the Revolving Credit Agreement.

As a result of the satisfaction in full of the Second Lien Term Loan pursuant to the 2019 Transaction Agreement, the Company recorded a gain on extinguishment of debt of $7.1 million, which was recorded as an increase in additional paid in capital due to the Värde Parties, being existing shareholders of the Company.

Interest Expense

The components of interest expense are as follows (in thousands) for the three and nine months ended September 30, 2019 and 2018:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Interest on debt	$	1,681	$	1,238	$	4,829	$	3,776
Net revenue payments on financing arrangement	146		—		146		—
Paid-in-kind interest on term loans	—		3,373		1,590		9,810
Amortization of debt financing costs	359		249		637		1,130
Amortization of discount on term loans	—		4,089		1,657		11,893
Total	$	2,186	$	8,949	$	8,859	$	26,609

NOTE 12 - LONG-TERM DEFERRED REVENUE LIABILITIES AND OTHER LONG-TERM LIABILITIES



	September 30, 2019		December 31, 2018
	(in thousands)
Long-term deferred revenue liabilities	$	42,500	$	52,500
Other long-term liabilities	36,833		13
Total long-term deferred revenue liabilities and other long-term liabilities	$	79,333	$	52,513

SCM Water LLC's Option to Exercise Purchase of Salt Water Disposal Assets

In July 2018, the Company entered into a water gathering and disposal agreement and a contract operating and right of first refusal agreement with SCM Water, LLC ("SCM Water"), a subsidiary of Salt Creek Midstream, LLC ("SCM"). The water gathering agreement complements the Company's existing water disposal infrastructure, and the Company has reserved the right to recycle its produced water. SCM Water will commence, upon receipt of regulatory approval, to build out new gathering and disposal infrastructure to all of the Company's current and future well locations in Lea County, New Mexico, and Winkler County, Texas. All future capital expenditures to construct, maintain and operate the water gathering system will be fully funded by SCM Water and will be designed to accommodate all water produced by the Company's operations. Pursuant to the contract operating agreement, the Company will act as contract operator of SCM Water's salt water disposal wells.

Additionally, the Company sold to SCM Water an option to acquire the Company's existing water infrastructure, a system which is comprised of approximately 14 miles of pipeline and one SWD well, for cash consideration upon closing, with additional payments based on reaching certain milestones.

On March 7, 2019, SCM Water exercised its option to purchase the Company's existing water infrastructure. The Company determined that approximately $11.7 million of the upfront payments were attributable to the sale of the water infrastructure and right-of-way/easement, and recorded the exercise of the option as a reduction of deferred liabilities and a reduction of oil and gas properties.

The Company is actively working on permitting additional SWD well locations. The Company anticipates that the majority of its water will eventually be disposed of through the future SCM Water system at a competitive gathering rate under the agreement. Total cash consideration for the water gathering and disposal infrastructure is $20.0 million. On July 25, 2018, the Company received an upfront non-refundable payment of $10.0 million for the option to acquire its existing water infrastructure and $5.0 million for a prefunded drilling bonus. Additionally, the Company received $2.5 million on October 1, 2018 as a bonus for the grant of an area right-of-way/easement, and the water gathering agreement provided that the Company would receive an additional $2.5 million bonus upon hitting the target of 40,000 barrels per day of produced water.

On March 11, 2019, the Company, SCM Water, and ARM Energy Management, LLC ("ARM"), a related company to SCM Water, agreed to amend the terms of the previously negotiated water gathering and disposal agreement and entered into a new crude oil sales contract (See Note 4 - Revenue and Note 20 - Commitments and Contingencies). Under the terms of such agreements, the Company agreed to an increase in salt water disposal rates in exchange for more favorable pricing differentials on the crude oil sales contract, modification on the minimum quantities of crude oil required under the crude oil sales contract, an upfront payment of $2.5 million and the elimination of the potential bonus for hitting a target of 40,000 barrels of produced water per day. The Company determined that the upfront $2.5 million payment was primarily attributable to the crude oil sales contract, and the Company recorded the $2.5 million payment as deferred revenues and will recognize it in income ratably as the crude oil is sold.

Crude Oil Gathering Agreement and Option Agreement

On May 21, 2018, the Company entered into a crude oil gathering agreement and option agreement with SCM. The crude oil gathering agreement (the "Gathering Agreement") enables SCM to (i) design, engineer, and construct a gathering system which will provide gathering services for the Company's crude oil under a tariff arrangement and (ii) gather the Company's crude oil on the gathering system in certain production areas located in Winkler and Loving Counties, Texas and Lea County, New Mexico. Construction of the gathering system has commenced and is expected to be completed during the first quarter of 2020. The Gathering Agreement has a term of 12 years that automatically renews on a year to year basis until terminated by either party.

SCM and the Company also entered into an option agreement (the "Option Agreement") whereby the Company granted an option to SCM to provide certain midstream services related to natural gas in Winkler and Loving Counties, Texas and Lea County, New Mexico, subject to the expiration and terms of the Company's existing gas agreement. The Option Agreement has a term commencing May 21, 2018 and terminating January 1, 2027, pursuant to its one-time option. As consideration for this option, the Company received a one-time payment of $35.0 million, which was recorded in long-term deferred revenue.

Asset Disposition Accounted for as a Financing Arrangement

As a result of certain repurchase rights, as discussed more fully in Note 6 - Acquisitions and Divestitures, the agreements with WLR and WLWI do not meet the criteria for a sale and are accounted for as a financing arrangement under ASC 470. The net proceeds of the transaction of $39.0 million are included in long-term deferred revenue and other long-term liabilities on the Company's condensed consolidated balance sheet as of September 30, 2019. As a result of the transaction, the net revenue payments of $0.1 million for the three and nine months ended September 30, 2019 are included in interest expense on the Company's condensed consolidated statements of operations (see Note 6 - Acquisitions and Divestitures).

NOTE 13 - RELATED PARTY TRANSACTIONS

During the nine months ended September 30, 2019 and 2018, the Company was engaged in the following transactions with certain related parties:



		As of September 30,
Related Party	Transactions	2019			2018
		(In thousands)
Directors and Officers:
Ronald D. Ormand (Former Chief Executive Officer)	Receivable for tax withholding on vested restricted shares. Additional Shares were canceled to cover this tax withholding	$	—		$	441
Värde Partners, Inc. (1)	The Company acquired oil and natural gas interests from VPD, an affiliate of Värde	—			10,705
	Receivable balance outstanding as of September 30, 2019 for operating costs associated with VPD's producing wells	200			—
	Payable to WLR for net proportionate share of production	(242		)	—
	Asset disposition accounted for as a financing arrangement	(36,833		)	—
	Total:	$	(36,875	)	$	11,146

⁽¹⁾Värde was the lead lender in the Company's Second Lien Term Loan (see Note 11 - Long-Term Debt), is a major stockholder of the Company, and also participated in various transactions in 2018 and during the nine months ended September 30, 2019 (which such transactions included the issuance of preferred stock to Värde Parties) (see Note 14 - Preferred Stock).

Additionally, on March 5, 2019, pursuant to the 2019 Transaction Agreement and the related payoff letter, the Company agreed to issue to the Värde Parties shares of two new series of its preferred stock and shares of its common stock, as consideration for the termination of the Second Lien Credit Agreement with the Värde Parties and the satisfaction in full, in lieu of repayment in cash, of the Second Lien Term Loan under the Second Lien Credit Agreement. See Note 11 - Long-Term Debt and Note 14 - Preferred Stock for additional information.

On July 31, 2019, the Company entered into two agreements with affiliates of Värde for the sale of an overriding royalty interest and a non-operated working interest in undeveloped assets. See Note 6 - Acquisitions and Divestitures for additional information.

On August 16, 2019, the company entered into an agreement with an affiliate of Värde to repurchase the overriding royalty interest for the New Mexico acreage sold. See Note 6 - Acquisitions and Divestitures for additional information.

NOTE 14 - PREFERRED STOCK

Preferred Stock Issuances

On January 30, 2018, the Company entered into a Securities Purchase Agreement by and among the Company and the Värde Parties, pursuant to which, on January 31, 2018, the Company issued and sold to the Värde Parties 100,000 shares of a newly created series of preferred stock of the Company, designated as "Series C 9.75% Convertible Participating Preferred Stock" for a purchase price of $1,000 per share, or an aggregate of $100.0 million. The Series C 9.75% Convertible Participating Preferred Stock was subsequently re-designated as "Series C-1 9.75% Convertible Participating Preferred Stock" in connection with the transactions contemplated by the 2018 Transaction Agreement (as defined in Note 11 - Long-Term Debt) and as "Series C-1 9.75% Participating Preferred Stock" in connection with the transactions contemplated by the 2019 Transaction Agreement (as defined in Note 11 - Long-Term Debt) (as re-designated, the "Series C-1 Preferred Stock").

Pursuant to the 2018 Transaction Agreement, on October 10, 2018, the Company issued and sold to the Värde Parties 25,000 shares of a newly created series of the Company's preferred stock designated as "Series C-2 9.75% Convertible Participating Preferred Stock" for a purchase price of $1,000 per share, or an aggregate of $25.0 million. The Series C-2 9.75% Convertible Participating Preferred Stock was subsequently re-designated as "Series C-2 9.75% Participating Preferred Stock" in connection

with the transactions contemplated by the 2019 Transaction Agreement (as re-designated, the "Series C-2 Preferred Stock" and, together with the Series C-1 Preferred Stock, the "Series C Preferred Stock"). Also pursuant to the 2018 Transaction Agreement, on October 10, 2018, the Company issued to the Värde Parties 39,254 shares of its Series D 8.25% Convertible Participating Preferred Stock. The Series D 8.25% Convertible Participating Preferred Stock was subsequently re-designated as "Series D 8.25% Participating Preferred Stock" in connection with the transactions contemplated by the 2019 Transaction Agreement (as re-designated, the "Series D Preferred Stock").

Pursuant to the 2019 Transaction Agreement, on March 5, 2019, the Company issued to the Värde Parties (i) 60,000 shares of its Series E Preferred Stock and (ii) 55,000 shares of its Series F Preferred Stock.

Additionally, pursuant to the 2019 Transaction Agreement, on March 5, 2019, the Company issued to the Värde Parties an aggregate of 7,750,000 shares of its common stock, as consideration for the Värde Parties' consent to the amendment of the terms of the Series C Preferred Stock and the Series D Preferred Stock to, among other things, eliminate the convertibility and voting rights of the Series C Preferred Stock and the Series D Preferred Stock. As a result of the transactions effected under the 2019 Transaction Agreement, the potential dilution of the Company's common stockholders resulting from the conversion of convertible debt and convertible preferred stock was reduced from approximately 53.5 million shares of common stock (related to the Second Lien Term Loan, the Series C Preferred Stock and the Series D Preferred Stock) to approximately 24.0 million shares of common stock (related to the Series E Preferred Stock). Other than the Series E Preferred Stock, the Company has no convertible debt or convertible preferred stock outstanding following the closing of the transactions contemplated by the 2019 Transaction Agreement. The amendments to the terms of the Series C Preferred Stock also fixed the redemption price payable by the Company in connection with a redemption of the Series C Preferred Stock at price per share equal to (i) the Stated Value (as defined in the certificate of designation for the Series C Preferred Stock) multiplied by 125.0% plus (ii) accrued and unpaid dividends thereon and any other amounts payable by the Company in respect thereof. Prior to the amendments, the percentage specified in clause (i) above would have increased to 130.0% for a redemption of the Series C Preferred Stock effected after December 31, 2019.

As of September 30, 2019, the Company accounted for the Series C, D, E and F Preferred Stock at its initial fair value at closing of the 2019 Transaction Agreement, plus cumulative paid-in-kind dividends accrued subsequent to the closing of the transactions contemplated by the 2019 Transaction Agreement, under mezzanine equity in the consolidated balance sheet. The components of each series of preferred stock are summarized in the table below:



	Series C Preferred Stock				Series D Preferred Stock				Series E Preferred Stock			Series F Preferred Stock
	Number of Shares	Amount			Number of Shares	Amount			Number of Shares	Amount		Number of Shares	Amount
	(In thousands, except shares)
Balance, January 1, 2019	125,000	$	132,296		39,254	$	40,729		—	$	—	—	$	—
Change in carrying value due to modification	—	(46,633		)	—	(15,057		)	—	—		—	—
Issuance of Preferred Stock in extinguishment of debt	—	—			—	—			60,000	62,115		55,000	46,682
Paid-in-kind dividends	—	10,105			—	2,530			—	2,873		—	2,877
Balance, September 30, 2019	125,000	$	95,768		39,254	$	28,202		60,000	$	64,988	55,000	$	49,559

Description of the Series E Preferred Stock and Series F Preferred Stock

Ranking. The Series F Preferred Stock ranks senior to all of the other series of preferred stock of the Company, and the Series E Preferred Stock ranks senior to the Series D Preferred Stock and the Series C Preferred Stock, in each case with respect to dividends and rights on the liquidation, dissolution or winding up of the Company.

Stated Value. The Series E Preferred Stock and the Series F Preferred Stock have an initial per share stated value of $1,000, subject to increase in connection with the payment of dividends in kind as described below (the "Stated Value").

Dividends. Holders of the Series E Preferred Stock and Series F Preferred Stock are entitled to receive cumulative preferential dividends, payable and compounded quarterly in arrears on January 1, April 1, July 1 and October 1 of each year,

commencing April 1, 2019, at an annual rate of 8.25% of the Stated Value for the Series E Preferred Stock and at an annual rate of 9.00% of the Stated Value for the Series F Preferred Stock. However, if, on any dividend payment date occurring after April 26, 2021, dividends due on such dividend payment date on the Series E Preferred Stock or the Series F Preferred Stock are not paid in full in cash, the annual dividend rate for the dividends due on such dividend payment date (but not for any future dividend payment date on which dividends are paid in full in cash) will be 9.25% on the Series E Preferred Stock and 10.00% on the Series F Preferred Stock. Dividends are payable, at the Company's option, (i) in cash, (ii) in kind by increasing the Stated Value by the amount per share of the dividend or (iii) in a combination thereof.

In addition to these cumulative preferential dividends, holders of the Series E Preferred Stock and Series F Preferred Stock are entitled to participate in dividends paid on the Company's common stock. For holders of the Series E Preferred Stock, such participation will be based on the number of shares of common stock such holders would have owned if all shares of Series E Preferred Stock had been converted to common stock at the Conversion Rate (as defined below) then in effect. For holders of the Series F Preferred Stock, such participation will be based on the dividends such holders would have received if, immediately prior to the applicable record date, each outstanding share of Series F Preferred Stock had been converted into a number of shares of common stock equal to the Series F Optional Redemption Price (as defined below) divided by $7.00, subject to proportionate adjustment in connection with stock splits and combinations, dividends paid in stock and similar events affecting the outstanding common stock (regardless of the fact that shares of the Series F Preferred Stock are not convertible into common stock).

Optional Redemption. Subject to the limitations described below and certain additional limitations on partial redemptions, the Company has the right to redeem the Series E Preferred Stock, in whole or in part, at a price per share equal to (i) the Stated Value then in effect multiplied by (A) 110% if the optional redemption date occurs on or prior to March 5, 2020, (B) 105% if the optional redemption date occurs after March 5, 2020 and on or prior to March 5, 2021 and (C) 100% if the optional redemption date occurs after March 5, 2021, plus (ii) accrued and unpaid dividends thereon and any other amounts payable by the Company in respect thereof (the "Series E Optional Redemption Price"). However, for any optional redemption effected in connection with or following a Change of Control (as defined in the Series E Certificate of Designation) or any mandatory redemption in connection with a Change of Control as described below, the Series E Optional Redemption Price will be calculated under clause (C) above, regardless of when the redemption or Change of Control occurs.

Except in the case of a Change of Control Redemption (as defined in the Series E Certificate of Designation), the Company may not effect an optional redemption of the Series E Preferred Stock unless:


•	either (i) as of the optional redemption date, there are no shares of the Series F Preferred Stock outstanding or (ii) all outstanding shares of the Series F Preferred Stock are redeemed on such optional redemption date concurrently with such optional redemption of the Series E Preferred Stock in accordance with the terms of the Series F Certificate of Designation;


•	the aggregate Series E Optional Redemption Price for all shares of the Series E Preferred Stock to be redeemed pursuant to such optional redemption shall not exceed the aggregate amount of net cash proceeds received by the Company from a contemporaneous issuance of common stock issued for the purpose of redeeming such shares of Series E Preferred Stock; and

•

if the optional redemption date occurs prior to March 5, 2022, then (i) the VWAP for at least 20 trading days during the 30 trading day period immediately preceding the notice of the optional redemption has been at least 150% of the Conversion Price (as defined below) then in effect, and (ii) such optional redemption shall be for all (but not less than all) then-outstanding shares of Series E Preferred Stock.

The Series E Preferred Stock is not redeemable at the option of the holders except in connection with a Change of Control as described below and is perpetual unless converted or redeemed in accordance with the Series E Certificate of Designation.

The Company has the right to redeem the Series F Preferred Stock, in whole or in part (subject to certain limitations on partial redemptions), at a price per share equal to (i) the Stated Value then in effect, multiplied by 115.0%, plus (ii) accrued and unpaid dividends thereon and any other amounts payable by the Company in respect thereof (the "Series F Optional Redemption Price").

The Series F Preferred Stock is not redeemable at the option of the holders except in connection with a Change of Control as described below and is perpetual unless converted or redeemed in accordance with the Series F Certificate of Designation.

Conversion. Each share of the Series E Preferred Stock is convertible at any time at the option of the holder into the number of shares of common stock equal to (i) the applicable Series E Optional Redemption Price that would have been received by the holder upon the redemption of the applicable shares of Series E Preferred Stock as of the Conversion Date (as defined in the Series E Certificate of Designation) divided by (ii) the Conversion Price (as defined below) (the "Conversion Rate"). However, for purposes of determining the Conversion Rate, the Series E Optional Redemption Price will be calculated on the basis applicable

to an optional redemption occurring after March 5, 2021 (i.e., multiplying the Stated Value by 100.0%), regardless of the timing or circumstances of the conversion. The "Conversion Price" for the Series E Preferred Stock is $2.50, subject to adjustment as described below. The Conversion Price will be subject to proportionate adjustment in connection with stock splits and combinations, dividends paid in stock and similar events affecting the outstanding common stock. Additionally, the Conversion Price will be adjusted, based on a broad-based weighted average formula, if the Company issues, or is deemed to issue, additional shares of common stock for consideration per share that is less than the Conversion Price then in effect, subject to certain exceptions and to the Share Cap (as defined below).

To comply with the rules of the NYSE American, the Series E Certificate of Designation provides that the number of shares of common stock issuable on conversion of a share of Series E Preferred Stock may not exceed the Stated Value divided by $1.88 (which was the closing price of the common stock on the NYSE American on March 4, 2019) (the "Share Cap"), subject to proportionate adjustment in connection with stock splits and combinations, dividends paid in stock and similar events affecting the outstanding common stock (such price, as so adjusted, the "Initial Market Price"), prior to the receipt of stockholder approval of the issuance of shares of common stock in excess of the Share Cap upon conversion of shares of Series E Preferred Stock. The 2019 Transaction Agreement requires the Company to seek such shareholder approval at its next annual meeting of shareholders. Accordingly, the Company received shareholder approval at its 2019 annual meeting of shareholders held on May 20, 2019.

The Company does not have the right to force the conversion of shares of the Series E Preferred Stock based on the trading price of the common stock or otherwise.

The Series F Preferred Stock is not convertible into common stock.

Change of Control. Upon the occurrence of a Change of Control (as defined in the Series E Certificate of Designation and the Series F Certificate of Designation), each holder of shares of the Series E Preferred Stock and Series F Preferred Stock will have the option to: (i) cause the Company to redeem all of such holder's shares of Series E Preferred Stock or Series F Preferred Stock for cash in an amount per share equal to the applicable Optional Redemption Price; (ii) in the case of the Series E Preferred Stock, convert all of such holder's shares of Series E Preferred Stock into common stock at the Conversion Rate; or (iii) continue to hold such holder's shares of Series E Preferred Stock or Series F Preferred Stock, subject to the Company's or its successor's optional redemption rights described above and, in the case of the Series E Preferred Stock, subject to any adjustments to the Conversion Price or the number and kind of securities or other property issuable upon conversion resulting from the Change of Control.

Liquidation Preference. Upon any liquidation, dissolution or winding up of the Company, holders of shares of Series F Preferred Stock will be entitled to receive, prior to any distributions on the Series E Preferred Stock, the Series D Preferred Stock, the Series C Preferred Stock, the common stock or other capital stock of the Company ranking junior to the Series F Preferred Stock, an amount per share equal to the greater of (i) the Series F Optional Redemption Price then in effect and (ii) the proceeds the holders of Series F Preferred Stock would be entitled to receive if, immediately prior to the payment of such amount, each then-outstanding share of the Series F Preferred Stock had been converted into a number of shares of common stock equal to the Series F Optional Redemption Price divided by the Participation Price (as defined in the certificate of designation for the Series F Preferred Stock), regardless of the fact that shares of the Series F Preferred Stock are not convertible into common stock.

Upon any liquidation, dissolution or winding up of the Company, holders of shares of Series E Preferred Stock will be entitled to receive, after any distributions on the Series F Preferred Stock and prior to any distributions on the Series D Preferred Stock, the Series C Preferred Stock, the common stock or other capital stock of the Company ranking junior to the Series E Preferred Stock, an amount per share of Series E Preferred Stock equal to the greater of (i) the Series E Optional Redemption Price then in effect and (ii) the amount such holder would receive in respect of the number of shares of common stock into which such share of Series E Preferred Stock is then convertible.

Board Designation Rights. The Series E Certificate of Designation provides that holders of the Series E Preferred Stock have the right, voting separately as a class, to designate one member of the Board for as long as the shares of common stock issuable on conversion of the outstanding shares of Series E Preferred Stock represent at least 5% of the outstanding shares of common stock (giving effect to conversion of all outstanding shares of the Series E Preferred Stock).

The Series F Certificate of Designation provides that holders of the Series F Preferred Stock have the right, voting separately as a class, to designate one member of the Board for as long as the aggregate Stated Value of all outstanding shares of the Series F Preferred Stock is at least equal to $13.8 million.

Voting Rights. In addition to the Board designation rights described above, holders of Series E Preferred Stock are entitled to vote with the holders of the common stock, as a single class, on all matters submitted for a vote of holders of the common stock.

When voting together with the common stock, each share of Series E Preferred Stock will entitle the holder to a number of votes equal to the applicable Stated Value as of the applicable record date or other determination date divided by the greater of (i) the then-applicable Conversion Price and (ii) the then-applicable Initial Market Price.

Holders of shares of Series F Preferred Stock are not entitled to vote with the holders of the common stock as a single class on any matter.

Negative Covenants. The Series E Certificate of Designation and Series F Certificate of Designation contain customary negative covenants.

Transfer Restrictions. Shares of Series E Preferred Stock and Series F Preferred Stock and shares of common stock issued on conversion of shares of Series E Preferred Stock may not be transferred by the holder of such shares, other than to an affiliate of such holder, prior to September 5, 2019. After September 5, 2019, such shares will be freely transferable, subject to applicable securities laws.

NOTE 15 - STOCKHOLDERS' EQUITY

Issuance of Common Stock

On March 5, 2019, pursuant to the 2019 Transaction Agreement, as (i) partial consideration for the satisfaction in full of the Second Lien Term Loan as discussed in Note 11 - Long-Term Debt and (ii) consideration for the amendment of the terms of the Series C Preferred Stock and the Series D Preferred Stock as discussed in Note 14 - Preferred Stock, the Company issued an aggregate of 17,641,638 shares of the Company's common stock, par value $0.0001 per share.

Warrants

The following table provides a summary of the Company's warrant activity for the nine months ended September 30, 2019:



	Warrants		Weighted- Average Exercise Price
Outstanding at January 1, 2019	5,017,329		$	3.83
Forfeited or expired	(2,263,267	)	$	2.81
Outstanding at September 30, 2019	2,754,062		$	4.67

NOTE 16 - SHARE BASED AND OTHER COMPENSATION

For the nine months ended September 30, 2019 and 2018, the Company's share-based compensation consisted of the following (dollars in thousands):



	Nine Months Ended September 30, 2019						Nine Months Ended September 30, 2018
	Stock Options		Restricted Stock		Total		Stock Options		Restricted Stock		Total
Share based compensation expensed	$	290	$	6,043	$	6,333	$	1,796	$	5,858	$	7,654
Unrecognized share-based compensation costs	$	130	$	1,444	$	1,574	$	970	$	5,069	$	6,039
Weighted average amortization period remaining (in years)	1.64		1.27				0.44		0.50

Restricted Stock

A summary of restricted stock grant activity pursuant to the Lilis 2012 Omnibus Incentive Plan (the "2012 Plan") and the 2016 Omnibus Incentive Plan (the "2016 Plan") for the nine months ended September 30, 2019, is presented below:



	Number of Shares		Weighted Average Grant Date Price
Outstanding at January 1, 2019	953,584		$	4.85
Granted	3,731,550		$	1.47
Vested and issued	(2,362,533	)	$	2.13
Forfeited or canceled ⁽¹⁾	(749,477	)	$	2.75
Outstanding at September 30, 2019	1,573,124		$	1.90

⁽¹⁾ Forfeitures are accounted for as and when incurred.

Stock Options

A summary of stock option activity pursuant to the 2016 Plan for the nine months ended September 30, 2019, 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, 2019	5,031,578		$	3.81	5,035,317	7.9
Granted	135,000		$	2.17
Exercised	—		$	—
Forfeited or canceled ⁽¹⁾	(938,528	)	$	2.37
Outstanding at September 30, 2019	4,228,050		$	4.08	4,125,842	7.2

⁽¹⁾ Forfeitures are accounted for as and when incurred.

During the nine months ended September 30, 2019, options to purchase 135,000 shares of the Company's common stock were granted under the 2016 Plan. The weighted average fair value of these options was $1.47 utilizing the weighted average expected term of 10 years, expected volatility of 30%, no expected dividends, and risk-free interest rate of 2.67%.

NOTE 17 - INCOME (LOSS) PER COMMON SHARE

The following table shows the computation of basic and diluted net loss per share for the three and nine months ended September 30, 2019 and 2018 (in thousands):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Net income (loss)	$	(20,409	)	$	(2,856	)	$	(45,371	)	$	(21,818	)
Dividends on preferred stock	(7,185		)	(2,410		)	(18,385		)	(6,527		)
Unallocated net income (loss)	$	(27,594	)	$	(5,266	)	$	(63,756	)	$	(28,345	)

Numerator for basic earnings (loss) per share:
Net income (loss) attributable to common stockholders	$	(27,594	)	$	(5,266	)	$	(63,756	)	$	(28,345	)

Denominator for basic loss per share:
Basic weighted average common shares outstanding	91,349,994			64,572,104			86,734,449			60,082,902

Net loss per share:
Basic attributable to common stockholders	$	(0.30	)	$	(0.08	)	$	(0.74	)	$	(0.47	)

Numerator for diluted loss per share:
Net income (loss) attributable to common stockholders	$	(27,594	)	$	(5,266	)	$	(63,756	)	$	(28,345	)
Add: interest expense on convertible Second Lien Term Loan	—			7,499			—			—
Less: gain on fair value change of embedded derivatives associated with Second Lien Term Loan	—			(10,612		)	—			—
Net loss attributable to common stockholders	$	(27,594	)	$	(8,379	)	$	(63,756	)	$	(28,345	)

Denominator for diluted net loss per share:
Basic weighted average common shares outstanding	91,349,994			64,572,104			86,734,449			60,082,902
Dilution effect of if-converted Second Lien Term Loan	—			24,137,977			—			—
Diluted weighted average common shares outstanding	91,349,994			88,710,081			86,734,449			60,082,902

Net loss per share - diluted:
Common shares (diluted)	$	(0.30	)	$	(0.09	)	$	(0.74	)	$	(0.47	)

The Company excluded the following shares from the diluted loss per share calculations above because they were anti-dilutive at September 30, 2019 and 2018:



	September 30,
	2019	2018
Stock Options	4,228,050	5,099,450
Series C Preferred Stock	—	20,807,726
Stock Purchase Warrants	2,754,062	5,137,329
Series E Preferred Stock	25,149,169	—
Conversion of term loans	—	24,143,977
	32,131,281	55,188,482

NOTE 18 - SUPPLEMENTAL NON-CASH TRANSACTIONS

The following table presents the supplemental disclosure of cash flow information for the nine months ended September 30, 2019 and 2018:



	Nine Months Ended September 30,
	2019		2018
	(in thousands)
Non-cash investing and financing activities excluded from the statement of cash flows:
Issued shares of common stock and preferred stock upon extinguishment of debt and modification of Series C Preferred Stock and Series D Preferred Stock	$	141,787	$	—
Common stock issued for acquisition of oil and gas properties	—		24,778
Cashless exercise of warrants	—		356
Deferred revenue realized upon purchase option exercise	11,700		—
Change in capital expenditures for drilling costs in accrued liabilities	7,871		17,313
Accrued cumulative paid in kind dividends on preferred stock	18,385		6,527
Change in asset retirement obligations	32		380

NOTE 19 - SEGMENT INFORMATION

Operating segments are defined as components of an entity that engage in activities from which it may earn revenues and incur expenses for which separate operational financial information is available and are regularly evaluated by the chief operating decision maker for the purposes of allocating resources and assessing performance. The Company currently has only one reportable operating segment, which is oil and gas development, exploration and production, for which the Company has a single management team that allocates capital resources to maximize profitability and measures financial performance as a single entity.

NOTE 20 - COMMITMENTS AND CONTINGENCIES

Firm Oil Takeaway and Pricing Agreement

On August 2, 2018, the Company executed a five-year agreement with SCM Crude, LLC, an affiliate of SCM, to secure firm takeaway pipeline capacity and pricing on a long-haul pipeline to the Gulf Coast region commencing July 1, 2019. On March 11, 2019, the agreement was replaced with a 5-year agreement between the Company and ARM, a related company to SCM. The new agreement accelerated the start date to March 2019 and guarantees firm takeaway capacity on a long-haul pipeline to Corpus Christi, Texas, once completed, at a specified price. Under the terms of the new contract, the Company received more favorable pricing differentials on the crude oil sales contract and the minimum quantities of crude oil required were modified as follows:



Date	Quantity (Barrels per Day)
March 2019 - June 2019	5,000
July 2019 - December 2019	4,000
January 2020 - June 2020	5,000
July 2020 - June 2021	6,000
July 2021 - December 2024 ⁽¹⁾	7,500

⁽¹⁾ Extending to the later of December 2024 or 5 years from the EPIC Crude Oil pipeline in-service date (no later than June 2025).

During the three month period ended September 30, 2019, the Company did not meet its required minimum quantity commitment under the contract due to a temporary production outage. The purchaser declined to enforce any make whole provisions and production has been restored.

Further, ARM has agreed to purchase crude from the Company based upon Magellan East Houston pricing with a fixed "differential basis," providing price relief versus current market conditions.

Environmental and Governmental Regulation

As of September 30, 2019, there were no known environmental or regulatory matters which are reasonably expected to result in a material liability to the Company. Many aspects of the oil and natural gas industry are extensively regulated by federal, state, and local governments and regulatory agencies in all areas in which the Company has operations. Regulations govern such things as drilling permits, environmental protection and air emissions/pollution control, spacing of wells, the unitization and pooling of properties, reports concerning operations, land use, taxation, and various other matters. Oil and natural gas industry legislation and administrative regulations are periodically changed for a variety of political, economic, and other reasons. As of September 30, 2019, the Company had not been fined or cited for any violations of governmental regulations that would have a material adverse effect on the financial condition of the Company.

Legal Proceedings

The Company may from time to time be involved in various legal actions arising in the ordinary course of business. In the opinion of management, the Company's liability, if any, in these pending actions would not have a material adverse effect on the financial position of the Company. The Company's general and administrative expenses would include amounts incurred to resolve claims made against the Company.

The Company believes there is no litigation pending that could have, individually or in the aggregate, a material adverse effect on its results of operations or financial condition.

NOTE 21 - SUBSEQUENT EVENTS

Fourth Amendment to Revolving Credit Agreement

On November 5, 2019, the Company entered into a Fourth Amendment (the "Fourth Amendment") to the Revolving Credit Agreement (as defined in Note 11 - Long-Term Debt), pursuant to which the requisite lenders under the Revolving Credit Agreement waived compliance by the Company with the Leverage Ratio covenant (as defined and described in Note 11 - Long-Term Debt) as of September 30, 2019 in exchange for a customary fee. Additionally, the Fourth Amendment modified the manner in which EBITDAX is calculated for the periods ending December 31, 2019, March 31, 2020 and June 30, 2020 such that EBITDAX is calculated on an annualized basis for those periods, excluding quarterly periods ended prior to December 31, 2019. The Fourth Amendment also (1) requires the Company to use 100% of net cash proceeds from dispositions to repay borrowings until completion of the scheduled November 1, 2019 redetermination or during a borrowing base deficiency, (2) added completion of the scheduled November 1, 2019 redetermination as a condition precedent to future borrowings and (3) limits certain exceptions to certain of the negative covenants under the Revolving Credit Agreement during the period from the date of the Fourth Amendment to the date on which annual financial statements for the fiscal year ending December 31, 2019 are delivered.

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, as well as the unaudited 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 Item "1A. Risk Factors." in our Annual Report.

Overview

We are a Permian Basin focused company engaged in the exploration, production, development, and acquisition of oil, natural gas, and NGLs, with all of our properties and operations in the Delaware Basin. Our focus is on the production of crude oil and NGLs ("Liquids"). In each of the past two years, over 90% of our revenues have been generated from the sale of Liquids. We have a largely contiguous acreage position with significant stacked-pay potential, which we believe includes at least five to seven productive zones and approximately 1,000 future drilling locations.

Our focus is on growing our Company and increasing value to our stockholders by generating cash flow from our existing acreage base, as well as through delineation of our acreage and future acquisitions, acreage exchanges and organic leasing.

We have focused on reducing our cash spending since the second quarter of 2019 and realized significant improvements in drill cycle times, which resulted in material per-well drilling AFE savings. While we intend to continue to drill and complete wells on our properties, we have recently temporarily suspended drilling and completion operations in the fourth quarter in order to focus on field level facility upgrades and the evaluation of our most recent completions. We expect to resume our drilling and completion program in the first quarter of 2020, but the timing and scope of our plan are subject to our reevaluation of our liquidity sources for drilling and completion capital, as described in more detail below under "Capital Resources and Liquidity."

Third Quarter 2019 Operational and Financial Highlights


•	Significantly reduced cycle times under the Company's new operations team by reducing average drilling days for longer lateral wells from approximately 45 days (spud to total depth) to approximately 17 days


•	Achieved reduced drilling cycle times by incorporating oil-based drilling mud, a higher quality rig and better down hole tools/configurations


•	Achieved combined cost savings of over $4.3 million on the Grizzly A #2H, the Grizzly B #2H, and the East Shammo #3H wells due to reduced drilling days and drilling costs


•	Drilled the fastest well by the Company to date, the East Shammo #3H, at 15 days spud to total depth of 20,715 feet


•	Improved in-zone precision during drilling from approximately 89% in 2018 to approximately 100% in recent wells


•	Successfully completed both the Kudu A #2H and the Kudu B #2H under completion AFE cost estimates, and both wells are currently on flowback


•	Deployed our operations team with extensive Northern Delaware Basin experience, which has taken measures to standardize completion methods and adopt the latest techniques in-line with offset operators


•	Received 2-year extended flaring permits to mitigate the need for future shut-ins associated with regulatory flaring compliance and successfully brought all four previously shut-in wells back online and flowing to sales


•	Implemented solutions for delivering all produced natural gas to sales by year-end


•	Currently have 24 drilling permits in various stages of submittal and review with the Bureau of Land Management in New Mexico and expect to have multiple permits approved by year-end


•	Completed two significant transactions that brought approximately $56 million of capital into the Company


•	Sold 513 net undeveloped acres in New Mexico, noncontiguous to the Company's core operational area, for approximately $33,000 per net acre


•	Completed an overriding royalty interest and working interest transaction


•	Achieved significant general and administrative expenses savings by completing the closing of the Houston and San Antonio offices, consolidating all operations to a single location in Fort Worth, and reducing full-time equivalent employees (corporate, operations and field personnel) by approximately 28%


•	Realized oil pricing of 96% of WTI for the quarter, versus 93% of WTI in the second quarter of 2019


•	Achieved commodity volume mix of 66% Liquids, including 53% crude oil, resulting in 94% of revenue attributable to liquids sales during the third quarter

Results of Operations – For the Three and Nine Months Ended September 30, 2019 and 2018

Current Operations Update

During the nine months ended September 30, 2019, four horizontal wells were placed on production. As of September 30, 2019, we have 41 gross operated wells, of which 28 horizontal wells and 13 legacy vertical wells were producing and flowing to sales. We are nearing completion on several New Mexico permits, which are currently included in our 2020 drill plan.

To enhance performance, the Company is installing artificial lift on select wells. Currently, eleven wells have been placed on artificial lift, with additional wells targeted during the fourth quarter.

In July, we self-elected to temporarily shut-in four of our wells to remain within Texas flaring regulations. By the end of the third quarter, we brought all four of those previously shut-in wells back online and flowing to sales, received extended flaring permits in Texas to mitigate the need for future shut-ins due to regulatory compliance, and continue to advance efforts with the implementation of field treating solutions. The treating systems involve chemical intervention, upgrades to the surface facilities at each tank battery and upgrades to natural gas handling facilities for specific wells that do not meet quality specifications. The crude oil treating implementation is expected to be complete by the end of November, and the natural gas treating solution continues to be advanced with the intention of being in a position to deliver all natural gas that is currently being flared to sales by year-end.

Effective March 1, 2019, the Company began selling its crude oil under a single long-term contract with a term that extends to at least December 31, 2024. The purchaser's commitment has a quantity-based limit set forth in the contract, measured in barrels per day, with the maximum quantity commitment increasing at periodic intervals over the life of the contract to coincide with the Company's expected growth in production. Pursuant to the long-term contract, pricing is based on posted indexes for crude oil of similar quality, with a differential based on pipeline delivery to Houston.

In May 2018, we engaged SCM to implement a gathering system to transport our crude oil production. The initial system is not yet fully in service, but we anticipate commissioning with a majority of our crude oil flowing through the gathering system in the fourth quarter of 2019.

Oil, Natural Gas and NGL Sales

The following table sets forth selected revenue and sales volume data for the three months ended September 30, 2019 and 2018:



	Three Months Ended September 30,
	2019		2018		Variance			%
Net sales volume:
Oil (Bbl)	188,913		302,448		(113,535		)	(38	)%
Natural gas (Mcf)	716,197		856,865		(140,668		)	(16	)%
NGL (Bbl)	47,225		68,844		(21,619		)	(31	)%
Total (BOE)	355,504		514,102		(158,598		)	(31	)%
Average daily sales volume (BOE/d)	3,864		5,588		(1,724		)	(31	)%
Average realized sales price:
Oil ($/Bbl)	$	54.03	$	52.82	$	1.20		2	%
Natural gas ($/Mcf)	0.97		1.79		(0.83		)	(46	)%
NGL ($/Bbl)	14.76		28.59		(13.83		)	(48	)%
Total ($/BOE)	$	32.62	$	37.90	$	(5.27	)	(14	)%
Oil, natural gas and NGL revenues (in thousands):
Oil revenue	$	10,206	$	15,976	$	(5,770	)	(36	)%
Natural gas revenue	694		1,538		(844		)	(55	)%
NGL revenue	697		1,968		(1,271		)	(65	)%
Total revenue	$	11,597	$	19,482	$	(7,885	)	(40	)%

Sales Volumes and Revenues

Total sales volume decreased 31% to 355,504 BOE during the three months ended September 30, 2019, compared to 514,102 BOE during the same period in 2018, a decrease of 158,598 BOE. The decrease in total sales volume primarily resulted from voluntarily shutting-in additional wells (excluding wells shut-in during the third quarter for flaring compliance) related to upgrading surface facilities for natural gas and crude oil treating. These upgrades are intended to allow deliveries of all production into our third-party midstream providers' gathering systems.

Total revenue decreased $7.9 million to $11.6 million for the three months ended September 30, 2019, as compared to $19.5 million for the three months ended September 30, 2018, representing a 40% decrease, which was primarily the result of decreased sales volume. Lower realized prices for oil, natural gas, and NGLs also contributed to decreased revenue for the three-month period ended September 30, 2019 as compared to the three-month period ended September 30, 2018.

The following table sets forth selected revenue and sales volume data for the nine months ended September 30, 2019 and 2018:



	Nine Months Ended September 30,
	2019		2018		Variance			%
Net sales volume:
Oil (Bbl)	863,758		749,659		114,099			15	%
Natural gas (Mcf)	2,558,714		2,017,509		541,205			27	%
NGL (Bbl)	187,574		177,331		10,243			6	%
Total (BOE)	1,477,785		1,263,241		214,544			17	%
Average daily sales volume (BOE/d)	5,413		4,627		786			17	%
Average realized sales price:
Oil ($/Bbl)	$	51.97	$	57.12	$	(5.15	)	(9	)%
Natural gas ($/Mcf)	1.00		1.77		(0.77		)	(43	)%
NGL ($/Bbl)	18.17		28.02		(9.84		)	(35	)%
Total ($/BOE)	$	34.42	$	40.66	$	(6.24	)	(15	)%
Oil, natural gas and NGL revenues (in thousands):
Oil revenue	$	44,890	$	42,819	$	2,071		5	%
Natural gas revenue	2,570		3,572		(1,002		)	(28	)%
NGL revenue	3,408		4,969		(1,561		)	(31	)%
Total revenue	$	50,868	$	51,360	$	(492	)	(1	)%

Sales Volumes and Revenues

Total sales volume increased 17% to 1,477,785 BOE during the nine months ended September 30, 2019, compared to 1,263,241 BOE during the same period in 2018, an increase of 214,544 BOE. The increase in total sales volume was primarily due to six additional wells placed on production since the third quarter of 2018. Total revenue decreased $0.5 million to $50.9 million for the nine months ended September 30, 2019, as compared to $51.4 million for the nine months ended September 30, 2018, representing a 1% decrease. The decrease is primarily attributable to lower realized prices, which is partially offset by increased volumes.

Operating Expenses

The following table shows a comparison of operating expenses for the three months ended September 30, 2019 and 2018:



	Three Months Ended September 30,
	2019		2018		Variance			%
Operating Expenses per BOE:
Production costs	$	11.94	$	6.19	$	5.75		93	%
Gathering, processing and transportation	2.65		1.87		0.78			42	%
Production taxes	1.53		2.01		(0.48		)	(24	)%
General and administrative	13.65		13.30		0.35			3	%
Depreciation, depletion, amortization and accretion	15.25		13.95		1.30			9	%
Impairment of oil and gas properties	46.64		—		46.64			100	%
Total operating expenses per BOE	$	91.66	$	37.32	$	54.34		146	%

Operating Expenses (in thousands):
Production costs	$	4,243	$	3,184	$	1,059		33	%
Gathering, processing and transportation	942		963		(21		)	(2	)%
Production taxes	543		1,034		(491		)	(47	)%
General and administrative	4,852		6,838		(1,986		)	(29	)%
Depreciation, depletion, amortization and accretion	5,420		7,172		(1,752		)	(24	)%
Impairment of oil and gas properties	16,580		—		16,580			100	%
Total operating expenses	$	32,580	$	19,191	$	13,389		70	%

Production Costs

Production costs increased by $1.1 million, or 33%, to $4.2 million for the three months ended September 30, 2019, compared to $3.2 million for the three months ended September 30, 2018, primarily due to an increase in the number of producing wells. Our production costs on a per BOE basis increased by $5.75, or 93%, from $6.19 per BOE for the three months ended September 30, 2018, to $11.94 for the three months ended September 30, 2019. The increase in production costs per BOE is primarily associated with the decrease in sales volumes due to voluntarily shutting-in additional wells to begin the testing and implementation of the natural gas and crude oil treating systems.

Gathering, Processing and Transportation

Gathering, processing and transportation costs decreased by $0.02 million to $0.9 million for the three months ended September 30, 2019, compared to $1.0 million during the same period in 2018. This cost decrease was primarily the result of lower sales volumes of natural gas. The cost on a per BOE basis increased 42% from $1.87 for the three months ended September 30, 2018, to $2.65 for the three months ended September 30, 2019, primarily attributable to higher per BOE costs under our long-term natural gas purchase contract as compared to the short-term natural gas contract in the prior year.

Production Taxes

Production taxes decreased $0.5 million to $0.5 million for the three months ended September 30, 2019, compared to $1.0 million for the same period in 2018. On a per BOE basis, production taxes decreased by 24% to $1.53 per BOE for the three months ended September 30, 2019, from $2.01 per BOE for the three months ended September 30, 2018.

General and Administrative Expenses

General and administrative expenses ("G&A") decreased by $2.0 million to $4.9 million for the three months ended September 30, 2019, as compared to $6.8 million for the same period in 2018. The decrease of $2.0 million in G&A was primarily attributable to the $1.8 million decrease in stock compensation and a $0.7 million decrease in professional services, partially offset by increased severance costs, during the third quarter of 2019.

Depreciation, Depletion, Amortization and Accretion

Depreciation, depletion and amortization ("DD&A") expense decreased by $1.8 million to $5.4 million for the three months ended September 30, 2019, compared to $7.2 million during the same period in 2018. Third quarter 2019 DD&A expense decreased due primarily to a 31% decrease in sales volumes to 355,504 BOE. Partially offsetting the volume decrease was a 9% increase in the depletion rate to $15.25 per BOE for the three months ended September 30, 2019. Our higher DD&A rate for the three months ended September 30, 2019 was primarily attributable to a 4% decrease in the oil and gas property depletable base and a larger decrease of 12% in proved reserves on a BOE basis.

Impairment of Oil and Gas Properties

The Company recorded an impairment of oil and gas properties of $16.6 million for the three months ended September 30, 2019. The net book value of the Company's oil and gas properties at September 30, 2019 exceeded the ceiling limitation calculated as required under the full cost method of accounting. The impairment was the result of lower discounted future net cash flows as reported in our September 30, 2019 proved reserves report. The significant decrease in discounted future net cash flows for September 30, 2019 as compared to the discounted future net cash flows for June 30, 2019 was primarily the result of an approximate 6% decrease in the oil and gas pricing under SEC rules used in the September 30, 2019 report as compared to June 30, 2019. Despite the significant decrease in discounted future net cash flows at September 30, 2019, the variance in proved reserves volumes was insignificant.

The following table shows a comparison of operating expenses for the nine months ended September 30, 2019 and 2018:



	Nine Months Ended September 30,
	2019		2018		Variance			%
Operating Expenses per BOE:
Production costs	$	8.71	$	7.47	$	1.24		17	%
Gathering, processing and transportation	2.27		1.82		0.45			25	%
Production taxes	1.74		2.14		(0.40		)	(19	)%
General and administrative	16.18		19.54		(3.36		)	(17	)%
Depreciation, depletion, amortization and accretion	15.40		13.91		1.49			11	%
Impairment of oil and gas properties	11.22		—		11.22			100	%
Total operating expenses per BOE	$	55.52	$	44.88	$	10.64		24	%

Operating Expenses (in thousands):
Production costs	$	12,866	$	9,431	$	3,435		36	%
Gathering, processing and transportation	3,355		2,297		1,058			46	%
Production taxes	2,568		2,705		(137		)	(5	)%
General and administrative	23,913		24,682		(769		)	(3	)%
Depreciation, depletion, amortization and accretion	22,762		17,572		5,190			30	%
Impairment of oil and gas properties	16,580		—		16,580			100	%
Total operating expenses	$	82,044	$	56,687	$	25,357		45	%

Production Costs

Production costs increased by $3.4 million, or 36%, to $12.9 million for the nine months ended September 30, 2019, compared to $9.4 million for the nine months ended September 30, 2018, primarily due to an increase in producing wells. Our production costs on a per BOE basis increased by $1.24, or 17%, to $8.71 for the nine months ended September 30, 2019, as compared to $7.47 per BOE for the nine months ended September 30, 2018. The increase in production costs per BOE is primarily the result of increased contract labor and workover charges.

Gathering, Processing and Transportation

Gathering, processing and transportation costs increased by $1.1 million to $3.4 million for the nine months ended September 30, 2019, compared to $2.3 million during the same period in 2018. This cost increase was primarily the result of higher sales volumes of natural gas. The cost on a per BOE basis increased 25% from $1.82 for the nine months ended September 30, 2018, to $2.27 for the nine months ended September 30, 2019, primarily attributable to higher per BOE costs under our long-term natural gas purchase contract as compared to the short-term natural gas contract in the comparative period.

Production Taxes

Production taxes decreased $0.1 million to $2.6 million for the nine months ended September 30, 2019, compared to $2.7 million for the same period in 2018. On a per BOE basis, production taxes decreased to $1.74 per BOE for the nine months ended September 30, 2019, a 19% decrease from the $2.14 per BOE for the nine months ended September 30, 2018, primarily due to six additional wells located in Texas that came online since September 30, 2018. Sales of production from New Mexico wells previously made up a larger proportion of total sales and are subject to higher tax rates than sales in Texas.

General and Administrative Expenses

G&A decreased by $0.8 million to $23.9 million for the nine months ended September 30, 2019, as compared to $24.7 million for the nine months ended September 30, 2018. The decrease of $0.8 million in G&A was primarily attributable to a decrease in stock-based compensation of $1.3 million, a decrease in travel expenses of $0.4 million, and a decrease in professional services of $0.5 million, offset by an increase in personnel costs of $1.4 million including severance costs and directors fees.

Depreciation, Depletion, Amortization and Accretion

DD&A expense was $22.8 million for the nine months ended September 30, 2019, compared to $17.6 million for the nine months ended September 30, 2018; an increase of $5.2 million, or 30%. DD&A expense for the nine-month 2019 period increased due to a 17% sales volume increase of 214,544 BOE to 1,477,785 BOE during the nine months ended September 30, 2019, as compared to 1,263,241 BOE during the nine months ended September 30, 2018. Our DD&A rate also increased by 11% to $15.40 per BOE during the nine months ended September 30, 2019 from $13.91 per BOE during the nine months ended September 30, 2018, primarily due to a 32% increase of proved oil and gas net book value, a 22% decrease of future development costs and a 12% decrease in total proved reserve volumes on a BOE basis.

Impairment of Oil and Gas Properties

The Company recorded an impairment of oil and gas properties of $16.6 million for the nine months ended September 30, 2019. The net book value of the Company's oil and gas properties exceeded the ceiling limitation calculated as required under the full cost method of accounting. The impairment was the result of lower discounted future net cash flows as reported in our September 30, 2019 proved reserves report. The significant decrease in discounted future net cash flows for September 30, 2019 as compared to the discounted future net cash flows for June 30, 2019 was primarily the result of an approximate 6% decrease in the oil and gas pricing used in the September 30, 2019 report as compared to June 30, 2019. Despite the significant decrease in discounted future net cash flows at September 30, 2019, the variance in proved reserves volumes was insignificant.

Other Expenses

The following table shows a comparison of other expenses for the three months ended September 30, 2019 and 2018:



	Three Months Ended September 30,
	2019			2018			Variance			%
	(In Thousands)
Other income (expense):
Gain (loss) from early extinguishment of debt	$	(1,299	)	$	—		$	(1,299	)	100	%
Gain (loss) from commodity derivatives, net	3,943			(4,811		)	8,754			(182	)%
Change in fair value of financial instruments	—			10,612			(10,612		)	(100	)%
Interest expense	(2,186		)	(8,949		)	6,763			(76	)%
Other income	116			1			115			100	%
Total other income (expenses)	$	574		$	(3,147	)	$	3,721		(118	)%

Gain (Loss) on Early Extinguishment of Debt

The Company repurchased certain overriding royalty interests in the acreage previously sold under the ORRI Agreement (as defined in Note 6 - Acquisitions and Divestitures), resulting in a $1.3 million loss on extinguishment of a portion of the financing arrangement.

Gain (Loss) from Commodity Derivatives

Gain on our commodity derivatives increased by $8.8 million during the three months ended September 30, 2019, which primarily resulted from fluctuations in the underlying commodity prices versus fixed hedge prices and the monthly settlement of the hedged instruments. During the three months ended September 30, 2019, we had unrealized net gains of $4.4 million on mark-to-market adjustments on unsettled positions, which were partially offset by net losses of $0.4 million on cash settlement and resulted in a net gain of $3.9 million. During the three months ended September 30, 2018, our net loss from commodity derivatives consisted primarily of net losses of $0.8 million on cash settlements and a loss of $4.0 million on mark-to-market adjustments on unsettled positions.

Change in Fair Value of Financial Instruments

During the three months ended September 30, 2019 and 2018, the fair value change of $10.6 million is a result of no longer having embedded derivatives as the Second Lien Credit Agreement was terminated on March 5, 2019. Refer to Note 11 - Long-Term Debt for details on the termination of the Second Lien Credit Agreement. The fair value change of $10.6 million recorded during the three months ended September 30, 2018, was primarily attributed to the decrease in the Company stock price from $5.20 per share at June 30, 2018, to $4.90 per share at September 30, 2018.

Interest Expense

Interest expense for the three months ended September 30, 2019 was $2.2 million compared to $8.9 million for the three months ended September 30, 2018. For the three months ended September 30, 2019, we incurred interest expense of $2.2 million, which included $1.7 million from the Revolving Credit Agreement (as defined in Note 11 - Long-Term Debt) and $0.4 million of amortized debt issuance costs. For the three months ended September 30, 2018, we incurred interest expense of $1.2 million for quarterly interest payments on the $50 million term loans outstanding during the period, $3.4 million of paid-in-kind ("PIK") interest, $4.1 million of amortized debt discount and $0.2 million of amortized debt issuance costs. The term loans were converted to preferred stock in March of 2019, and, as a result, there was no PIK interest or amortization of debt discount during the 2019 period.

The following table shows a comparison of other expenses for the nine months ended September 30, 2019 and 2018:



	Nine Months Ended September 30,
	2019			2018			Variance			%
	(In Thousands)
Other income (expense):
Gain (Loss) on early extinguishment of debt	$	(1,299	)	$	—		$	(1,299	)	—	%
Gain (Loss) from commodity derivatives, net	(3,733		)	(9,383		)	5,650			(60	)%
Change in fair value of financial instruments	(335		)	19,499			(19,834		)	(102	)%
Interest expense	(8,859		)	(26,609		)	17,750			(67	)%
Other income	31			2			29			1450	%
Total other income (expenses)	$	(14,195	)	$	(16,491	)	$	2,296		(14	)%

Gain (Loss) on Early Extinguishment of Debt

The Company repurchased certain overriding royalty interests in the acreage previously sold under the ORRI Agreement, resulting in a $1.3 million loss on extinguishment of a portion of the financing arrangement.

Gain (Loss) from Commodity Derivatives

Loss on our commodity derivatives decreased by $5.7 million, or 60% during the nine months ended September 30, 2019, which primarily resulted from fluctuations in the underlying commodity prices versus fixed hedge prices and the monthly settlement of the hedging instruments. During the nine months ended September 30, 2019, our net loss from commodity derivatives consisted primarily of net losses of $3.6 million on cash settlements and $0.1 million on mark-to-market adjustments on unsettled position. During the nine months ended September 30, 2018, our net loss from commodity derivatives consisted primarily of net losses of $2.1 million on cash settlements and $7.3 million on mark-to-market adjustments on unsettled position.

Change in Fair Value of Financial Instruments

The change in fair value of financial instruments is attributable to embedded derivatives associated with the conversion feature of the Second Lien Term Loan (as defined in Note 11 - Long-Term Debt). Changes in our stock price directly affect the fair value of the embedded derivative. During the period from January 1, 2019 to March 5, 2019, we recognized a loss of $0.3 million on the embedded derivative. On March 5, 2019, the embedded derivative was extinguished as part of the 2019 Transaction Agreement (as defined in Note 11 - Long-Term Debt).

Interest Expense

Interest expense for the nine months ended September 30, 2019 was $8.9 million compared to $26.6 million for the nine months ended September 30, 2018. For the nine months ended September 30, 2019, we incurred interest expense of $8.9 million, which included $4.8 million from the Revolving Credit Agreement, $1.6 million of PIK interest, $1.7 million related to amortized debt discount on our Second Lien Term Loan and $0.6 million of amortized debt issuance costs. For the nine months ended September 30, 2018, we incurred interest expense of $26.6 million, which included $3.8 million for quarterly interest payments on notes payable and term loans, $9.8 million of PIK interest, $11.9 million related to amortized debt discount on our Second Lien Term Loan and $1.1 million of amortized debt issuance costs. The term loans were converted to preferred stock in March of 2019, and, as a result, there was less paid-in-kind interest and amortization of debt discount during the 2019 period.

Capital Resources and Liquidity

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 targeted 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.

During the nine months ended September 30, 2019, liquidity was increased by $62.5 million through an increase of the borrowing base of our Revolving Credit Agreement, the receipt of a bonus payment from the water gathering and disposal agreement

with SCM Water, the ORRI Agreement and WI Agreement (as defined in Note 6 - Acquisitions and Divestitures), and the sale of a noncontiguous New Mexico asset.

From time to time, we raise capital through the sale of oil and gas properties that are not in our current drilling plans. We may enter into such sales in the future. In August 2019, we sold approximately 513 noncontiguous net acres in New Mexico for net cash proceeds of $16.6 million. The Company repurchased certain overriding royalty interests in the acreage previously sold under the ORRI Agreement for $2.6 million, resulting in net proceeds of approximately $14 million that were used for general corporate purposes and to restart drilling and completion activity during the third quarter.

During the nine months ended September 30, 2019, we improved our capital structure through the exchange and conversion of our outstanding Second Lien Term Loan with a face value of approximately $133.6 million for a combination of preferred stock and common stock, of which $60.0 million was converted into Series E Preferred Stock, $55.0 million was converted into Series F Preferred Stock, and $18.6 million was converted into common stock based on a $1.88 per share issuance price. Additionally, the conversion features and voting rights on the existing Series C Preferred Stock and Series D Preferred Stock were eliminated in exchange for the issuance of 7.75 million shares of our common stock. The net dilution to our common stockholders was decreased by approximately 12 million shares as the result of the conversion of the Second Lien Term Loan and the elimination of the conversion features on the Series C Preferred Stock and the Series D Preferred Stock.

In 2019, we have relied significantly on borrowings under our Revolving Credit Agreement to provide drilling and completion capital and for other general corporate purposes. Our ability to maintain or increase our borrowing base under our Revolving Credit Agreement is dependent on numerous factors, including our ability to add proved reserves and production, commodities prices and the lending policies of our lenders. We currently have three wells drilled and awaiting completion (referred to as "DUC" wells) and are completing several wells that will add to our current production cash flows in early 2020 and provide additional value for our borrowing base. In July 2019, we entered into the Third Amendment (as defined in Note 11 - Long-Term Debt) to the Revolving Credit Agreement, which reduced the borrowing base to $115 million from the $125 million previously in effect. Prior to the redetermination in July 2019, the borrowing base on our Revolving Credit Agreement was increased to $125 million from $108 million in March 2019, in conjunction with the exchange transaction that eliminated the Second Lien Term Loan. The Third Amendment also amended the Current Ratio covenant (as defined and described in Note 11 - Long-Term Debt) under our Revolving Credit Agreement to provide that, subject to the consummation of the Asset Sales (as defined in Note 6 - Acquisitions and Divestitures) and the required use of the proceeds, the Company's Current Ratio as of September 30, 2019, may not be less than 0.85 to 1.00, rather than 1.00 to 1.00 as required for other future measurement dates.

As of October 31, 2019, we were fully drawn against the borrowing base under our Revolving Credit Agreement, with $115 million of indebtedness outstanding under our Revolving Credit Agreement. Our next borrowing base redetermination, scheduled to occur on or about November 1, 2019, is expected to occur in mid-November 2019. If the borrowing base is reduced by the lenders in connection with this redetermination, we will be required to repay borrowings in excess of the borrowing base or eliminate the borrowing base deficiency by pledging additional oil and gas properties to secure our obligations under the Revolving Credit Agreement. Under the Revolving Credit Agreement, we have the option to effect such repayment either in full within 30 days after the redetermination or in monthly installments over a six-month period after the redetermination. We are currently considering alternative secured financing to replace the current revolving credit facility under our Revolving Credit Agreement.

As of September 30, 2019, the Company was in compliance with the Current Ratio covenant under the Revolving Credit Agreement but was not in compliance with Leverage Ratio covenant (as defined and described in Note 11 - Long-Term Debt). Pursuant to the Fourth Amendment (as defined in Note 11 - Long-Term Debt), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio covenant as of September 30, 2019. The Fourth Amendment also amended the Leverage Ratio with respect to certain future periods. The Company was not in compliance with the Leverage Ratio covenant as of September 30, 2019 due to the Company voluntarily shutting-in wells across our properties to begin testing and implementing certain natural gas and crude oil treating systems, in addition to shutting-in certain wells during the third quarter while flare permits were being extended.

future cash flows, and consequently our EBITDAX, are subject to a number of variables, including uncertainty in forecasted production volumes and commodity prices, and we may not be able to complete sales of non-core assets or access other sources of capital on acceptable terms or at all.

Information about our cash flows for the nine months ended September 30, 2019 and 2018, are presented in the following table (in thousands):



	Nine Months Ended September 30,
	2019			2018
Cash provided by (used in):
Operating activities	$	(42,385	)	$	83,679
Investing activities	(38,717		)	(190,906		)
Financing activities	64,304			114,719
Net change in cash, cash equivalents	$	(16,798	)	$	7,492

Operating Activities

For the nine months ended September 30, 2019, net cash used in operating activities was $42.4 million, compared to net cash provided by operating activities of $83.7 million in the same period in 2018. The $42.4 million used in operating activities was primarily used for payments of accounts payable.

Investing Activities

For the nine months ended September 30, 2019, net cash used in investing activities was $38.7 million, compared to $190.9 million for the same period in 2018. The $38.7 million in cash used for investing activities during the nine months ended September 30, 2019, was primarily attributable to the following:


•	approximately $55.6 million in drilling and completion costs; partially offset by


•	approximately $16.9 million in proceeds from the sale of assets.

Capital Expenditure Breakdown

During the nine months ended September 30, 2019, drilling and completion capital cost incurred was $61.8 million, comprised of $28.9 million on DUC wells and $21.6 million related to the 2019 drilling program, plus an additional $3.0 million related to the 2018 drilling program and $8.3 million for leasehold costs and other well and facility projects.

At December 31, 2018, we had six DUC wells. Although completion costs were incurred on all six DUC wells during 2019, four wells were placed on production. Four DUC wells, the Oso #1H, Haley #1H, Haley #2H, and NE Axis #2H, have been completed and placed on production in 2019.

During the third quarter and under the direction of the Company's new operations team, significant reductions in drilling days and drilling costs have been achieved. Reduced drilling cycle times were realized by incorporating oil-based drilling mud, utilizing a higher quality rig and better down hole tools/configurations. This has reduced the number of bit trips by 44% and

increased the rate of penetration by 110% over prior wells drilled in early 2019. The identification of optimal drilling zones within drilling targets has also reduced time spent slide drilling by 5%. The Company has also improved in-zone precision from approximately 89% in 2018 to approximately 100% in recent wells. In addition to these changes, continuous drilling optimization is being evaluated and implemented with different hole sizes and configurations to further reduce cycle times. The Company expects to incorporate these improved techniques on all future wells with the goal of achieving similar cost savings.



	Three Months Ended September 30,					Nine Months Ended September 30,
	2019			2018		2019		2018
Leasehold Acquisitions
Proved	$	—		$	591	$	—	$	9,382
Unproved	447			2,842		1,802		89,036
2017 Drilling & Completion Program	—			260		—		12,015
2018 Drilling & Completion Program	36			41,007		2,994		107,337
2018 Drilling & Completion Program-DUCs	(153		)	7,284		28,884		7,284
2018 Working Interest Acquisitions	—			1,258		—		1,258
2019 Drilling & Completion Program	11,837			—		21,633		—
Facilities & Other Projects	2,180			2,433		8,262		5,916
Total Capital Spending	$	14,347		$	55,675	$	63,575	$	232,228

Financing Activities

For the nine months ended September 30, 2019, net cash provided by financing activities was $64.3 million compared to cash provided by financing activities of $114.7 million during the same period in 2018. The $64.3 million in net cash provided by financing activities included $47.1 million in net proceeds from drawdowns on the Revolving Credit Agreement and $38.2 million in net proceeds from the ORRI Agreement and WI Agreement, offset by repayment of $18.0 million on the Revolving Credit Agreement.

Borrowing Base on our Revolving Credit Agreement

In July 2019, the borrowing base on our Revolving Credit Agreement was reduced to $115.0 million from $125.0 million in conjunction with the Asset Sales and the Third Amendment to the Revolving Credit Agreement. At September 30, 2019 we had borrowings of $105.0 million outstanding under out Revolving Credit Agreement and $10.0 million available. On October 10, 2019, we drew the remaining $10.0 million on our Revolving Credit Agreement. Our next borrowing base redetermination, scheduled to occur on or about November 1, 2019, is expected to occur in mid-November 2019. If the borrowing base is reduced by the lenders in connection with this redetermination, we will be required to repay borrowings in excess of the borrowing base or eliminate the borrowing base deficiency by pledging additional oil and gas properties to secure our obligations under the Revolving Credit Agreement.

Exchange and Conversion of Second Lien Term Loan and Issuance of Preferred Stock

During the first quarter of 2019, in exchange for satisfaction of the outstanding principal amount of the Second Lien Term Loan, accrued and unpaid interest thereon and the make-whole premium totaling approximately $133.6 million, we issued to the Värde Parties an aggregate of 60,000 shares of a newly created series of preferred stock of the Company, designated as "Series E 8.25% Convertible Participating Preferred Stock", corresponding to $60 million of the Second Lien Exchange Amount based on the aggregate initial Stated Value of the shares of Series E Preferred Stock; 55,000 shares of a newly created series of preferred stock of the Company, designated as "Series F 9.00% Participating Preferred Stock", corresponding to $55 million of the Second Lien Exchange Amount based on the aggregate initial Stated Value of the shares of Series F Preferred Stock; and 9,891,638 shares of common stock, corresponding to approximately $18.6 million of the Second Lien Exchange Amount, based on the $1.88 closing price of the common stock on the NYSE American on March 4, 2019.

In connection with the transaction, the Company also issued to the Värde Parties an aggregate of 7,750,000 shares of common stock as consideration for the Värde Parties' consent to the amendment of the terms of the Series C Preferred Stock and the Series D Preferred Stock to, among other things, eliminate the convertibility of the Series C Preferred Stock and Series D

Preferred Stock into shares of common stock and the voting rights of the Series C Preferred Stock and the Series D Preferred Stock.

The elimination of the Second Lien Term Loan and the elimination of the convertibility features and the voting rights of the Series C Preferred Stock and the Series D Preferred Stock significantly improved our capital structure, including:


•	Reduced our indebtedness by $133.6 million;


•	Decreased fully diluted share count by approximately 12 million shares;


•	Eliminated near-term cash service, as all series of preferred stock have PIK options;


•	Eliminated the 2021 maturity of the Second Lien Term Loan and extended the maturity of the Revolving Credit Agreement to 2023, resulting in no scheduled principal repayments required until 2023; and


•	Eliminated conversion features associated with the Second Lien Term Loan, Series C Preferred Stock, and Series D Preferred Stock and reduced Series C Preferred Stock redemption premium.

Off-Balance Sheet Arrangements

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

Commitments and Contractual Obligations

There have been no material changes in our contractual obligations during the three and nine months ended September 30, 2019.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to various market risks, including risks relating to changes in commodity prices, interest rate risk, customer credit risk and currency exchange rate risk, as discussed below.

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our oil and natural gas production. Market risk refers to the risk of loss from adverse changes in oil and natural gas prices. Realized pricing is primarily driven by the prevailing domestic price for crude oil and spot prices applicable to the region in which we produce natural gas. Historically, prices received for oil and natural gas production have been volatile and unpredictable. We expect pricing volatility to continue. The prices that we receive depend on external factors beyond our control.

During the three and nine months ended September 30, 2019, our realized prices for liquids (crude oil and NGLs) continued to show significant improvement over the lows realized in January 2019, due largely to the rise in market index prices since then. Average liquids prices softened somewhat in June 2019, but rebounded and stabilized for the three months ended September 30, 2019. Our realized oil price also continued to benefit from sales under the Company's Crude Oil Gathering Agreement with SCM, which commenced March 1, 2019. Conversely, our realized natural gas prices saw a sharp decline beginning in April 2019 due primarily to the oversupply in the market combined with industry-wide infrastructure constraints in our operating region. Natural gas pricing saw marked improvement during the three months ended September 30, 2019 and have stabilized at levels not seen since the first three months of 2019.

During the three months ended September 30, 2019, the oil prices we received ranged from a low of $52.25 per barrel to a high of $56.60 per barrel. The NGL prices we received in the period ranged from a low of $0.24 per gallon to a high of $0.46 per gallon. Natural gas prices during the period ranged from a low of $0.75 per MCF to a high of $1.32 per MCF. During the nine months ended September 30, 2019, the oil prices we received ranged from a low of $37.33 per barrel to a high of $61.66 per barrel. The NGL prices we received ranged from a low of $0.24 per gallon to a high of $0.56 per gallon. Our realized natural gas prices ranged from a low of $0.36 per MCF to a high of $1.97 per MCF.

A significant decline in the prices of oil or natural gas could have a material adverse effect on our financial condition and results of operations. In order to reduce commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil and natural gas, we may enter into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production.

The derivative contracts may include fixed-for-floating price swaps (whereby, on the settlement date, the Company will receive or pay an amount based on the difference between a pre-determined fixed price and a variable market price for a notional quantity of production), put options (whereby the Company pays a cash premium in order to establish a fixed floor price for a notional quantity of production and, on the settlement date, receives the excess, if any, of the fixed price floor over a variable market price), and costless collars (whereby, on the settlement date, the Company receives the excess, if any, of a variable market price over a fixed floor price up to a fixed ceiling price for a notional quantity of production). We do not enter into derivatives for trading or other speculative purposes. We believe that our use of derivatives and related hedging activities reduces our exposure to commodity price rate risk and does not expose us to material credit risk or any other material market risk.

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. The amount we can borrow is subject to periodic redetermination based in part on changing expectations of future prices. Lower prices may also reduce the amount of oil and natural gas that we can economically produce. We currently sell all of our oil and natural gas production under price sensitive or market price contracts.

Interest Rate Risk

As of September 30, 2019, we had $105 million outstanding under our Revolving Credit Agreement with an applicable margin that varies from 2.75% to 3.25%. In addition, holders of our shares of Preferred Stock are entitled to receive cumulative preferential dividends, payable and compounded quarterly in arrears at an average annual rate of 9.07% of the Stated Value until maturity.

Currently, we do not have any interest rate derivative contracts in place. If we incur significant debt with a risk of fluctuating interest rates in the future, we may enter into interest rate derivative contracts on a portion of our then outstanding debt to mitigate the risk of fluctuating interest rates.

Customer Credit Risk

Our principal exposure to credit risk is through receivables from the sale of our oil and natural gas production of approximately $6.9 million at September 30, 2019, and through actual and accrued receivables from our joint interest partners of approximately $16.7 million at September 30, 2019. We are subject to credit risk due to the concentration of our oil and natural gas receivables with our most significant customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. For the three months ended September 30, 2019, sales to two customers, ARM Energy Management, LLC, and Lucid Energy Delaware, LLC, accounted for approximately 89%, and 11% of our revenue, respectively. For the nine months ended September 30, 2019, sales to three customers, ARM Energy Management, LLC, Texican Crude & Hydrocarbon, LLC, and Lucid Energy Delaware, LLC, accounted for approximately, 74%, 16% and 10% of our revenue, respectively. Due to availability of other purchasers, we do not believe the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations.

Currency Exchange Rate Risk

We do not have any foreign sales and we accept payment for our commodity sales only in U.S. dollars. We are, therefore, not exposed to foreign currency exchange rate risk on these sales.

Midstream Transportation and Marketing Risk

The marketability of our production depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems, rail service, and processing facilities, in addition to competing oil and natural gas production available to third-party purchasers. We deliver our produced crude oil and natural gas through trucking, gathering systems and pipelines. The lack of availability of capacity on third-party systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of our development plans.

Although we have contractual control over the transportation of our production through firm transportation arrangements, third-party systems and facilities may be temporarily unavailable due to market conditions, mechanical issues, adverse weather conditions, work-loads, or other reasons outside of our control. Additionally, if our natural gas contains levels of hydrogen sulfide that require treatment prior to transportation, it could cause delays in the transportation and marketing of our production. In addition, if we are unable to market our production or if we have processing interruptions or capacity and infrastructure constraints associated with natural gas production, we may be required to flare natural gas, which would decrease the volumes sold from our wells, and, in certain circumstances, would require us to pay royalties on such flared natural gas. Any significant changes affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities, could delay or decrease our production, which could negatively impact our results of operations, cash flows, and financial condition.

If the trading price of our common stock fails to comply with the continued listing requirements of the NYSE American, we could face possible delisting. NYSE American delisting could materially adversely affect the market for our shares.

Our common stock is currently listed on the NYSE American and is recently trading at levels below $0.25 per share. The NYSE American will consider suspending dealings in, or delisting, securities of an issuer that does not meet its continued listing standards, including trading at prices that the NYSE American views as abnormally low. If we cannot meet the NYSE American continued listing requirements, the NYSE American may delist our common stock resulting in our common stock trading in the less liquid over-the-counter market, which could have an adverse impact on us and the liquidity and market price of our stock. The delisting of our stock from the NYSE American could result in even further reductions in our stock price, substantially limit the liquidity of our common stock, and materially adversely affect our ability to raise capital or pursue strategic restructuring, refinancing or other transactions on acceptable terms, or at all. Delisting from the NYSE American could also have other negative results, including the potential loss of confidence by vendors and employees, the loss of institutional investor interest and fewer business development opportunities. Our management is considering alternatives to ensure continued compliance with NYSE American listing standards, but there is no assurance that we will continue to maintain compliance with NYSE American continued listing standards.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), is accumulated and communicated to the issuer's management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. As required under 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(b), 13a-15(e) and 15d-15(e) of the Exchange Act). Based on this evaluation, our principal executive officer has concluded that the Company's disclosure controls and procedures were effective as of September 30, 2019.

Changes in Internal Control over Financial Reporting

There were no 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

We may be the subject of threatened or pending legal actions and contingencies in the normal course of conducting our business. We provide for costs related to these matters when a loss is probable and the amount can be reasonably estimated. The effect of the outcome of these matters on our future results of operations and liquidity cannot be predicted because any such effect depends on future results of operations and the amount or timing of the resolution of such matters. For certain types of claims, we maintain insurance coverage for personal injury and property damage, product liability and other liability coverages in amounts and with deductibles that we believe are prudent, but there can be no assurance that these coverages will be applicable or adequate to cover adverse outcomes of claims or legal proceedings against us.

Item 1A. Risk Factors

In addition to the risk factor below, please refer to Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2018.

There were no additional material changes to our risk factors during the nine months ended September 30, 2019.

Item 2. Recent Sales of Unregistered Securities; Use of Proceeds from Registered Securities

On March 5, 2019, the Company issued to the Värde Parties an aggregate of (i) 9,891,638 shares of common stock, (ii) 60,000 shares of a newly created series of preferred stock of the Company, designated as "Series E 8.25% Convertible Participating Preferred Stock," and (iii) 55,000 shares of a newly created series of preferred stock of the Company, designated as "Series F 9.00% Participating Preferred Stock," as consideration for the termination of the Second Lien Credit Agreement and the satisfaction in full, in lieu of repayment in full in cash, of $133,596,279 pursuant to the Payoff Letter (as defined in the 2019 Transaction Agreement). The Company also issued to the Värde Parties, as consideration for the amendment and restatement of the Second Amended and Restated Series C Certificate of Designation and the Amended and Restated Series D Certificate of Designation, 7,750,000 shares of the common stock. The Series E Preferred Stock is convertible into the Company's common stock, and the Series F Preferred Stock is non-convertible. The Värde Parties beneficially own more than 10% of our outstanding equity. The securities were issued in reliance upon the exemption from registration provided by Rule 506 of Regulation D of the Securities Act of 1933.

Each share of the Series E Preferred Stock is convertible at any time at the option of the holder into the number of shares of common stock equal to (i) the applicable Series E Optional Redemption Price divided by (ii) the Conversion Price (the "Conversion Rate"). However, for purposes of determining the Conversion Rate, the Series E Optional Redemption Price will be calculated on the basis applicable to an optional redemption occurring after March 5, 2021 (i.e., multiplying the Stated Value by 100.0%), regardless of the timing or circumstances of the conversion. The "Conversion Price" for the Series E Preferred Stock is $2.50, subject to adjustment as described below. The Conversion Price will be subject to proportionate adjustment in connection with stock splits and combinations, dividends paid in stock and similar events affecting the outstanding common stock. Additionally, the Conversion Price will be adjusted, based on a broad-based weighted average formula, if the Company issues, or is deemed to

issue, additional shares of common stock for consideration per share that is less than the Conversion Price then in effect, subject to certain exceptions and to the Share Cap.

On March 15, 2019, the Company filed a registration statement on Form S-3 (Registration No. 333-230343), which was subsequently amended on March 29, 2019, to register the above-referenced unregistered common stock and the common stock issuable upon conversion of the Series E Preferred Stock; however, the registration statement has not yet been declared effective by the SEC.

Item 3. Defaults Upon Senior Securities

None

Item 4. Mine Safety Disclosures

None

Item 5. Other Information

On November 5, 2019, we entered into a Fourth Amendment and Waiver to our Revolving Credit Agreement (the "Fourth Amendment"). The material terms of the Fourth Amendment are described under "Revolving Credit Agreement-Fourth Amendment and Waiver to Revolving Credit Agreement" in Note 11 - Long-Term Debt in the Notes to the Unaudited Condensed Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q. Such description is incorporated by reference in this Item 5.

Item 6. Exhibits

EXHIBIT INDEX



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 Articles of Incorporation of Recovery Energy, Inc., dated as of November 15, 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 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).
3.4	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).
3.5	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).
3.6	Certificate of Designation of Preferences, Rights and Limitations of Series C 9.75% Convertible Participating Preferred Stock, dated January 31, 2018 (incorporated herein by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K filed on February 1, 2018).
3.7	Amended and Restated Certificate of Designation of Preferences, Rights and Limitations of Series C-1 9.75% Convertible Participating Preferred Stock and Series C-2 9.75% Convertible Participating Preferred Stock, dated October 10, 2018 (incorporated herein by reference to Exhibit 3.1 of the Company's Current Report on Form 8-K filed on October 16, 2018).
3.8	Certificate of Designation of Preferences, Rights and Limitations of Series D 8.25% Convertible Participating Preferred Stock, dated October 10, 2018 (incorporated herein by reference to Exhibit 3.2 of the Company's Current Report on Form 8-K filed on October 16, 2018).
3.9	Certificate of Designation of Preferences, Rights and Limitations of Series E 8.25% Convertible Participating Preferred Stock, dated March 5, 2019 (incorporated herein by reference to Exhibit 3.9 of the Annual Report on Form 10-K filed on March 7, 2019).
3.10	Certificate of Designation of Preferences, Rights and Limitations of Series F 9.00% Participating Preferred Stock, dated March 5, 2019 (incorporated herein by reference to Exhibit 3.10 of the Annual Report on Form 10-K filed on March 7, 2019).
3.11	Second Amended and Restated Certificate of Designation of Preferences, Rights and Limitations of Series C-1 9.75% Participating Preferred Stock and Series C-2 9.75% Participating Preferred Stock, dated March 5, 2019 (incorporated herein by reference to Exhibit 3.11 of the Annual Report on Form 10-K filed on March 7, 2019).
10.1	First Amendment and Waiver to Second Amended and Restated Credit Agreement dated as of March 1, 2019, among Lilis Energy, Inc., the subsidiaries of Lilis Energy, Inc. party thereto as guarantors, BMO Harris Bank, N.A., as administrative agent for the Lenders, and the other lenders party thereto (incorporated herein by reference to Exhibit 10.41 of the Annual Report on Form 10-K filed on March 7, 2019).
10.2	Transaction Agreement, dated as of March 5, 2019, by and among Lilis Energy, Inc., the Värde Fund Vi-A, L.P., Värde Investment Partners, L.P., the Värde Fund Xi (Master), L.P., Värde Investment Partners (Offshore) Master, L.P., the Värde Skyway Fund, L.P., the Värde Skyway Mini-Master Fund, L.P. and the Värde Fund Xii (Master), L.P. (incorporated herein by reference to Exhibit 10.42 of the Annual Report on Form 10-K filed on March 7, 2019).
10.3	Amended and Restated Registration Rights Agreement, dated as of March 5, 2019, by and among Lilis Energy, Inc. and the Värde Parties party thereto (incorporated herein by reference to Exhibit 10.43 of the Annual Report on Form 10-K filed on March 7, 2019).
10.4	Second Amendment and Waiver to Second Amended and Restated Credit Agreement dated as of May 6, 2019, among Lilis Energy, Inc., the subsidiaries of Lilis Energy, Inc. party thereto as guarantors, BMO Harris Bank, N.A., as administrative agent for the Lenders, and the other lenders party thereto. (incorporated herein by reference to Exhibit 10.4 of the Quarterly Report on Form 10-Q filed on May 9, 2019).
10.5	Separation and Release Agreement for Ronald D. Ormand (incorporated herein by reference to Exhibit 10.1 of the Current Report on Form 8-K filed on June 6, 2019).
10.6	Third Amendment and Waiver to Second Amended and Restated Credit Agreement dated as of July 26, 2019, among Lilis Energy, Inc., the subsidiaries of Lilis Energy, Inc. party thereto as guarantors, BMO Harris Bank, N.A., as administrative agent for the Lenders, and the other lenders party thereto.
10.7	Purchase and Sale Agreement by and between Lilis Energy, Inc. and Winkler Lea WI, L.P. dated July 31, 2019 (incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed on August 5, 2019).



10.8	Purchase and Sale Agreement by and between Lilis Energy, Inc. and Winkler Lea Royalty, L.P. dated July 31, 2019 (incorporated herein by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed on August 5, 2019).
10.9*	Fourth Amendment and Waiver to Second Amended and Restated Credit Agreement dated as of November 5, 2019, among Lilis Energy, Inc., the subsidiaries of Lilis Energy, Inc. party thereto as guarantors, BMO Harris Bank, N.A., as administrative agent for the Lenders, and the other lenders party thereto.
31.1*	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended (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.
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema Document
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document
*	Filed herewith.
†	Indicates management contract or compensatory plan.
+	To be filed by amendment.

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.

Date: November 7, 2019	By:	/s/ Joseph C. Daches
		Joseph C. Daches
		Interim Chief Executive Officer, President,
		Chief Financial Officer and Treasurer
		(Principal Financial and Accounting Officer)