LILIS ENERGY, INC. (Form: 10-K, Received: 04/30/2020 16:49:02)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K



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

For the fiscal year ended December 31, 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)

Registrant’s telephone number including area code (817) 585-9001

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

Securities registered pursuant to Section 12(g) of the Exchange Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act:

Yes ¨ No ý

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15 (d) of the Act: Yes [ ] No ý

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	¨	Non-accelerated filer	ý
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 June 28, 2019, the aggregate market value of the voting and non-voting shares of common stock of the registrant issued and outstanding on such date, excluding shares held by affiliates of the registrant as a group was $35,554,508 based on the closing sales price of $0.61 per share of the registrant’s common stock on June 28, 2019 on the NYSE American.

As of April 30, 2020, 95,422,277 shares of the registrant’s common stock were issued and outstanding.

TABLE OF CONTENTS



		Page
PART I

Special Note regarding Forward Looking Statements
Items 1 and 2.	Business and Properties	7
Item 1A.	Risk Factors	20
Item 3.	Legal Proceedings	36
Item 4.	Mine Safety Disclosures	36

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	37
Item 6.	Selected Financial Data	37
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	55
Item 8.	Financial Statements and Supplementary Data	56
Item 9.	Changes in and disagreements with Accountants on Accounting and Financial Disclosure	57
Item 9A.	Controls and Procedures	57
Item 9B.	Other Information	57

PART III

Item 10.	Directors, Executive Officers and Corporate Governance	58
Item 11.	Executive Compensation	63
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	71
Item 13.	Certain Relationships and Related Transactions, and Director Independence	73
Item 14.	Principal Accounting Fees and Services	75

PART IV

Item 15.	Exhibits, Financial Statement Schedules	77
Item 16.	Form 10-K Summary	82

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K (this “Annual Report”) contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. Forward-looking statements may include the words “may,” “should,” “could,” “estimate,” “intend,” “plan,” “project,” “continue,” “believe,” “predict,” “expect,” “anticipate,” “goal,” “forecast,” “target” or other similar words.

All statements, other than statements of historical fact, that are included in this Annual Report, including such statements that address activities, events or developments that we expect or anticipate will or may occur in the future are forward-looking statements, including, but not limited to, the potential impact of epidemics and pandemics, including the COVID-19 coronavirus (“COVID-19”), any projections of earnings, revenue or other financial items; any statements of the plans, strategies and objectives of management for future operations; any statements concerning future production, reserves or other resource development opportunities; any projected well performance or economics, or potential joint ventures or strategic partnerships; any statements regarding future economic conditions or performance; any statements regarding future capital-raising activities; any statements of belief; commodity price risk management activities and the impact on our average realized price; and any statements of assumptions underlying any of the foregoing.

Although we believe that the expectations, plans, and intentions reflected in or suggested by our forward-looking statements are reasonable, we can give no assurance that these plans, intentions, or expectations will be achieved, and our actual results could differ materially from those projected or assumed in any of our forward-looking statements.

Our future financial condition and results of operations, as well as any forward-looking statements, are subject to inherent risks and uncertainties, many of which are beyond our control. Some of the factors, which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include but are not limited to, the impacts of COVID-19 on our business, financial condition and results of operations, the significant fall in the price of oil since the beginning of 2020, other conditions and events that raise doubts about our ability to continue as a going concern, and the other Risk Factors set forth in this Annual Report in Part I, “Item 1A. Risk Factors.” Should one or more of the risks or uncertainties described in this Annual Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those in any forward-looking statements.

The forward-looking statements in this Annual Report present our estimates and assumptions only as of the date of this Annual Report. Except as required by law, we specifically disclaim all responsibility to publicly update any information contained in any forward-looking statement and, therefore, disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by this cautionary statement.

Unless the context otherwise requires, all references in this report to “Lilis,” “we,” “us,” “our,” “ours,” or “the Company” are to Lilis Energy, Inc. and its subsidiaries.

GLOSSARY

In this Annual Report, the following abbreviation and terms are used:

Bbl. Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude, condensate or natural gas liquids.

Bcf. Billion cubic feet of natural gas.

Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one barrel of crude oil or condensate.

BLM. The Bureau of Land Management of the United States Department of the Interior.

BOE. One barrel of crude oil equivalent, determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.

BOE/d. Barrels of oil equivalent per day.

BO/d. Barrel of oil per day.

BTU or British Thermal Unit. The quantity of heat required to raise the temperature of one pound mass of water by 28.5 to 59.5 degrees Fahrenheit.

Completion. Installation of permanent equipment for production of oil or natural gas.

Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure but that, when produced, is in the liquid phase at surface pressure and temperature.

Development well. A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

Drilling locations. Total gross locations specifically quantified by management to be included in our multi-year drilling activities on existing acreage. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors.

Dry well or dry hole. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Exploratory well. A well drilled to find a new field or to find a new reservoir. Generally, an exploratory well in any well that is not a development well, an extension well, a service well or a stratigraphic well.

FERC. The Federal Energy Regulatory Commission.

Field. An area consisting of either a single reservoir or multiple reservoirs all grouped on or related to the same geological structural feature and/or stratigraphic condition.

Formation. An identifiable layer of subsurface rocks named after its geographical location and dominant rock type.

Gross acres, gross wells, or gross reserves. A well, acre or reserves in which we own a working interest, reported at the 100% or 8/8ths level. For example, the number of gross wells is the total number of wells in which we own a working interest.

Lease. A legal contract that specifies the terms of the business relationship between an energy company and a landowner or mineral rights holder on a particular tract of land.

Leasehold. Mineral rights leased in a certain area to form a project area.

Liquids. Crude oil and natural gas liquids, or NGLs.

MBBLs. One thousand barrels of crude oil or other liquid hydrocarbons.

MBOE. One thousand barrels of crude oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Mcf. One thousand cubic feet of natural gas.

Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

MMbtu. One million British Thermal Units.

MMcf. One million cubic feet of natural gas.

Net acres or net wells. The sum of fractional ownership working interests in gross acres or gross wells. The number of net acres or wells is the sum of the fractional working interests owned in gross acres or wells expressed as whole numbers and fractions of whole numbers.

NGL. Natural gas liquids, or liquid hydrocarbons found as a by-product of natural gas.

Overriding royalty interest. Is similar to a basic royalty interest except that it is created out of the working interest. For example, an operator possesses a standard lease providing for a basic royalty to the lessor or mineral rights owner of 1/8 of 8/8. This then entitles the operator to retain 7/8 of the total oil and natural gas produced. The 7/8 in this case is the 100% working interest the operator owns. This operator may assign his working interest to another operator subject to a retained 1/8 overriding royalty. This would then result in a basic royalty of 1/8, an overriding royalty of 1/8 and a working interest of 3/4. Overriding royalty interest owners have no financial or other obligation or responsibility for developing and operating the property. The only expenses borne by the overriding royalty owner are a share of the production or severance taxes and sometimes costs incurred to make the oil or gas salable.

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

Production. Natural resources, such as oil or gas, flowed or pumped out of the ground.

Productive well. A producing well or a well that is mechanically capable of production.

Proved developed oil and natural gas reserves. Proved developed oil and natural gas reserves are proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Proved reserves. Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Proved undeveloped reserves. Proved undeveloped oil and natural gas reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Project. A targeted development area where it is probable that commercial oil and/or natural gas can be produced from new wells.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Recompletion. The process of re-entering an existing well bore that is either producing or not producing and modifying the existing completion and/or completing new reservoirs in an attempt to establish new production or increase or re-activate existing production.

Reserves. Estimated remaining quantities of oil, natural gas and natural gas liquids anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Reservoir. A subsurface formation containing a natural accumulation of producible natural gas and/or oil that is naturally trapped by impermeable rock or other geologic structures or water barriers and is individual and separate from other reservoirs.

Secondary Recovery. A recovery process that uses mechanisms other than the natural pressure or fluid drive of the reservoir, such as gas injection or water flooding, to produce residual oil and natural gas remaining after the primary recovery phase.

Shut-in. A well suspended from production or injection but not abandoned.

Standardized measure. The present value of estimated future cash flows from proved oil and natural gas reserves, less future development, abandonment, production and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.

Successful. A well is determined to be successful if it is producing oil or natural gas in paying quantities.

Undeveloped acreage. Leased acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas regardless of whether such acreage contains proved reserves.

Water-flood. A method of secondary recovery in which water is injected into the reservoir formation to maintain or increase reservoir pressure and displace residual oil and enhance hydrocarbon recovery.

Working interest. The operating interest that gives the lessees/owners the right to drill, produce and conduct operating activities on the property, and to receive a share of the production revenue, subject to all royalties, overriding royalties and other burdens, all development costs, and all risks in connection therewith.

PART I

Items 1 and 2. Business and Properties

Overview

Lilis is an independent oil and natural gas company focused on the exploration, development, production, and acquisition of oil, natural gas and NGLs from properties in the Permian Basin. Our operations are focused in the Delaware Basin of the Permian in Winkler, Loving, and Reeves Counties, Texas and Lea County, New Mexico, where the production is approximately 74% Liquids, a relatively high liquid production ratio compared to many of our peers. Over 90% of our revenues are generated from the sale of Liquids.

Our History

The Company was incorporated in the State of Nevada in 2007. The name of the corporation was changed from Recovery Energy, Inc. to “Lilis Energy, Inc.” in December 2013, and at such time, the Company was primarily focused on the exploration, development and production of oil and natural gas properties in the Denver-Julesburg (DJ) Basin.

In June 2016, we completed a transformative merger transaction with Brushy Resources, Inc. (“Brushy Resources” or “Brushy”), which resulted in the acquisition of the Company’s initial assets in the Permian Basin. Given the stacked-pay opportunities and high rates of return in the Permian Basin, the Company determined that it would focus exclusively on expanding and developing its core Permian Basin assets and completed the divestiture of all of its oil and natural gas properties located in the DJ Basin in March 2017.

Our Business/Strategy

We are a pure play Permian Basin company focused on the production of Liquids. In each of the past two years, over 90% of our revenues have been generated from the sale of Liquids.

We are actively working on increasing liquidity including seeking strategic financing options. There is no assurance that our efforts will be successful and as a result there is substantial doubt about our ability to continue as a going concern. See Note 2 - Liquidity and Going Concern to our consolidated financial statements included in this Annual Report for additional information regarding our plans to improve our liquidity and our ability to continue to comply with the financial covenants under our Revolving Credit Agreement.

Oil and Natural Gas Properties

As of December 31, 2019, we owned leasehold acreage in approximately 27,920 gross (19,562 net) acres in the Delaware Basin, comprised of approximately 16,012 net acres in Winkler, Loving, and Reeves Counties, Texas and approximately 3,550 net acres in Lea County, New Mexico. Average net sales production volumes from our properties increased approximately 3% to 5,102 BOE/d in 2019 from 4,965 BOE/d in 2018.

We currently estimate our properties include at least five to seven productive zones and hold more than 1,000 future drilling locations across all of the productive zones within this position.

Reserves Data

Proved Reserves

The following table presents our estimated net proved oil and natural gas reserves based on the reserves report prepared by LaRoche Petroleum Consultants, Ltd. (“LaRoche”) as of December 31, 2019, and the reserves reports prepared by Cawley, Gillespie & Associates, Inc. (“CG&A”) for the years 2018 and 2017. Each reserves report has been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”). All of our proved reserves included in the reserves reports are located in the Delaware Basin of the Permian Basin:

Summary of Oil and Natural Gas Reserves



	For the Year Ended December 31,
	2019	2018	2017
Proved Developed Reserves
Oil (MBbls)	5,335	6,278	2,531
NGLs (MBbls)	2,278	2,654	645
Total Liquids (MBbls)	7,613	8,932	3,176
Natural Gas (MMcf)	29,445	27,046	6,594
Total MBOE	12,521	13,440	4,275

Proved Undeveloped Reserves
Oil (MBbls)	—	14,927	4,640
NGLs (MBbls)	—	5,723	960
Total Liquids (MBbls)	—	20,650	5,600
Natural Gas (MMcf)	—	51,703	9,466
Total MBOE	—	29,267	7,178

Total Proved Reserves
Oil (MBbls)	5,335	21,205	7,171
NGLs (MBbls)	2,278	8,377	1,605
Total Liquids (MBbls)	7,613	29,582	8,776
Natural Gas (MMcf)	29,445	78,749	16,060
Total MBOE	12,521	42,707	11,453

Proved Undeveloped Reserves

As of December 31, 2019, we did not recognize any proved undeveloped reserves. During 2019, our proved undeveloped (“PUD”) reserves decreased 29,267 MBOE primarily due to capital constraints, as discussed below, and the conversion of one PUD to proved developed producing (“PDP”) reserves in 2019. Costs incurred to develop the PUD were approximately $7.5 million during 2019.

All of our PUD reserves were reclassified as unproved due to our inability to meet the Reasonably Certain criteria for recognizing PUD reserves because of the uncertainty regarding the availability of capital to us for the development of these reserves as of December 31, 2019, which was driven by further pricing declines during the fourth quarter of 2019. See Note 2 - Liquidity and Going Concern to our consolidated financial statements in this Annual Report. As a result, the Company recognized approximately $75.3 million of impairment relating to the value of PUD reserves which were reclassified as unproved in the fourth quarter of 2019.

For additional information regarding the changes in our proved reserves, see our “Supplementary Information on Oil and Natural Gas Exploration, Development and Production Activities” to our consolidated financial statements in Item 15 of this Annual Report.

Control over Reserve Estimates

The Company’s estimated proved oil and gas reserves have been prepared by the independent petroleum engineering firm LaRoche as of December 31, 2019 and CG&A as of December 31, 2018, assisted by the engineering and operations departments of the Company. For the year ended December 31, 2019, LaRoche estimated reserves for our properties comprising 100% of the PV-10 of our proved oil and gas reserves as described in more detail herein, in compliance with SEC definitions and guidance and in accordance with generally accepted petroleum engineering principles.

Internal Controls over Reserves Estimate

Our policy regarding internal controls over the recording of reserves is structured to objectively and accurately estimate our oil and natural gas reserves quantities and values in compliance with the regulations of the SEC. Responsibility for compliance in reserves bookings is delegated to our Chief Executive Officer with assistance from our Vice President of Reservoir Engineering.

Technical reviews are performed by our Vice President of Reservoir Engineering, our senior geologist and other consultants who evaluate all available geological and engineering data. This data, in conjunction with economic data and ownership information, is used in making a determination of estimated proved reserves quantities. Indranil (Neil) Barman, our Vice President of Reservoir Engineering, has more than 23 years of industry experience and has been evaluating oil and natural gas properties since 2004. He received his Ph.D. degree in Petroleum Engineering from Texas A&M University and is a registered professional engineer licensed in the State of Texas.

For the year ended December 31, 2019, our Reserves Committee, a committee of our Board of Directors, assisted management and the Board of Directors with their oversight of our reserves estimation and certification process and the work of our independent reserves engineer. Following the resignation of three directors, effective as of April 15, 2020, the Board of Directors dissolved the Reserves Committee as a result of a reduction in the size of the Board of Directors.

Our reserves estimates and the corresponding report from LaRoche, along with the process for developing such estimates, are also reviewed by our geologist and the Audit Committee of our Board of Directors to ensure compliance with SEC disclosure and internal control requirements and to verify the independence of our third-party consultants. The Audit Committee of our Board of Directors reviews the final reserves estimate in conjunction with LaRoche’s reserves report.

Third-Party Reserves Study

Our controls over reserves estimates include retaining an independent third-party consultant, LaRoche, as our independent petroleum engineering consulting firm to perform a reserves report of our proved reserves for 2019. We provided LaRoche with information about our oil and natural gas properties, including production information, prices and costs, and LaRoche performed reserves studies using its own engineering assumptions and the economic data provided by us. All of our total calculated proved reserves value was estimated by LaRoche for 2019, and all of the information regarding our 2019, 2018, and 2017 reserves in this Annual Report is derived from the third party reports of LaRoche and CG&A.

LaRoche is an independent petroleum engineering consulting firm that has been providing petroleum engineering consulting services for over 40 years. The technical personnel responsible for preparing the reserves estimates at LaRoche meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. LaRoche is an independent firm of petroleum engineers, geologists, geophysicists, and petrophysicists. They do not own an interest in any of our properties and are not employed on a contingent fee basis. All reports by LaRoche were developed utilizing their own geological and engineering data, supplemented by data provided by Lilis

Oil and natural gas reserves and the estimates of the present value of future net cash flows therefrom were determined based on prices and costs as prescribed by the SEC and Financial Accounting Standards Board (“FASB”) guidelines. Reserves calculations involve the estimate of future net recoverable reserves of oil and natural gas and the timing and amount of future net cash flows to be received therefrom. Such estimates are not precise and are based on assumptions regarding a variety of factors, many of which are variable and uncertain. Proved reserves were estimated in accordance with guidelines established by the SEC and the FASB, which require that reserves estimates be prepared under existing economic and operating conditions with no provision for price and cost escalations except by contractual arrangements. For the years ended December 31, 2019, 2018, and 2017, we based the estimated discounted future net cash flows from proved reserves on the trailing 12-month averages of oil and natural gas index prices, calculated as the un-weighted arithmetic average for the first-day-of-the-month price for each month and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties.

The price of oil and natural gas has fallen significantly since the beginning of 2020, due in part to failed OPEC negotiations as well as concerns about the COVID-19 pandemic, which has significantly decreased worldwide demand for oil. If these reduced prices continue or if prices of oil, natural gas and NGLs experience additional substantial decline, our oil, natural gas and NGL reserves may be materially and adversely affected.

Oil and Natural Gas Production, Production Prices, and Production Costs

Production Volumes and Sales Prices

The following table summarizes the average volumes and realized prices of oil and natural gas produced from our properties during the periods indicated:



	For the Years Ended December 31,
	2019		2018		2017
Production
Oil (Bbls)-net production	1,131		1,090		372
Oil (per Bbl)-average realized price	$	52.19	$	53.26	$	47.92
Natural gas liquids (Bbls)-net production	221		246		74
Natural gas liquids (per Bbl)-average realized price	$	17.52	$	28.11	$	22.49
Natural Gas (Mcf)-production	3,064		2,856		776
Natural Gas (per Mcf)-average realized price	$	1.04	$	1.84	$	2.74
Barrels of oil equivalent (BOE)	1,862		1,812		575
Average daily net production (BOE)	5,102		4,965		1,576
Average Sales Price per BOE	$	35.47	$	38.75	$	37.57

The average oil and NGL sales prices above are calculated by dividing revenue from oil sales by volume of oil sold, in “Bbls.” The average natural gas sales prices above are calculated by dividing revenue from natural gas sales by the volume of natural gas sold, in “Mcf.” The total average sales price amounts are calculated by dividing total revenues by total volume sold, in BOE. The average production costs above are calculated by dividing production costs by total production in BOE.

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

The following table sets forth certain information regarding oil and natural gas production costs, production taxes, and depreciation, depletion and amortization:



	For the Years Ended December 31,
	2019		2018		2017
Production costs per BOE	$	10.79	$	9.51	$	12.21
Production taxes per BOE	1.77		2.05		2.06
Depreciation, depletion, and amortization per BOE	17.85		14.00		12.21
Impairment of oil and gas properties per BOE	122.60		—		18.26
Total operating costs per BOE	$	153.01	$	25.56	$	44.74

Acreage

The following table sets forth our approximate gross and net developed and undeveloped leasehold acreage as of December 31, 2019:

Undeveloped Acreage

Developed Acreage

Total

Gross

Net

Gross

Net

Gross

Net

Delaware Basin

15,250

8,050

12,670

11,512

27,920

19,562

Undeveloped Acreage Expirations

Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. The following table sets forth the net undeveloped acreage, as of December 31, 2019, that will expire over the next three years unless production is established within the spacing units covering the acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates:



	2020	2021	2022
Delaware Basin	5,670	1,570	90

As of the date of this Annual Report, leases holding 1,285 net acres in Reeves County and 593 net acres in Winkler County have expired in 2020. We have additional acreage that may expire depending on the timing and availability of capital for continued development of our leasehold acreage and lease renewals.

Our undeveloped leasehold acreage at December 31, 2019 was 15,250 gross (8,050 net) acres, of which 5,670 net acres have expiration dates in 2020 and will expire if the Company does not obtain necessary funding to either extend the leases or begin drilling before their expiration dates, less 560 net leasehold acres as part of the February 28, 2020 Lea County, New Mexico leasehold divestiture. As a result of the uncertainty regarding the availability of capital to fund drilling operations or extend leases holding undeveloped acreage, we recorded $56.2 million of impairments for undeveloped acreage for the year ended December 31, 2019.

Productive Wells

As of December 31, 2019, we had 18 gross (14.8 net) oil wells and 23 gross (19.8 net) natural gas wells. A net well is our percentage ownership interest in a gross well.

Productive wells are either wells producing in commercial quantities or wells capable of commercial production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Multiple completions in the same wellbore are counted as one well. A well is categorized under state reporting regulations as an oil well or a natural gas well based on the ratio of natural gas to oil produced when it first commenced production, and such designation may not be indicative of current production.

Drilling Activity

For the year ended December 31, 2019, we drilled 5 gross (4.4 net) horizontal wells in the Delaware Basin. We completed and placed on production 7 gross (5.4 net) horizontal wells. As of December 31, 2019, 4 gross (3.8 net) wells were drilled but not yet completed. All of these wells were successful, and none were a dry hole.

The following table sets forth information with respect to the number of wells drilled during the years indicated. Each of these wells was drilled in the Delaware Basin in the Permian Basin.



	2019		2018		2017
	Gross	Net	Gross	Net	Gross	Net
Exploratory:
Productive	5	4.4	9	8.7	5	4.2
Dry	—	—	—	—	—	—
Development:
Productive	—	—	6	5.6	—	—
Dry	—	—	—	—	—	—
Total:
Productive	5	4.4	15	14.3	5	4.2
Dry	—	—	—	—	—	—

Present Activities

As of December 31, 2019, we had no wells in the process of drilling, completing, dewatering or shut-in awaiting infrastructure.

Title to Properties

We generally conduct a preliminary title examination prior to the acquisition of properties or leasehold interests. Prior to commencement of operations on such acreage, a thorough title examination will usually be conducted, and any significant defects will be remedied before proceeding with operations. We believe the title to our leasehold properties is good, defensible and customary with practices in the oil and natural gas industry, subject to such exceptions that we believe do not materially detract from the use of such properties. We have identified title defects during 2018 and 2019 which resulted in impairment of undeveloped acreage costs and further title defects may exist which would result in impairment of undeveloped acreage costs. Our properties are potentially subject to customary royalty and other interests, liens for current taxes, and other burdens which do not materially interfere with the use of or affect our carrying value of the properties. The majority of our Delaware Basin leasehold position is also subject to mortgages securing indebtedness under our credit and guarantee agreement.

With respect to our properties of which we are not the record owner, we rely on contracts with the owner or operator of the property or assignment of leases, pursuant to which, among other things, we generally have the right to have our interest placed on record.

Competitive Business Conditions

The oil and natural gas industry is intensely competitive, particularly with respect to acquiring prospective oil and natural gas properties. We face intense competition from a substantial number of major and independent oil and natural gas companies, many of which have larger technical staffs and greater financial and operational resources. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects. We also compete with other oil and natural gas companies to secure drilling rigs and other equipment and services necessary for the drilling, completion, production, processing and maintenance of our wells, and we could face shortages or delays in securing these services from time to time if availability is limited. In addition, we compete to hire and retain professionals, including experienced geologists, geophysicists, engineers, and other professionals and consultants. We believe the location of our acreage, our technical expertise, available technologies, our financial resources, and the experience and knowledge of our management enables us to compete effectively in our core operating areas, but we recognize that many of our competitors have greater financial and operational resources.

The oil and natural gas industry also faces competition from alternative fuel sources, including other fossil fuels such as coal and imported liquefied natural gas. Competitive conditions may also be affected by future new energy, climate-related, financial, and other policies, legislation, and regulations.

Marketing and Pricing

We derive our revenue and cash flow principally from the sale of oil, natural gas and NGLs. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil, natural gas and NGLs. We sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts. Because some of our operations are located outside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTI or other major market pricing. The market price for oil, natural gas and NGLs is dictated by supply and demand; consequently, we cannot accurately predict or control the price we may receive for our oil, natural gas and NGLs. The price of oil and natural gas has fallen significantly since the beginning of 2020, due in part to failed Organization of Petroleum Exporting Countries (“OPEC”) negotiations as well as concerns about the COVID-19 pandemic and its impact on the worldwide economy and global demand for oil and gas. The resulting precipitous decline in oil and gas pricing experienced during March 2020, through the date of this Annual Report, if prolonged. or a further deterioration of the market price for oil and natural gas, will further negatively impact our ability to continue to operate as a going concern.

We have an active hedging program to mitigate risk regarding our cash flow and to protect returns from our development activity in the event of decreases in the prices received for our production; however, hedging arrangements may expose us to risk of significant financial loss in some circumstances and may limit the benefit we would receive from increases in the prices for oil, natural gas and NGLs.

Major Customers

We sell our production to a small number of customers which is common in the oil and natural gas industry. The following table outlines our major customers and their percentage contribution to our total revenues for the years ended December 31, 2019 and 2018:



	Year Ended December 31,
	2019			2018
Texican Crude & Hydrocarbon, LLC		19	%	87	%
ARM Energy Management, LLC		68	%	—	%
Lucid Energy Delaware, LLC		12	%	10	%
ETC Field Services LLC		1	%	2	%
		100	%	100	%

Delivery Commitments

ARM Sales Agreement

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



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

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

the contract and the net settlement criteria being met. See Note 9 - Derivatives to our consolidated financial statements for information regarding the recognition of the net settlement mechanism as an embedded derivative over the remainder of the contract.

Regulation of the Oil and Natural Gas Industry

General

Our oil and natural gas exploration, production, and related operations are subject to extensive federal, state and local laws and regulations. These laws and regulations, which are under continual review for amendment, include matters relating to drilling and production practices; the disposal of water from operations and the processing, handling and disposal of hazardous materials; bonding, permitting and licensing, and reporting requirements; taxation; and marketing, transportation and pricing practices.

The failure to comply with these laws and regulations could result in substantial penalties, including administrative, civil, or criminal penalties. These laws and regulations increase our cost of doing business and can potentially affect our profitability.

Regulation of Production of Oil and Natural Gas

The production of oil and natural gas is subject to regulation under a wide range of federal, state and local laws, orders and regulations. These statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. The states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing or density, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations so as to have reductions in well spacing or density. We believe we are in substantial compliance with these laws and regulations; however, should we fail to comply with these laws and regulations, we could face substantial penalties.

Environmental, Health, and Safety Regulations

Our operations are subject to stringent federal, state, and local laws and regulations relating to the protection of the environment and human health and safety. There are various governmental agencies, including the U.S. Environmental Protection Agency (“EPA”), the U.S. Occupational Safety and Health Administration (“OSHA”) and analogous state agencies, that have the authority to enforce compliance with these laws and regulations. Environmental laws and regulations may require that permits be obtained before drilling commences or facilities are commissioned; restrict the types, quantities, and concentration of various substances that can be released into the environment in connection with drilling and production activities; govern the handling and disposal of waste material; and limit or prohibit drilling and exploitation activities on certain lands lying within wilderness, wetlands, and other protected areas, including areas containing threatened or endangered animal species.

We do not believe that our environmental risks are materially different from those of comparable companies in the oil and natural gas industry. We believe our present activities substantially comply, in all material respects, with existing environmental laws and regulations. Nevertheless, environmental laws may result in a curtailment of production or material increases in the cost of production, development or exploration, and may otherwise adversely affect our financial condition and results of operations. Although we maintain liability insurance coverage for liabilities from pollution, environmental risks are generally not fully insurable. We are committed to strict compliance with these regulations. During the years ended December 31, 2019 and 2018, we incurred approximately $220,000 and approximately $38,000, respectively, related to compliance with environmental laws for our oil and natural gas properties.

The following is a summary of the more significant existing and proposed environmental and occupational health and safety laws and regulations to which our business operations are or may be subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position:

The Resource Conservation and Recovery Act. The Resource Conservation and Recovery Act, as amended (“RCRA”), and the comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. The RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility. The RCRA includes an exemption for certain oil and natural gas exploration and production waste from regulation as hazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. As a

result, we are not required to comply with a substantial portion of RCRA’s hazardous waste requirements. At various times in the past, proposals have been made to amend the RCRA to rescind the exemption that excludes oil and natural gas exploration and production wastes from regulation as hazardous waste. Most recently, in April 2019, EPA concluded that rescinding the RCRA exploration and production waste exemption was not necessary “at this time”.

In the event that we fail to comply with requirements for the management of hazardous waste, administrative, civil and/or criminal penalties can be imposed. We believe that we are in substantial compliance with current applicable requirements related to hazardous waste management. Repeal or modification of the RCRA oil and natural gas exemption, or modification of similar exemptions in applicable state statutes, could increase the volume of hazardous waste we are required to manage and dispose of and could cause us to incur potentially significant increased operating expenses.

Water Discharges. The Federal Water Pollution Control Act (also known as the Clean Water Act), the Safe Drinking Water Act, the Oil Pollution Act and analogous state laws and regulations impose restrictions and controls on the discharge of produced waters and other oil and natural gas wastes into navigable waters of the United States as well as state waters. Permits must be obtained to discharge pollutants into state and federal waters and to discharge pollutants into regulated waters and wetlands. Spill Prevention, Control, and Countermeasure requirements of the Clean Water Act require appropriate secondary containment loadout controls, piping controls, berms and other measures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon spill, rupture or leak. In June 2015, the EPA and the U.S. Army Corps of Engineers jointly promulgated rules redefining the scope of waters protected under the Clean Water Act, and in October 2015, the U.S. Court of Appeals for the Sixth Circuit stayed them nationwide. The EPA and U.S. Army Corps of Engineers have resumed nationwide use of the agencies’ prior regulations defining the term “waters of the United States.” On February 28, 2017, President Trump directed the EPA to review the rules and “publish for notice and comment a proposed rule rescinding or revising the rules, as appropriate and consistent with law.” The Clean Water Act and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges of crude oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release.

The Oil Pollution Act of 1990 (“Oil Pollution Act”) and regulations thereunder are the primary federal law for oil spill liability. The Oil Pollution Act contains numerous requirements relating to the prevention of and response to petroleum releases into waters in the United States and imposes a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. The Oil Pollution Act subjects each responsible party to strict liability for oil removal costs and a variety of public and private damages, including all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters and natural resource damages.

The Safe Drinking Water Act, as amended, establishes a regulatory framework for the underground injection of a variety of wastes, including brine produced and separated from crude oil and natural gas production, with the main goal being the protection of usable aquifers. The primary objective of injection well operating permits and requirements is to ensure the mechanical integrity of the wellbore and to prevent migration of fluids from the injection zone into underground sources of drinking water.

In response to recent seismic events near underground injection wells used for the disposal of oil and natural gas-related wastewaters, federal and state agencies have been investigating whether such wells have caused increased seismic activity, and some states have shut down or imposed moratoria on the use of such injection wells. In Texas, the Texas Railroad Commission (“RRC”) regulates the disposal of produced water by injection well. The RRC requires operators to obtain a permit for the operation of saltwater disposal wells and establishes minimum standards for injection well operations. The RRC has adopted permit rules for injection wells to address these seismic activity concerns within the state. These rules could impact the availability of injection wells for disposal of wastewater from our operations. Increased costs associated with the transportation and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may reduce our profitability; however, we do not believe that the costs associated with the disposal of produced water will have a material adverse effect on our operations.

Failure to comply with these regulations may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws.

Air Pollutant Emissions. The federal Clean Air Act (the “Clean Air Act”), and comparable state and local air pollution laws, provide a framework for national, state and local efforts to protect air quality. Our operations utilize equipment that emits air pollutants which may be subject to federal and state air pollution control laws. These laws generally require utilization of air emissions control equipment to achieve prescribed emissions limitations and ambient air quality standards, as well as operating permits for existing equipment and construction permits for new and modified equipment. In May 2016, the EPA issued a final rule regarding the criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major

source, which would subject operators to more stringent air permitting processes and requirements. These laws and regulations may increase our costs of compliance, and we may face administrative, civil and criminal penalties if we fail to comply with the requirements of the Clean Air Act and associated state laws and regulations. We believe that we are in compliance in all material respects with the requirements of applicable federal and state air pollution control laws.

Regulation of “Greenhouse Gas” Emissions. The EPA has adopted regulations that, among other things, establish Prevention of Significant Deterioration (“PSD”), construction, and Title V operating permit requirements for certain new and modified large stationary sources to address findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHG”) present an endangerment to public health and the environment. Facilities required to comply with PSD requirements for their GHG emissions will be required to meet “best available control technology” standards for those emissions, which will be established on a case-by-case basis. The EPA has also issued rules requiring the monitoring and reporting of GHG emissions, which include the reporting of GHG emissions from gathering and boosting systems, completions and workovers of oil wells using hydraulic fracturing, and blowdowns of natural gas transmission pipelines.

While Congress has from time to time considered legislation to reduce emissions of GHG, there has not been significant activity in the form of adopted federal legislation to reduce GHG emissions in recent years. In the absence of such federal climate legislation, a number of state and regional cap and trade programs have emerged that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting GHG. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHG from, our equipment and operations could require us to incur costs to reduce emissions of GHG associated with our operations.

Restrictions on GHG emissions that may be imposed could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources, as well as increase our costs of operations.

Hydraulic Fracturing Activities. Hydraulic fracturing is a common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight unconventional formations. Federal and state occupational safety and health laws require us to organize and maintain information about hazardous materials used, released, or produced in our operations. Some of this information must be provided to our employees, state and local governmental authorities, and local citizens. We are also subject to the requirements and reporting framework set forth in the federal workplace standards.

Several states and local jurisdictions have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, the Texas Legislature adopted legislation requiring oil and natural gas operators to publicly disclose the chemicals used in the hydraulic fracturing process. The RRC adopted rules and regulations implementing this legislation that apply to all wells for which the RRC issues an initial drilling permit. The law requires that the well operator disclose the list of chemical ingredients subject to the requirements of OSHA for disclosure on an internet website and also file the list of chemicals with the RRC with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the RRC. The RRC also adopted rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular.

We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities; however, if new or more stringent federal, state, or local restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells. For additional information about hydraulic fracturing and related regulatory matters, see “Risk Factors-Risks Relating to the Oil and natural gas Industry.”

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “superfund law,” imposes joint and several liabilities, regardless of fault or the legality of the original conduct, on some classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of a disposal site or sites where the release occurred and companies that transport, dispose, or arrange for disposal of the hazardous substance(s) released. Persons who are or were responsible for releases of hazardous substances under CERCLA may be jointly and severally liable for the costs of cleaning up the hazardous substances and for damages to natural resources.

We generate materials in the course of our operations that may be regulated as hazardous substances. Despite the “petroleum exclusion” of CERCLA, which currently encompasses natural gas, we may handle other hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations. In addition, we currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration, production and processing for many years, and some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for disposal. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state and local laws. Under these laws, we could be required to undertake investigatory, response, or corrective measures, which could include soil and groundwater sampling, the removal of previously disposed substances and wastes, the cleanup of contaminated property, or performance of remedial plugging or pit closure operations to prevent future contamination, the costs of which could be substantial.

Endangered Species Act and Migratory Birds. The Endangered Species Act (“ESA”) restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. We may conduct operations under oil and natural gas leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species that potentially could be listed as threatened or endangered under the ESA may exist.

The U.S. Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.

OSHA. We are subject to the requirements of OSHA and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes and regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

State Laws. There are numerous state laws and regulations in the states where we operate that relate to the environmental aspects of our business. Some of those laws and regulations are discussed above. They relate to, among other things, requirements to remediate spills of deleterious substances associated with oil and natural gas activities, the conduct of salt water disposal operations, and the methods of plugging and abandonment of oil and natural gas wells which have been unproductive. Numerous state laws and regulations also relate to air and water quality. We believe that we are in substantial compliance with all state laws governing environmental matters and all permitting requirements; however, in the event that we fail to comply with such laws, we may face substantial penalties and incur significant costs.

Natural Gas Sales and Transportation

Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. The Federal Energy Regulatory Commission (“FERC”) has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies.

Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and release of our natural gas pipeline capacity. FERC has also promulgated a series of orders, regulations and rules to foster competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company.

Under FERC’s current regulatory regime, transmission services are provided on an open-access, non-discriminatory basis at cost-based rates or negotiated rates. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of transporting natural gas to point-of-sale locations.

Additionally, we are required to comply with anti-market manipulation laws and regulations promulgated by FERC and the Commodity Future Trading Commission with regard to our physical purchases and sales of energy commodities and any related hedging activities, and, if we fail to comply, we could be subject to penalties and potential third-party damage claims.

Oil Sales and Transportation

Sales of crude oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Our crude oil sales are affected by the availability, terms and cost of transportation.

The transportation of oil in common carrier pipelines is subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. We believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors, as effective interstate and intrastate rates are equally applicable to all comparable shippers.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by pro-rationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

Federal Income Tax and State Severance Taxes

Federal income tax laws significantly affect our operations. The principal provisions that affect us are those that permit us, subject to certain limitations, to deduct as incurred, rather than to capitalize and amortize/depreciate, our domestic “intangible drilling and development costs” and to claim depletion on a portion of our domestic oil and natural gas properties based on 15% of our oil and natural gas gross income from such properties (up to an aggregate of 1,000 barrels per day of domestic crude oil and/or equivalent units of domestic natural gas).

Additionally, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. Texas and New Mexico currently impose a severance tax on oil production of 4.60% and 8.39%, respectively, and a severance tax on natural gas production of 7.50% and 9.24%, respectively.

Federal Leases

Operations on federal oil and natural gas leases must comply with certain regulatory restrictions, including various non-discrimination statutes, and certain of such operations must be conducted pursuant to certain on-site security regulations and other permits issued by federal agencies. In addition, on federal lands in the United States, the Office of Natural Resources Revenue (“ONRR”) prescribes, and in some cases limits, the types of costs that are deductible transportation costs for purposes of royalty valuation of production sold off the lease, including the deduction of costs associated with marketer fees, cash out and other pipeline imbalance penalties, or long-term storage fees. The ONRR has also been engaged in a process of promulgating new rules and procedures for determining the value of crude oil produced from federal lands for purposes of calculating royalties owed to the government. We cannot predict what, if any, effect any new rule will have on our operations.

Some of our operations are conducted on federal lands pursuant to oil and natural gas leases administered by the Bureau of Land Management (“BLM”). These leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. In addition to permits required from other regulatory agencies, lessees must obtain a permit from the BLM before drilling and comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, the valuation of production and payment of royalties, the removal of facilities, and the posting of bonds to ensure that lessee obligations are met. Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated.

Other Laws and Regulations

Various laws and regulations require permits for drilling wells and also cover spacing of wells, the prevention of waste of natural gas and oil, rates of production and other matters. The effect of these laws and regulations, as well as other regulations that could be promulgated in the jurisdictions in which we have production, could be to limit the number of wells that could be drilled on our properties and to limit the allowable production from the successful wells completed on our properties, thereby limiting our revenues.

Seasonal Nature of Business

Generally, the demand for oil and natural gas fluctuates depending on the time of year. Generally, demand for oil increases during the summer months and decreases during the winter months while natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers may sometimes lessen this fluctuation. Further, pipelines, utilities, local distribution companies, and industrial end users utilize oil and natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can also lessen seasonal demand.

Operational Hazards and Insurance

The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, blow outs, hydrogen sulfide emissions or releases, pipe failures and, in some cases, abnormally high pressure formations which could lead to environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. If any of these should occur, we could be required to pay amounts due to injury; loss of life; damage or destruction to property, natural resources and equipment; pollution or environmental damage; regulatory investigation; and penalties and suspension of operations.

In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We evaluate the purchase of insurance, coverage limits and deductibles on an annual basis.

Current Employees

As of December 31, 2019, we had 43 employees, all of whom were full-time employees. Our employees are not represented by any labor union or covered by any collective bargaining agreements.

As a result of layoffs and furloughs in response to COVID-19 and current commodity market conditions, the Company currently has 20 active employees.

We also retain certain independent consultants and contractors to provide various professional services, including additional land, legal, engineering, geology, environmental and tax services on a contract or fee basis as necessary for our operations.

Principal Executive Office and Corporate Offices

Our principal executive offices are in leased office space located at 201 Main St, Suite 700, Fort Worth, TX 76102, and our telephone number is (817) 585-9001.

Availability of Company Reports

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act of 1934 will be available through our Internet website at https://www.lilisenergy.com as soon as reasonably practical after we electronically file such material with, or furnish it to, the SEC. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at www.sec.gov. The information on, or that can be accessed through, our website is not incorporated by reference into this Annual Report and should not be considered part of this Annual Report or incorporated into any of our other filings with the SEC.

Item 1A. Risk Factors

Our business involves a high degree of risk. You should carefully consider all of the risks described in this Annual Report, in addition to the other information contained in this Annual Report. If any of the following risks, or any risk described elsewhere in this Annual Report, actually occur, our business, prospects, financial condition, results of operations, or cash flows could be materially adversely affected. In any such case, the trading price of our common stock could decline. Additional risks not presently known to us or that we currently deem immaterial may also adversely affect our business.

Risks Relating to Our Business

Failure to comply with any of the financial covenants contained in our Revolving Credit Agreement could cause an event of default and have a material adverse effect on our business.

Our Revolving Credit Agreement (hereinafter defined and described in more detail) requires the Company to maintain a ratio of Total Debt to EBITDAX (each as defined in the Revolving Credit Agreement) (the “Leverage Ratio”) of not more than 4.00 to 1.00 and a ratio of Current Assets to Current Liabilities (each as defined in the Revolving Credit Agreement) (the “Current Ratio”) of not less than 1.00 to 1.00 as of the last day of each fiscal quarter. See Note 10 to our consolidated financial statements in this Annual Report for a more detailed description of these financial covenants. Failure to comply with these covenants could cause an event of default under our Revolving Credit Agreement and have a material adverse effect on our business.

As of March 31, 2020, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants. Pursuant to the Fourteenth Amendment (as defined in Note 11 - Long-Term Debt), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants as of March 31, 2020. A failure to comply with the covenants, ratios or tests in our Revolving Credit Agreement, or any future indebtedness, including borrowing base deficiency payments, could result in an event of default. If an event of default occurs and is not cured or waived, our lenders, (i) would not be required to lend any additional amounts to us, (ii) could elect to declare all outstanding borrowings, together with accrued and unpaid interest and fees to be due and payable, (iii) could require us to apply all of our available cash to repay these borrowings and (iv) could prevent us from making debt service payments under our other agreements. A potential event of default and subsequent acceleration of indebtedness would have a material adverse effect on our business, financial condition and results of operations, and raises substantial doubt about our ability to continue as a going concern.

We have identified conditions and events that raise doubt about our ability to continue as a going concern.

We have incurred losses and negative cash flows from operating activities for the years ended December 31, 2019 and 2018 and, as of December 31, 2019, and we had a stockholders’ deficit of $238.2 million. We anticipate negative operating cash flows to continue for the foreseeable future due to, among other things, significant uncertainty in the outlook for oil and gas development and external market pressures due to the effects of pandemics, epidemics and other global health concerns such as the COVID-19 pandemic and its impact on the worldwide economy and global demand for oil and gas that are not within our control. For example, the price of oil and natural gas has fallen significantly since the beginning of 2020, due in part to failed OPEC negotiations and to concerns about the COVID-19 pandemic, which has significantly decreased worldwide demand for oil. As of December 31, 2019, our cash and cash equivalents was $3.8 million and our working capital deficit was $143.5 million. As of December 31, 2019, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants. Pursuant to the Twelfth Amendment (as defined in Note 11 - Long-Term Debt), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants, among other waivers of default, as of December 31, 2019. In addition, we currently have no availability for borrowing under our Revolving Credit Agreement.

We have been unable to secure further sources of liquidity, and as a result, substantial doubt exists about our ability to continue as a going concern as of the date of the filing of this Annual Report and our auditors have included a going concern paragraph in their Report of Independent Registered Public Accounting Firm. The accompanying consolidated financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of recorded assets, or the amounts and classification of liabilities that might be different should we be unable to continue as a going concern based on the outcome of these uncertainties described above. If we are unable to continue as a going concern, we may have to liquidate our assets and may receive less than the value at which those assets are carried on our audited financial statements, and it is likely

that investors will lose all or a part of their investment. See Note 2 - Liquidity and Going Concern to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” in this Annual Report for further detail.

Our ability to continue as a “going concern” contemplates the realization of assets and satisfaction of liabilities in the normal course of business, including the effective implementation and success of management’s plans to mitigate the conditions that raise substantial doubt about our ability to continue as a going concern.

Our consolidated financial statements included in Item 8 of this Annual Report have been presented on the basis that we would continue as a going concern, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business. Our liquidity and ability to comply with debt covenants under our Revolving Credit Agreement have been negatively impacted by the recent decrease in commodity prices, which have fallen significantly since the beginning of 2020, due in part to failed OPEC negotiations as well as concerns about the COVID-19 pandemic and its impact on the worldwide economy and global demand for oil and gas. As of March 31, 2020, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants and the Company will not be in compliance in future periods without additional sources of liquidity. Pursuant to the Fourteenth Amendment (as defined in Note 11 - Long-Term Debt Concern to our consolidated financial statements in this Annual Report), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants as of March 31, 2020. The uncertainty related to our continued operations, liquidity, and compliance with the financial covenants under our Revolving Credit Agreement raises substantial doubt regarding our ability to continue as a going concern. The consolidated financial statements do not reflect any adjustments that might result if we are unable to continue as a going concern.

In order to continue to improve our leverage position and current ratio to meet the financial covenants under the Revolving Credit Agreement and satisfy the borrowing base deficiency payment, we are currently pursuing or considering a number of actions, which in certain cases may require the consent of current lenders and stockholders. In November 2019, our board of directors formed a committee of independent directors (the “Special Committee”) tasked with reviewing and evaluating strategic alternatives that may enhance the value of the Company, including alternatives that may be available to identify and access further sources of liquidity. The Special Committee hired financial and legal advisors to advise the Special Committee on these matters.

The Special Committee continues to explore other financing alternatives and deleveraging transactions. We are also addressing operational matters such as adjusting our capital budget and improving cash flows from operations by continuing to reduce costs, and we intend to continue to pursue and consider other strategic alternatives.

There can be no assurance that we will be able to implement any of these plans successfully, or that such plans, if executed, will result in compliance with our Revolving Credit Agreement covenants or allow us to continue as a going concern.

Oil, natural gas and NGL prices are highly volatile. If commodity prices continue to experience substantial decline, our operations, financial condition, and level of expenditures for the development of our oil, natural gas and NGL reserves may continue to be materially and adversely affected.

The prices we receive for our oil, natural gas, and NGL production heavily influence our revenue, operating results, profitability, access to capital, future rate of growth and carrying value of our properties. Oil, natural gas, and NGLs are commodities, and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand.

Historically, the commodities markets have been volatile, and these markets will likely continue to be volatile in the future. The price of oil has fallen approximately $43.00 a barrel based on WTI from December 31, 2019 to the date of this Annual Report, due in part to failed OPEC negotiations as well as concerns about the COVID-19 pandemic, which has significantly decreased worldwide demand for oil. If these reduced prices continue or if prices of oil, natural gas and NGLs experience additional substantial decline, our operations, financial condition and level of expenditures for the development of our oil, natural gas and NGL reserves may continue to be materially and adversely affected. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control, including:


•	changes in global supply and demand for oil and natural gas;


•	the ability and willingness of the OPEC and non-OPEC countries, such as Russia, to set and maintain production levels and prices for oil and the other actions of OPEC;


•	the price and quantity of imports of foreign oil and natural gas;


•	political conditions, including embargoes, affecting oil-producing activity;


•	the level of global oil and natural gas exploration and production activity;


•	the level of global oil and natural gas inventories;


•	weather conditions;


•	technological advances affecting energy consumption


•	the price and availability of alternative fuels; and


•	epidemics, pandemics or other major public health issues, such as COVID-19.

Our revenues, operating results, profitability and future rate of growth depend primarily upon the prices we receive for oil and, to a lesser extent, natural gas that we sell. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. In addition, we may be required to record asset carrying value write-downs if prices remain low. The current low prices of oil and natural gas or an additional significant decline in the prices of oil and natural gas will adversely affect our financial position, financial results, cash flows, access to capital and ability to grow.

We are analyzing and evaluating strategic alternatives to address our capital structure and there can be no assurance that we will be successful in identifying, undertaking or completing any strategic alternative, that any such strategic alternative will address our capital structure and not have a negative impact on our stockholders or that the process will not have an adverse impact on our business.

In November 2019, we formed the Special Committee as part of a process to analyze and evaluate various strategic alternatives to address our capital structure and to position us for future success. The Special Committee continues to explore other financing alternatives and deleveraging transactions. The process of reviewing strategic alternatives may be time consuming and disruptive to our business operations and, if we are unable to effectively manage the process, our business, financial condition and results of operations could be adversely affected. We could incur substantial expenses associated with identifying and evaluating potential strategic alternatives. No decision has been made with respect to any strategic alternative and we cannot assure you that we will be able to identify, undertake and complete any strategic alternative that will address our capital structure and not have a negative impact on our stockholders or provide any guidance on the timing of such action, if any.

Any potential strategic alternative would be dependent upon a number of factors that may be beyond our control. We do not intend to comment regarding the evaluation of strategic alternatives until such time as we have determined that further disclosure is necessary or appropriate. As a consequence, perceived uncertainties related to our future may result in the loss of potential business opportunities and may make it more difficult for us to attract and retain qualified personnel and business partners.

Our level of indebtedness could adversely affect our ability to raise additional capital to fund our operations, limit our ability to react to changes in the economy or our industry and prevent us from meeting our obligations under our indebtedness.

We entered into the Revolving Credit Agreement in 2018. As of December 31, 2019, $115.0 million was outstanding under our Revolving Credit Agreement. As provided for in the Seventh Amendment to the Revolving Credit Agreement, and as a result of a decrease in commodity prices, on January 17, 2020, the borrowing base was decreased to $90.0 million. The reduction in the borrowing base resulted in a borrowing base deficiency of $25.0 million. We have made scheduled repayments of $17.3 million and pursuant to the Fourteenth Amendment to the Revolving Credit Agreement, the remaining $7.8 million is due on June 5, 2020.

We may incur additional debt, including secured indebtedness, or issue preferred stock in order to maintain adequate liquidity and develop and acquire properties to the extent desired. If we are able to utilize our credit facilities in the future or if we obtain additional financing, our level of indebtedness could affect our operations, including limiting our ability to obtain additional debt or equity financing for working capital, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes. Additionally, if we increase our indebtedness, the debt service requirements of the additional indebtedness could make it more difficult for us to satisfy our financial obligations; and a substantial portion of our cash flows from operations would be dedicated to the payment of principal and interest on our indebtedness and would not be available for other purposes, including our operations, capital expenditures and future business opportunities. A higher level of indebtedness and/or preferred stock also increases the risk that we may default on our obligations.

The UK’s Financial Conduct Authority, or FCA, which regulates LIBOR, stated on July 27, 2017, that following 2021 it will no longer encourage panel banks to contribute to LIBOR, as it has done to date. Borrowings under our 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. In the event LIBOR becomes unavailable prior to the maturity of our Revolving Credit Agreement, the rate of interest payable on our Revolving Credit Agreement may change. Uncertainty regarding the future of or changes to LIBOR or the unavailability of LIBOR could adversely affect our financial condition.

The Revolving Credit Agreement and Second Lien Credit Agreement, guaranteed and further secured by substantially all our assets, contain restrictive covenants that may limit our ability to respond to changes in market conditions or pursue business opportunities.

Our Revolving Credit Agreement and Second Lien Credit Agreement contain restrictive covenants that limit our ability to, among other things:


•	incur additional indebtedness;


•	create additional liens;


•	incur fundamental changes;


•	sell certain of our assets;


•	merge or consolidate with another entity;


•	pay dividends or make other distributions;


•	engage in transactions with affiliates; and


•	enter into certain swap agreements.

The requirement that we comply with these provisions may have a material adverse effect on our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.

We may from time to time enter into alternative or additional debt agreements that contain restrictive covenants that may prevent us from taking actions that we believe would be in the best interest of our business, require us to sell assets or take other actions to reduce indebtedness to meet such covenants, or make it difficult for us to successfully execute our business strategy or effectively compete with companies that are not similarly restricted.

In addition, our Revolving Credit Agreement requires us to maintain certain financial ratios. We may from time to time be out of compliance with covenants under our debt agreements, which will require us to seek waivers from our lenders. In connection with the preparation of this Annual Report and the associated financial statements, the Company became aware, and promptly informed its Lenders, that it did not satisfy the current ratio and leverage ratio covenants in the Revolving Credit Agreement, as of the fiscal quarter ended December 31, 2019. Accordingly, the Company requested that our lenders consent to a waiver with respect to such provision. On March 30, 2020, the Company entered into that certain Twelfth Amendment and Waiver to Second Amended and Restated Credit Agreement, whereby our lenders granted a waiver with respect to the breach of the leverage ratio and current ratio covenants, among other waivers of default. As of March 31, 2020, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants. Pursuant to the Fourteenth Amendment (as defined in Note 11 - Long-Term Debt), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants as of March 31, 2020. If we fail to comply with these provisions or other financial and operating covenants in the Revolving Credit Agreement, we could be in default under the terms of the agreement. In the event of such default, our lenders could elect to declare all the funds borrowed thereunder to be due and payable, together with the accrued and unpaid interest, and the lenders under or Revolving Credit Agreement could elect to terminate their commitments thereunder.

If we are unable to access additional capital, it could negatively impact our production, our income and ultimately our ability to retain our leases.

Our principal sources of liquidity historically have been equity contributions, borrowings under our credit facilities, net cash provided by operating activities, and net proceeds from the issuance of preferred stock. Our capital program may require additional financing above the level of cash generated by our operations to fund our growth. If our expected cash flow from operations decreases as a result of lower commodity prices or otherwise, our ability to expend the capital necessary to replace our proved reserves, maintain our leasehold acreage or maintain production may be limited, resulting in decreased production and proved reserves over time.

We plan to finance our capital expenditures with cash on hand, cash flow from operations and future issuances of debt and/or equity securities. Our cash flow from operations and access to capital is subject to a number of factors, including:


•	our estimated proved oil and natural gas reserves;


•	the amount of oil and natural gas we produce from existing wells;


•	the prices at which we sell our production;


•	the costs of developing and producing our oil and natural gas reserves;


•	our ability to acquire, locate and produce new reserves;


•	the ability and willingness of banks to lend to us; and


•	our ability to access the equity and debt capital markets.

Our operations and capital resources may not provide cash in sufficient funds to maintain planned or future levels of capital expenditures. Further, our actual capital expenditures in 2020 could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount of capital we have available, we could be required to seek additional sources of capital, which may include refinancing existing debt, joint venture partnerships, production payment financings, offerings of debt or equity securities or other means.

Our undeveloped leasehold acreage with expiration dates in 2020 at December 31, 2019 was 5,670 net acres and will expire if the Company does not obtain necessary funding to either extend the leases or begin drilling before their expiration dates. As a result, we have recorded an impairment of unproved leasehold of $56.2 million during the year ended December 31, 2019.

Värde Partners, Inc., its portfolio companies, and its affiliates (collectively, “Värde”) beneficially own a significant portion of our common stock. Värde is not limited in their ability to compete with us, and the waiver of the corporate opportunity provisions in the certificates of designation relating to our Series C Preferred Stock, Series D Preferred Stock, Series E Preferred Stock, and Series F Preferred Stock, may allow Värde to benefit from corporate opportunities that might otherwise be available to us. As a result, conflicts of interest could arise in the future between us and Värde concerning conflicts over our operations or business opportunities.

Värde is a family of private investment funds that beneficially owns a significant portion of our common stock as a result of the conversion rights available to them under the Series E Preferred Stock (as hereinafter defined and described). Värde also has investments in other companies in the energy industry. The certificates of designation governing the preferences, rights and limitations of the Series E Preferred Stock provide that Värde is not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. In particular, subject to the limitations of applicable law, if Värde, or any agent, shareholder, member, partner, director, officer, employee, investment manager or investment advisor of Värde who is also one of our directors or officers, becomes aware of a potential business opportunity, transaction or other matter, they will have no duty to communicate or offer that opportunity to us.

As such, Värde may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to other businesses in which they have invested, in which case those opportunities may not be available to us or may be more expensive for us to pursue. Additionally, any actual or perceived conflicts of interest with respect to the foregoing could have an adverse impact on the trading price of our common stock. As of March 5, 2019, we converted our outstanding Second Lien Loans under our Second Lien Credit Agreement to a combination of two newly created series of preferred stock, Series E convertible preferred stock (“Series E Preferred Stock”) and Series F non-convertible preferred stock (“Series F Preferred Stock”), and common stock and eliminated the conversion features and voting rights on our existing Series C Preferred Stock and Series D Preferred Stock, reducing potential dilution of our common stockholders. Our Series E Preferred Stock is convertible and, if converted, could result in dilution to our common stockholders.

Our disclosure controls and procedures and internal controls over financial reporting may not detect errors or potential acts of fraud.

Our disclosure controls and procedures and internal controls may not prevent all possible errors and fraud. A control system, no matter how well conceived and operated, can provide only reasonable assurance that the objectives of the control system are being met. In addition, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls are evaluated relative to their costs. Because of the inherent limitations in all control systems, no evaluation of our controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur without detection, which could have a material adverse effect on our business.

Failure to maintain an effective system of internal control over financial reporting may have an adverse effect on our stock price.

Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, and the rules and regulations promulgated by the SEC to implement Section 404, our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external purposes in accordance with generally accepted accounting principles. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we are required to conduct an evaluation of the effectiveness of our internal control over financial reporting based on framework of internal control issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Because of its inherent limitations, internal controls over financial reporting may not prevent or detect misstatements. In addition, projections of any evaluation effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.

Effective internal controls are necessary for us to provide reasonable assurance with respect to our financial reports and to effectively prevent fraud. If we cannot provide reasonable assurance with respect to our financial reports and effectively prevent fraud, our reputation and operating results could be harmed. Further, the complexities of our quarter-end and year-end closing processes increase the risk that a weakness in internal controls over financial reporting may go undetected. Therefore, even effective internal controls can provide only reasonable assurance with respect to the preparation and fair presentation of financial statements.

A material weakness in our internal control over financial reporting could adversely impact our ability to provide timely and accurate financial information. If we are unable to report financial information timely and accurately or to maintain effective disclosure controls and procedures, we could be subject to, among other things, regulatory or enforcement actions by the SEC and the NYSE American, including a delisting from the NYSE American, securities litigation, debt rating agency downgrades or rating withdrawals, any one of which could adversely affect the valuation of our common stock and could adversely affect our business prospects.

Decreases in oil and natural gas prices may require us to take write-downs of the carrying values of our oil and natural gas properties, potentially requiring earlier than anticipated debt repayment and negatively impacting the trading value of our securities.

Accounting rules require that we periodically review the carrying value of our oil and natural gas properties for possible impairment through the performance of a ceiling test. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties.

We perform the ceiling test at least quarterly and, in the event capitalized costs of the full cost pool exceed this ceiling, we would recognize an impairment expense. We recognized an impairment expense of approximately $228.3 million for the year ended December 31, 2019. We did not recognize an impairment expense for the year ended December 31, 2018.

Future write-downs will likely occur for reasons, including, but not limited to, continued reductions in oil and natural gas prices that lower the estimate of future net revenues from proved oil and natural gas reserves, revisions to reserves estimates, or from the addition of non-productive capitalized costs to the full cost pool that do not result in a corresponding increase in oil and natural gas reserves. Impairments of plugging and abandonment of wells in progress are other areas where costs may be capitalized into the full cost pool, without any corresponding increase in reserves values. As such, these situations could result in additional impairment expenses in the future. Impairment charges would not affect cash flow from operating activities but could have a material adverse effect on our net income and stockholders’ equity.

Our estimated reserves are based on many assumptions that may prove inaccurate. Any significant inaccuracies in our reserves estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Oil and natural gas reserves engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Any material inaccuracies in these reserves estimates or underlying assumptions could materially affect the quantities and present value of our reserves which could adversely affect our business, results of operations, and financial condition.

In order to prepare estimates, we must project production rates and the timing of development expenditures and analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Although the reserve information contained herein is reviewed by independent reserve engineers, estimates of oil and natural gas reserves are inherently imprecise.

Further, the present value of future net cash flows from proved reserves may not be the current market value of estimated oil and natural gas reserves. If our reserves estimates or the underlying assumptions prove inaccurate, it could have a negative impact on our earnings and net income, as well as the trading price of our securities.

Hedging transactions may limit our potential gains or result in losses.

In order to comply with the requirements of our Revolving Credit Agreement and to manage our exposure to price risks in the marketing of our oil and natural gas, we have entered into derivative contracts that economically hedge our oil and natural gas price on a portion of our production. These contracts may limit our potential gains if oil and natural gas prices were to rise substantially over the price established by the contract. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received; our production and/or sales of oil or natural gas are less than expected; payments owed under derivative hedging contracts come due prior to receipt of the hedged month’s production revenue; or the other party to the hedging contract defaults on its contract obligations.

Hedging transactions that we have entered into, or may enter into in the future, may not adequately protect us from declines in the prices of oil and natural gas. In addition, the counterparties under our current or future derivatives contracts may fail to fulfill their contractual obligations to us.

Our identified drilling locations are scheduled to be drilled over a period of several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of our drilling.

Our management has specifically identified and scheduled drilling locations as an estimation of future multi-year drilling activities on our existing acreage. These scheduled drilling locations represent a significant component of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability of capital, costs, drilling results, and regulatory approvals. Because of these uncertainties, we do not know if the potential drilling locations previously identified will ever be drilled or if we will be able to produce oil or natural gas from our potential drilling locations. As such, actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

Drilling for and producing oil and natural gas is a speculative activity and involves numerous risks and substantial and uncertain costs that could adversely affect us.

Our success will depend on the success of our drilling program. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities as such studies are merely an interpretive tool.

Drilling for oil and natural gas involves numerous risks, including the risk that no commercially productive natural gas or oil reservoirs will be discovered. The cost of drilling, completing, and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors beyond our control, including:


•	unexpected or adverse drilling conditions;


•	elevated pressure or irregularities in geologic formations;


•	equipment failures or accidents;


•	adverse weather conditions;


•	compliance with governmental requirements; and


•	shortages or delays in the availability of drilling rigs, crews, and equipment, including as the result shortages of personnel due to epidemics, pandemics or other major public health issues, such as COVID-19.

Additionally, the budgeted costs of planning, drilling, completing and operating wells are often exceeded and such costs can increase significantly due to various complications that may arise during the drilling and operating processes. If actual drilling

and development costs are significantly more than the current estimated costs, we may not be able to continue operations as proposed and could be forced to modify our drilling plans. A productive well may become uneconomical if water or other deleterious substances are encountered which impair or prevent the production of oil and/or natural gas from the well. Unsuccessful drilling activities could result in a significant decline in production and revenues and materially affect our operations and financial condition by reducing available cash and resources.

Financial difficulties encountered by our oil and natural gas purchasers, third-party operators or other third parties could decrease cash flow from operations and adversely affect our exploration and development activities.

We derive essentially all of our revenues from the sale of our oil, natural gas and NGLs to unaffiliated third-party purchasers, independent marketing companies and midstream companies. Any delays in payments from such purchasers caused by their financial difficulties, including those resulting from the impacts of COVID-19 and its impact on the global economy, will have an immediate negative effect on our results of operations and cash flows.

Additionally, liquidity and cash flow problems encountered by our working interest co-owners or the third-party operators of our non-operated properties may prevent or delay the drilling of a well or the development of a project. Our working interest co-owners may be unwilling or unable to pay their share of the costs of projects as they become due. In the case of a working interest owner, we could be required to pay the working interest owner’s share of the project costs.

Our industry is highly competitive, which may adversely affect our operations and performance.

We operate in a highly competitive environment. In addition to capital, the principle resources necessary for the exploration and production of oil and natural gas include: leasehold prospects under which oil and natural gas reserves may be discovered; drilling rigs and related equipment to explore for such reserves; and knowledgeable personnel to conduct all phases of oil and natural gas operations. We must compete for such resources with both major oil and natural gas companies and independent operators.

Many of our competitors have financial and other resources substantially greater than ours. The capital, materials and resources needed for our operations may not be available when needed. If we are unable to access capital, material and resources when needed, we may face various consequences, including the breach of our obligations under our oil and natural gas leases and the potential loss of those leasehold interests; damage to our reputation in the oil and natural gas community; inability to retain personnel or attract capital; a slowdown in our operations and decline in revenue; and a decline in the market price of our common stock.

Properties that we acquire may not produce oil or natural gas as projected, and we may be unable to determine reserves potential, identify liabilities associated with the properties or obtain protection from sellers against them, which could cause us to incur losses.

One of our growth strategies has been to pursue selective acquisitions of undeveloped acreage potentially containing oil and natural gas reserves. If we choose, and have the capital resources, to pursue an acquisition, we will perform a review of the target properties. However, these reviews are inherently incomplete as they are based on the quality, availability and interpretation of the reviewed data and the acumen and the assumptions of the evaluation personnel. Generally, it is not feasible to review in depth every individual property, well, facility and/or file involved in an acquisition. Even a detailed review of records and properties may not reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. We may not perform an inspection on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we may not be able to obtain effective contractual protection against all or part of those problems, and we may assume environmental and other risks and liabilities in connection with the acquired properties. If we acquire properties with risks or liabilities that were unknown or not assessed correctly, our financial condition, results of operations and cash flows could be adversely affected as claims are settled and cleanup costs related to the liabilities are incurred.

We may incur losses or costs as a result of title deficiencies in the properties in which we invest.

Prior to the drilling of an oil and natural gas well, it is customary practice in the oil and natural gas industry for the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed oil and natural gas well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and such curative work entails expense. Failure to cure any title defects may adversely impact our ability in the future to increase production and reserves. In the future, we may suffer a monetary loss from title defects or title failure. Additionally, unproved and unevaluated acreage has greater risk of title

defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest or acquire, we will suffer a financial loss which could adversely affect our financial condition, results of operations and cash flows.

Our producing properties are all located in the Delaware Basin, making us vulnerable to risks associated with operating in one major geographic area.

As of December 31, 2019, all of our estimated proved reserves were located in the Delaware Basin in Winkler, Loving, and Reeves Counties, Texas and Lea County, New Mexico. As a result of this concentration, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil or natural gas produced from the wells in this area.

In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas, which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

We may not be the operator on all of our drilling locations, and, therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated assets.

Currently, we are the operator of approximately 99% of our acreage. As we carry out our exploration and development programs, we may enter into arrangements with respect to existing or future drilling locations that result in wells being operated by others. As a result, we may have limited ability to exercise influence over the operations of the drilling locations operated by our partners. Dependence on the operator could prevent us from realizing target returns for those locations. The success and timing of exploration and development activities operated by our partners will depend on a number of factors that will be largely outside of our control and may adversely affect our financial condition and results of operation.

The marketability of our production is dependent upon transportation and processing facilities and third parties over which or whom we may have no control.

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 has impacted our ability to sell natural gas and 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, epidemics, pandemics or other major public health issues, such as COVID-19, 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. Any significant changes affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities, could delay our production, which could negatively impact our results of operations, cash flows, and financial condition.

The shut-in of our wells could negatively impact our production, liquidity, and, ultimately, our operations, results, and performance.

Our production depends, in part, upon our wells that are capable of commercial production not being shut-in (i.e., suspended from production). The lack of availability of capacity on third-party systems and facilities or the shut-in of an oil field’s production could result in the shut-in of our wells. As of December 31, 2019, we had two wells shut-in.

commodity prices in 2020 and 19 additional wells have been identified for short term shut-in through May and June. The 19 wells identified for short term shut-in are naturally flowing wells and could be turned back to sales quickly as market conditions dictate.

The producing wells in which we have an interest occasionally experience reduced or terminated production. These curtailments can result from mechanical failures, contract terms, pipeline and processing plant interruptions, market conditions, operator priorities, and weather conditions. These curtailments can last from a few days to many months, any of which could have an adverse effect on our results of operations.

If we experience low oil production volumes due to the shut-in of our wells or other mechanical failures or interruptions, it would impact our ability to generate cash flows from operations and we could experience a reduction in our available liquidity. A decrease in our liquidity could adversely affect our ability to meet our anticipated working capital, debt service, and other liquidity needs.

Unless we find new oil and natural gas reserves to replace our actual production, our reserves and production will decline, which would materially and adversely affect our business, financial condition, and results of operations.

Producing oil and natural gas reservoirs generally are characterized by declining production rates and depletion that vary depending upon various factors, including reservoir characteristics and subsurface and surface pressures. Our future oil and natural gas reserves and production and, therefore, our cash flow and revenue are highly dependent on our success in efficiently obtaining additional reserves. We may not be able to develop, find or acquire reserves to replace our current and future production at costs or other terms acceptable to us, or at all, in which case our business, financial condition and results of operations would be materially and adversely affected.

Any future plans for exploratory and development drilling are subject to drilling and completion execution risks, and drilling results may not meet our economic expectations for reserves or production.

Unconventional operations involve utilizing drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling include, but are not limited to, not reaching the desired objective due to drilling problems, not landing our wellbore in the desired drilling zone or specific target, not staying in the desired drilling zone while drilling horizontally through the formation, not running our casing the entire length of the wellbore and not being able to run tools and other equipment consistently through the horizontal wellbore. Risks that we face while completing our wells include, but are not limited to, insufficient mechanical integrity, not being able to hydraulic fracture stimulate the planned number of stages, not being able to run tools the entire length of the wellbore, improper design and engineering for the reservoir parameters, and unsuccessfully cleaning out the wellbore after completion of the final fracture stimulation stage.

The success of our drilling and completion techniques can only be developed over time as more wells are drilled and production profiles are established. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems or otherwise, the return on our investment in these areas may not be as attractive as we anticipate and we could incur material write-downs of undeveloped properties and the value of our undeveloped acreage could decline in the future.

The unavailability or high cost of drilling rigs, equipment supplies, or personnel could adversely affect our ability to execute our exploration and development plans, if and when we are able to resume drilling and completions activity.

The oil and natural gas industry is cyclical and, from time to time, there are shortages of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs of and demand for rigs, equipment and supplies may increase substantially and their availability may be limited. In addition, the demand for, and wage rates of, qualified personnel, including drilling rig crews, may rise as the number of rigs in service increases. If drilling rigs, equipment, supplies or qualified personnel are unavailable to us due to excessive costs or demand or otherwise, our ability to execute our exploration and development plans could be materially and adversely affected and, as a result, our financial condition and results of operations could be materially and adversely affected.

Terrorist attacks aimed at energy operations could adversely affect our business.

The continued threat of terrorism and the impact of military and other government action have led and may lead to further increased volatility in prices for oil and natural gas and could affect these commodity markets or the financial markets used by us. In addition, the U.S. government has issued warnings that energy assets may be a future target of terrorist organizations. These developments have subjected oil and natural gas operations to increased risks. Any future terrorist attack on our facilities, customer facilities, the infrastructure depended upon for transportation of products, and, in some cases, those of other energy companies, could have a material adverse effect on our business.

We are exposed to operating hazards and uninsured risks.

Our oil and natural gas exploration and production activities are subject to the operating risks and hazards associated with drilling for and producing oil and natural gas, including fires, explosions and blowouts; negligence of personnel; inclement weather; equipment or pipeline failure; abnormally pressured formations; and environmental pollution. These events may result in substantial losses or costs to us, including losses and costs resulting from injury or loss of life; severe damage to or destruction of property, natural resources or equipment; pollution or environmental damage; clean-up responsibilities; regulatory investigations; penalties and/or suspension of operations; or fees and other expenses incurred in the prosecution or defense of litigation relating to such events.

In accordance with customary industry practices, we maintain insurance against some, but not all, of these risks. Our insurance may not be adequate to cover all losses or liabilities. We do not carry business interruption insurance, and we cannot fully insure against pollution and environmental risks. We may elect not to carry certain types of insurance if our management believes that the cost of available insurance is excessive relative to the risks presented. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial condition and results of operations. The impact of natural disasters or weather events in the areas where we operate has resulted in escalating insurance costs and less favorable coverage terms. Losses and liabilities arising from uninsured or underinsured events may have a material adverse effect on our financial condition and operations, including the loss of our total investment in a particular prospect.

A failure of technology systems, data breach or cyberattack could materially affect our operations.

Our information technology systems may be vulnerable to security breaches, including those involving cyberattacks using viruses, worms or other destructive software, process breakdowns, phishing or other malicious activities, or any combination of the foregoing. Such breaches could result in unauthorized access to information, including customer, employee, or other confidential data. We do not carry insurance against these risks, although we do invest in security technology, perform penetration tests, and design our business processes to attempt to mitigate the risk of such breaches. However, there can be no assurance that security breaches will not occur. Moreover, the development and maintenance of these measures requires continuous monitoring as technologies change and security measures evolve. We have experienced, and expect to continue to experience, cyber security threats and incidents, none of which has been material to us to date. However, a successful breach or attack could have a material negative impact on our operations or business reputation and subject us to consequences such as litigation and direct costs associated with incident response.

Information technology solution failures, network disruptions, breaches of data security and cyberattacks could disrupt our operations by causing delays, impeding processing of transactions and reporting financial results, resulting in the unintentional disclosure of customer, employee or our information, or damage to our reputation. A system failure, data security breach or cyberattack could have a material adverse effect on our financial condition, results of operations or cash flows. In the past, we have experienced data security breaches resulting from unauthorized access to our e-mail systems, which to date have not had a material impact on our business; however, there is no assurance that such impacts will not be material in the future.

We may not be able to keep pace with technological developments in the industry.

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or competitive pressures may force us to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and, in the future, may allow them to implement new technologies before we are in a position to do so. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies used now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, the business, financial condition, and results of operations could be materially adversely affected.

We have limited management and staff and may be dependent upon partnering arrangements.

As of December 31, 2019, we had 43 full-time employees. As a result of layoffs and furloughs in response to COVID-19 and current commodity market conditions, the Company currently has 20 active employees. We leverage the services of independent consultants and contractors to perform various professional services, including engineering, oil and natural gas well planning and supervision, and land, legal, environmental, accounting and tax services. We also pursue alliances with partners in the areas of geological and geophysical services and prospect generation, evaluation and prospect leasing.

Our dependence on third-party consultants and service providers creates a number of risks, including but not limited to, the possibility that such third parties may not be available to us as and when needed and the possibility that we may not be able to properly control the timing and quality of work conducted with respect to our projects. If we experience significant delays in obtaining the services of such third parties or poor performance by such parties, our results of operations and stock price could be materially adversely affected.

Our business may suffer with the loss of key personnel or changes to our Board of Directors.

We depend to a large extent on the services of certain key management personnel and other executive officers and key employees. These individuals have extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties, marketing oil and natural gas production and developing and executing financing and hedging strategies. The loss of any of these individuals could have a material adverse effect on operations. We do not maintain key-man life insurance with respect to any of our employees. Our success will be dependent on our ability to continue to employ and retain skilled technical personnel.

We have an active board of directors that meets several times throughout the year and is intimately involved in the business and the determination of various operational strategies. Members of our board of directors work closely with management to identify potential prospects, acquisitions and areas for further development. If any directors resign or become unable to continue in their present role, it may be difficult to find replacements with the same knowledge and experience and as a result, operations may be adversely affected.

We may be subject to risks in connection with acquisitions, and the integration of significant acquisitions may be difficult.

Our business strategy is based on our ability to acquire additional reserves, oil and natural gas properties, prospects and leaseholds. If and when we are able to do this, significant acquisitions and other strategic transactions may involve risks, including:


•	diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;


•	challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of ours while carrying on our ongoing business;


•	difficulty associated with coordinating geographically separate organizations;


•	challenge of attracting and retaining capable personnel associated with acquired operations; and


•	failure to realize the full benefit that we expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition, or to realize these benefits within the expected time frame.

The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management and other staff may be required to devote considerable amounts of time to the integration process, which will decrease the time they will have to manage our business. If our senior management and staff are not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

We may face difficulties in securing and operating under authorizations and permits to drill, complete or operate our wells.

The continued growth in oil and natural gas exploration in the United States has drawn intense scrutiny from environmental and community interest groups, regulatory agencies and other governmental entities. As a result, we may face significant opposition to, or increased regulation of, our operations, that may make it difficult or impossible to obtain permits and other needed authorizations to drill, complete or operate, which could result in operational delays or otherwise make oil and natural gas exploration more costly or difficult.

Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners for use in our operations. However, Texas has endured severe drought conditions over the past several years. These drought conditions have led governmental authorities to restrict the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supplies. If we are unable to obtain water to use in our operations from local sources, we may be unable to produce oil and natural gas economically, which could have an adverse effect on our financial condition, results of operations and cash flows.

Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for oil and natural gas.

The EPA has determined that emissions of carbon dioxide, methane and other “greenhouse gases,” or “GHGs,” endanger public health and the environment because emissions of such gases are, according to the EPA, contributing to climatic changes. Based on these findings, the EPA, under the Clean Air Act, has adopted and implemented regulations to restrict emissions of greenhouse gases.

In addition, the U.S. Congress has from time to time considered adopting legislation to reduce GHG emissions and almost one-half of the states have already taken legal measures to reduce GHG emissions, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these GHG cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and natural gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal.

The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil, natural gas and NGLs we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business.

Legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations, and we routinely implement hydraulic fracturing techniques in many of our drilling and completion programs. The process is typically regulated by state oil and natural gas commissions, but the EPA, under the federal Safe Drinking Water Act (“SDWA”), has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel.

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. Additionally, local government may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in our exploration, development, or production activities, and perhaps even be precluded from drilling wells.

In addition, a number of federal agencies are analyzing, or have been requested to review, environmental issues associated with hydraulic fracturing. These types of studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.

Current water regulation relating to hydraulic fracturing, particularly water source and groundwater regulation, could result in increased operational costs, operating restrictions and delays.

Hydraulic fracturing can require between three to five million gallons of water per horizontal well. We may face regulatory concerns in both the sourcing and the discharge of water used in hydraulic fracturing.

In order to source water from the local water supply for hydraulic fracturing we may need to pay premium rates and be subject to a lower priority if the local area becomes subject to water restrictions. We may also seek water from alternative providers

supporting the hydraulic fracturing industry. If we have an insufficient water supply, we will be unable to engage in hydraulic fracturing until such supply is located.

In addition, hydraulic fracturing results in water discharges that must be treated and disposed of in accordance with applicable regulatory requirements. Environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing may increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, and all of which could have an adverse effect on operations and financial performance. Our ability to remove and dispose of water will affect production, and the cost of water treatment and disposal may affect profitability. The imposition of new environmental initiatives and regulations could also include restrictions on our ability to conduct hydraulic fracturing or disposal of produced water, drilling fluids and other substances associated with the exploration, development and production of oil and natural gas.

We are subject to numerous federal, state, local and other laws and regulations that can adversely affect the cost, manner or feasibility of doing business.

Our operations are subject to extensive federal, state and local laws and regulations relating to the exploration, production and sale of oil and natural gas. Future laws or regulations, any adverse change in the interpretation of existing laws and regulations or our failure to comply with existing legal requirements may result in substantial penalties and harm to our business and could affect our results of operations and financial condition. We may be required to make large and unanticipated capital expenditures to comply with applicable laws and governmental regulations, including regulations governing land use restrictions; lease permit restrictions; drilling bonds and other financial responsibility in connection with operations, such as plugging and abandonment bonds; well spacing; unitization and pooling of properties; safety precautions; operational reporting; eminent domain and government takings; and taxation.

Our operations could be significantly delayed or curtailed and our cost of operations could significantly increase as a result of future changes in federal, state or local laws, regulatory requirements or restrictions.

We may incur substantial expenses, and potentially resulting liabilities, to ensure our operations are in compliance with environmental laws and regulations.

Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to environmental protection, including laws and regulations relating to the release and disposal of materials into the environment. These laws and regulations, among other things, require a permit to be obtained before drilling or facility mobilization and commissioning, or injection or disposal commences; limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and impose substantial liabilities for pollution resulting from our operations.

Changes in environmental laws and regulations occur frequently and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to reach and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination or if our operations met previous standards in the industry at the time they were performed.

The Company may be adversely affected by the recent COVID-19 outbreak.

The spread of COVID-19 has caused severe disruptions in the worldwide economy, including the global demand for oil and natural gas, which has disrupted our business and operations. Moreover, since the beginning of January 2020, the COVID-19 outbreak has caused significant disruption in the financial markets both globally and in the United States. The continued spread of COVID-19 has resulted in a significant decrease in business and/or cause our oil and natural gas purchasers to be unable to meet existing payment or other obligations to us, particularly in the event of a spread of COVID-19 in our market areas. The continued spread of COVID-19 could also negatively impact the availability of our key personnel necessary to conduct our business. Such a spread could also negatively impact the business and operations of third party service providers who perform critical services for our business. If COVID-19 continues to spread or the response to contain COVID-19 is unsuccessful, we could continue to experience a material adverse effect on our business, financial condition, and results of operations.

Certain of our assets, including our oil and natural gas interests, may be or become subject to mechanic’s and materialman’s liens if we are unable to pay our oilfield service providers on a timely basis.

We enter into contracts with providers of oilfield services as part of our business. Under state laws, liens to secure payment for certain contractors and subcontractors performing certain mineral activities may be attached to certain of our assets, including our oil and natural gas interests. Due to existing economic conditions, we have been unable to, and may in the future continue to be unable to, pay certain of our oilfield service providers on a timely basis. As a result of not making such payments, certain of our assets have become subject to statutory mechanic’s and materialman’s liens, and additional statutory mechanic’s and materialman’s liens may be filed. As of the most recent date available, statutory mechanic's and materialman’s liens which remain unpaid in the amount of $8.7 million have been filed against the related assets.

Risks Relating to Our Securities

The market price of our common stock may be volatile, which may depress the market price of our securities and result in substantial losses to investors if they are unable to sell their securities at or above their purchase price.

The market price of our securities may fluctuate substantially for the foreseeable future, primarily due to a number of factors, including:


•	our status as a company with a limited operating history and limited revenues to date, which may make risk-averse investors more inclined to sell their shares on the market more quickly and at greater discounts than would be the case with the shares of a seasoned issuer in the event of negative news or lack of progress;


•	announcements of technological innovations or new products by us or our existing or future competitors;


•	the timing and development of our products;


•	general and industry-specific economic conditions;


•	actual or anticipated fluctuations in our operating results;


•	liquidity and loan covenants;


•	actions by our stockholders;


•	changes in our cash flow from operations or earnings estimates;


•	changes in market valuations of similar companies;


•	our capital commitments;


•	the sale or attempted sale or a large amount of common stock into the market;


•	the loss of any of our key management personnel; and


•	epidemics, pandemics or other major public health issues, such as COVID-19.

Many of these factors are beyond our control and may decrease the market price of our common stock, regardless of our operating performance.

We may issue shares of our preferred stock with greater rights than our common stock.

Our articles of incorporation authorize our board of directors to issue one or more series of preferred stock and set the terms of the preferred stock without seeking any further approval from our stockholders. Any preferred stock that is issued may rank ahead of our common stock, in terms of dividends, liquidation rights and voting rights. We currently have four series of preferred stock issued and outstanding, which ranks senior to our common stock with respect to dividends and rights on the liquidation, dissolution or winding up of the Company, amongst other preferences and rights.

There may be future dilution of our common stock.

We have a significant amount of derivative securities outstanding, which upon exercise or conversion, would result in substantial dilution of our common stock. To the extent outstanding restricted stock units, warrants or options to purchase our common stock under our 2016 Omnibus Incentive Plan or our 2012 Equity Incentive Plan are exercised, the price vesting triggers under the performance shares granted to our executive officers are satisfied, or additional shares of restricted stock are issued to our employees, holders of our common stock will experience dilution. Furthermore, the sale of additional equity or convertible debt securities could result in further dilution to our existing stockholders and cause the price of our outstanding securities to decline.

We do not expect to pay dividends on our common stock.

We have never paid dividends with respect to our common stock, and we do not expect to pay any dividends, in cash or otherwise, in the foreseeable future. We intend to retain any earnings for use in our business. In addition, our credit facilities and preferred stock prohibit us from paying any dividends. In the future, we may agree to further restrictions. Any return to stockholders will therefore be limited to the appreciation of their stock.

Securities analysts may not initiate coverage of our shares or may issue negative reports, which may adversely affect the trading price of the shares.

Securities analysts may not provide research reports on our Company. If securities analysts do not cover our Company, the lack of coverage may adversely affect the trading price of our shares. The trading market for our shares will rely in part on the research and reports that securities analysts publish about us and our business. If one or more of the analysts who cover our Company downgrades our shares, the trading price of our shares may decline. If one or more of these analysts ceases to cover our Company, we could lose visibility in the market, which, in turn, could also cause the trading price of our shares to decline. Further, because of our small market capitalization, it may be difficult for us to attract securities analysts to cover our Company, which could significantly and adversely affect the trading price of our shares.

Anti-takeover effects of certain provisions of Nevada state law hinder a potential takeover of our Company.

The existence of certain provisions under Nevada law could delay or prevent a change in control of the Company, which could adversely affect the price of our common stock. Additionally, Nevada law imposes certain restrictions on mergers and other business combinations between us and any holder of 10% or more of our outstanding common stock.

We are currently not in compliance with the NYSE American listing standards. If our common stock is delisted, the market price and liquidity of our common stock and our ability to raise additional capital would be adversely impacted.

Our common stock is currently listed on the NYSE American. Continued listing of a security on the NYSE American is conditioned upon compliance with various continued listing standards. On November 21, 2019, we received a deficiency letter (the “First Deficiency Letter”) from the NYSE American stating that we were below compliance with the continued listing standards as set forth in Section 1003(a)(i)-(iii) of the NYSE American Company Guide (the “Company Guide”) because we had reported a stockholders’ equity deficiency as of September 30, 2019 and net losses in our five most recent fiscal years ended December 31, 2018. On December 3, 2019 we received another deficiency letter (the “Second Deficiency Letter” and, together with the First Deficiency Letter, the “Deficiency Letters”) from the NYSE American stating we were below compliance with the continued listing standards as set forth in Section 1003(f)(v) of the Company Guide because our common stock had been selling for a low price per share for a substantial period of time. The Second Deficiency Letter stated that we must effect a reverse stock split of our common stock or otherwise demonstrate sustained price improvement no later than June 3, 2020.

The Deficiency Letters had no immediate effect on our listing on the NYSE American and, therefore, our common stock will continue to be listed on the NYSE American, subject to our compliance with other continued listing requirements of the NYSE American. On December 20, 2019, we submitted a plan of compliance to the NYSE American addressing how we intend to regain compliance with Sections 1003(a)(i)-(iii) of the Company Guide by May 21, 2021. On February 7, 2020, the Company received a letter from the NYSE American stating that our compliance plan has been accepted and that we have been granted a plan period through May 21, 2021.

By May 21, 2021, we must either be in compliance or must have made progress that is consistent with the plan during the plan period. In addition, during the plan period, we must provide quarterly updates to the NYSE American concurrent with our interim and annual SEC filings. Failure to meet the requirements to regain compliance could result in the initiation of delisting proceedings.

The Deficiency Letters do not affect our business operations or our reporting obligations under the rules and regulations of the SEC, nor do the Deficiency Letters conflict with or cause an event of default under any of the Company’s material agreements.

If we cannot meet the NYSE American continued listing requirements by the end of our compliance period, 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 3. Legal Proceedings

We may from time to time be involved in various legal actions arising in the normal course of business. However, we do not believe there is any currently pending litigation that could have, individually or in the aggregate, a material adverse effect on our results of operations or financial condition.

Item 4. Mine Safety Disclosures

Not applicable.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market Information

Our common stock trades on the NYSE American under the symbol “LLEX.”

Holders

As of April 30, 2020, there were 107 holders of record of our common stock.

Dividend Policy

Holders of shares of preferred stock are entitled to receive cumulative preferential dividends, payable and compounded quarterly in arrears. Dividends on our preferred stock are payable, at the Company’s option, (i) in cash, (ii) in kind, or (iii) in a combination thereof. In 2019, we did not pay cash dividends on our outstanding preferred stock. For the year ended December 31, 2019, the paid-in-kind dividends is $25.4 million. See Note 15 - Preferred Stock to our consolidated financial statements included in this Annual Report.

We have never paid cash dividends on our common stock and do not anticipate paying dividends in the foreseeable future. Our current business plan is to retain any future earnings to finance the expansion and development of our business. Any future determination to pay cash dividends will be at the discretion of our Board of Directors, and will be dependent upon our financial condition, results of operations, capital requirements and other factors as our Board of Directors may deem relevant at that time.

Recent Sales of Unregistered Securities

None

Equity Compensation Plan Information

The following table summarizes information regarding the number of shares of our common stock that are available for issuance under all of our existing equity compensation plans as of December 31, 2019:

໿



Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights (a)	Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights (b)	Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (excluding securities reflected in column (a)) (c)
Equity compensation plans approved by security holders	3,588,350	4.05	5,372,127
Equity compensation plans not approved by security holders	—	—	—
Total	3,588,350	4.05	5,372,127

For additional information regarding the Company’s benefit plans and share-based compensation expense, see Note 17 - Share Based and Other Compensation to our consolidated financial statements.

Item 6. Selected Financial Data

As a smaller reporting company, we are not required to provide the information required by this Item 6.

Item 7. 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 our consolidated financial statements and related notes included elsewhere in this Annual Report. The following discussion includes forward-looking statements, including, without limitation, statements relating to our plans, strategies, objectives, expectations, intentions and resources. Our actual results could differ materially from those discussed in these forward-looking statements as a result of many factors, including those discussed under “Risk Factors” and elsewhere in this 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 “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 more than 1,000 future drilling locations.

As of December 31, 2019, we were fully drawn against the borrowing base under our Revolving Credit Agreement (as defined in Note 11 - Long-Term Debt to our consolidated financial statements), with $115 million of indebtedness outstanding under our Revolving Credit Agreement. As provided for in the Seventh Amendment to our Revolving Credit Agreement and as a result of a decrease in commodity prices, on January 17, 2020, the borrowing base was decreased to $90.0 million. The reduction in the borrowing base resulted in a borrowing base deficiency of $25.0 million. We have made scheduled repayments of $17.3 million and pursuant to the Fourteenth Amendment to our Revolving Credit Agreement, the remaining $7.8 million is due on June 5, 2020. Refer to Note 11 - Long-Term Debt to our consolidated financial statements for additional information. Our next borrowing base redetermination is scheduled to occur on or around June 5, 2020. If the borrowing base is further reduced by the lenders in connection with this redetermination, we will be required to repay borrowings in excess of the borrowing base as we do not have sufficient additional oil and natural gas properties to eliminate the borrowing base deficiency by pledging additional oil and natural gas properties to secure our obligations under the Revolving Credit Agreement. Under the Revolving Credit Agreement, we have the option to affect such repayment either in full within 30 days after the redetermination or in monthly installments over a six-month period after the redetermination.

Our liquidity and ability to comply with debt covenants under our Revolving Credit Agreement have been negatively impacted by the recent decrease in commodity prices, which have fallen approximately $43.00 a barrel based on WTI from December 31, 2019 to the date of this Annual Report, due in part to failed OPEC negotiations as well as concerns about the COVID-19 pandemic, which has significantly decreased worldwide demand for oil and natural gas. Our Revolving Credit Agreement contains financial covenants requires the Company to maintain a ratio of Total Debt to EBITDAX (each as defined in the Revolving Credit Agreement) (the “Leverage Ratio”) of not more than 4.00 to 1.00 and a ratio of Current Assets to Current Liabilities (each as defined in the Revolving Credit Agreement) (the “Current Ratio”) of not less than 1.00 to 1.00 as of the last day of each fiscal quarter thereafter. See Note 11 - Long-term Debt to our consolidated financial statements for additional information regarding the financial covenants under our Revolving Credit Agreement. As of December 31, 2019, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants. Pursuant to the Twelfth Amendment (as defined in Note 11 - Long-Term Debt to our consolidated financial statements), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants as of December 31, 2019.

In order to improve our liquidity, leverage position and current ratio to meet the financial covenants under the Revolving Credit Agreement, we are currently pursuing or considering a number of actions, which in certain cases may require the consent of current lenders and stockholders. In November 2019, our board of directors formed a Special Committee tasked with reviewing and evaluating strategic alternatives that may enhance the value of the Company, including alternatives that may be available to identify and access further sources of liquidity through financing alternatives or deleveraging transactions. The Special Committee hired financial and legal advisors to advise the Special Committee on these matters.

The Special Committee continues to explore financing alternatives and deleveraging transactions. We are also addressing operational matters such as adjusting our capital budget and improving cash flows from operations by continuing to reduce costs, and intend to continue to pursue and consider other strategic alternatives.

There can be no assurance that we will be able to implement any of these plans successfully, or that such plans, if executed, will result in the ability to pay borrowing base deficiencies, generate sufficient liquidity or comply with our Revolving Credit Agreement covenants. These factors raise substantial doubt about our ability to continue as a going concern within twelve-month period following the date of issuance of these consolidated financial statements.

2019 Operational and Financial Highlights


•	Increased our net sales production by 3% to 5,102 BOE/d, for 2019 as compared to 2018, despite planned well shut-ins and temporary suspensions of our drilling and completions program throughout 2019. Net sales production for 2019 of 5,102 BOE/d was consistent with guidance for the year.

•

Significantly reduced general and administrative expenses 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 23%. These efforts contributed to reductions of general and administrative expenses by 15% for the year ended December 31, 2019 when compared to the year ended December 31, 2018.


•	Reduced general and administrative expenses per BOE by 17% for 2019 as compared to 2018


•	Reduced our crude transportation costs per Bbl by 85% from $5.15 per Bbl in January and February 2019, to $0.75 per Bbl beginning in March 2019 through year-end, resulting in a 2019 weighted average crude transportation cost of $1.49 per Bbl. This resulted in a total annual crude transportation cost savings of $3.0 million in 2019 versus 2018.


•	Reduced our saltwater disposal costs by 25% to approximately $1.93 per Bbl as of December 2019 through our sales agreements and access to infrastructure.


•	Increased saltwater disposal capacity through third party access by 380% to 46,600 bbl/d, compared to 2018.


•	Added seasoned oil and gas professionals to our operations and land departments.


•	Significantly reduced our cycle times by reducing average drilling days for longer lateral wells (> 1.5 miles) from approximately 45 days (spud to total depth) to approximately 17 days.


•	Successfully completed 7 gross wells (5.4 net) during 2019, despite temporary suspensions in the Company’s drilling and completions program.


•	Reduced average drilling costs per well by 26% compared to wells drilled by previous operations management in 2018.


•	Secured necessary power commitments to begin full electrification of our Texas field and currently in the process of securing the necessary power commitments for our New Mexico field.


•	Received 2-year extended flaring permits to mitigate the need for future shut-ins associated with regulatory flaring compliance and have implemented solutions for delivering all produced natural gas to sales by the end of the second quarter of 2020.


•	Received three drilling permits from the Bureau of Land Management in New Mexico. In addition, the Company has 13 submitted permits in various stages of review.


•	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


•	Realized oil pricing of 91% of WTI for 2019 versus 82% of WTI as compared to 2018.


•	Achieved commodity volume mix of 73% Liquids, including 61% crude oil, resulting in 95% of revenue attributable to Liquids sales during 2019

2020 Updates


•	Brought additional capital of $24.1 million into the Company through the sale of certain undeveloped leasehold assets in New Mexico.


•	Successfully installed gas treating system on certain well locations and are now in the final stages of testing the treated gas that will flow to sales. We anticipate all treated natural gas production to be flowing to sales during the second quarter of 2020.


•	In 2020, the Company has entered into the Seventh Amendment through the Fourteenth Amendment to the Revolving Credit Agreement which, among other things, amended the following (Refer to Note 11 - Long-Term Debt for additional information):


•	Reduced our borrowing base to $90.0 million, resulting in a borrowing base deficiency of $25.0 million,


•	Extended the due date for the final borrowing base deficiency payment to June 5, 2020, and


•	Waived compliance with the Leverage Ratio and Current Ratio covenants as of December 31, 2019 and March 31, 2020.

The Company has also implemented an employee furlough program to further reduce general and administrative costs. The furloughed employees will not receive compensation from the Company during the furlough period; however, subject to local regulations, these employees will be eligible for unemployment benefits. The furlough period is uncertain at this time and will be reassessed as business conditions dictate.

Access to Infrastructure

We entered into an amendment to our previously negotiated water gathering and disposal agreement and entered into a new crude oil sales contract to support the sales of our production of Liquids and natural gas, including transportation and sales agreements and salt water gathering and disposal agreements. We believe these agreements secure us cost effective movement of our Liquids and natural gas production in Texas and Mexico. Our agreements and relationships with SCM and ARM also provide the company with optionality in production storage capacity and down-stream transportation capacity.

Market Conditions and Commodity Pricing

Our financial results depend on many factors, including the price of oil, natural gas and NGLs and our ability to market our production on economically attractive terms. We generate the majority of our revenues from sales of Liquids and, to a lesser extent, sales of natural gas. The price of these products are critical factors to our success and volatility in these prices could impact our results of operations. In addition, our business requires substantial capital to acquire properties and develop our non-producing properties. The price of oil, natural gas and NGLs have fallen significantly since the beginning of 2020, due in part to failed OPEC negotiations and to concerns about the COVID-19 pandemic, which has significantly decreased worldwide demand for oil and natural gas. This significant decline and any further declines in the price of oil, natural gas and NGLs have reduced our revenues and result in lower cash inflow which have made it more difficult for us to pursue our plans to acquire new properties and develop our existing properties. Such declines in oil, natural gas, and NGL prices also adversely affect our ability to obtain additional funding on favorable terms.

Commodity prices continued to significantly decrease during first quarter 2020, through the date of filing. As of March 31, 2020, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants and received a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants as of March 31, 2020.

Results of Operations – For the Years Ended December 31, 2019 and 2018

Current Operations Update

During the year ended December 31, 2019, seven horizontal wells were placed on production. As of December 31, 2019, we have 41 gross operated wells, of which 30 horizontal wells and 9 legacy vertical wells were producing and flowing to sales. We received three drilling permits from the Bureau of Land Management in New Mexico and are nearing completion on several additional New Mexico permits.

To enhance performance, the Company has installed artificial lift on select wells. Currently, eleven wells have been placed on artificial lift.

In July 2019, 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 facility upgrades necessary for the crude oil treating implementation has been completed and our third-party crude gathering system is currently capable of flowing treated crude to all receipt points. The natural gas treating solution continues to be advanced and began delivering treated natural gas, that was previously being flared, to sales in the first quarter of 2020.

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. Due to ongoing matters involving construction and use of the gathering system, we have not been able to use the system as expected, which has delayed our realization of efficiencies in getting our production to sales and has increased our transportation costs on sales.

Sales Volumes and Revenues

The following table sets forth selected revenue and sales volume data for the years ended December 31, 2019 and 2018:



	Years Ended December 31,
	2019		2018		Variance			%
Net sales volume:
Oil (Bbl)	1,130,855		1,089,724		41,131			4	%
Natural gas (Mcf)	3,063,927		2,855,739		208,188			7	%
NGL (Bbl)	220,832		246,425		(25,593		)	(10	)%
Total (BOE)	1,862,342		1,812,106		50,236			3	%
Average daily sales volume (BOE/d)	5,102		4,965		137			3	%
Average realized sales price:
Oil ($/Bbl)	$	52.19	$	53.26	$	(1.08	)	(2	)%
Natural gas ($/Mcf)	1.04		1.84		(0.80		)	(44	)%
NGL ($/Bbl)	17.52		28.11		(10.59		)	(38	)%
Total ($/BOE)	$	35.47	$	38.75	$	(3.28	)	(8	)%
Oil, natural gas and NGL revenues (in thousands):
Oil revenue	$	59,015	$	58,042	$	973		2	%
Natural gas revenue	3,180		5,246		(2,066		)	(39	)%
NGL revenue	3,868		6,928		(3,060		)	(44	)%
Total revenue	$	66,063	$	70,216	$	(4,153	)	(6	)%

Total sales volume increased 3% to 1,862,342 BOE during the year ended December 31, 2019, compared to 1,812,106 BOE during 2018, an increase of 50,236 BOE. The increase in total sales volume was primarily due to 7 gross (5.4 net) additional wells placed on production since the third quarter of 2018. Total revenue decreased $4.2 million to $66.1 million for the year ended December 31, 2019, as compared to $70.2 million for the year ended December 31, 2018, representing a 6% decrease. The decrease was primarily attributable to lower realized prices partially offset by increased volumes.

Operating Expenses

The following table shows a comparison of operating expenses for the years ended December 31, 2019 and 2018:



	Years Ended December 31,
	2019		2018		Variance			%
Operating Expenses per BOE:
Production costs	$	8.66	$	7.64	$	1.02		13	%
Gathering, processing and transportation	2.13		1.87		0.26			14	%
Production taxes	1.77		2.05		(0.28		)	(14	)%
General and administrative	15.23		18.35		(3.12		)	(17	)%
Depreciation, depletion, amortization and accretion	17.85		14.00		3.85			28	%
Impairment of oil and natural gas properties	122.60		—		122.60			100	%
Total operating expenses per BOE	$	168.24	$	43.91	$	124.33		283	%

Operating Expenses (in thousands):
Production costs	$	16,127	$	13,843	$	2,284		16	%
Gathering, processing and transportation	3,960		3,392		568			17	%
Production taxes	3,302		3,709		(407		)	(11	)%
General and administrative	28,371		33,251		(4,880		)	(15	)%
Depreciation, depletion, amortization and accretion	33,252		25,367		7,885			31	%
Impairment of oil and natural gas properties	228,324		—		228,324			100	%
Total operating expenses	$	313,336	$	79,562	$	233,774		294	%

Production Costs

Production costs increased by $2.3 million, or 16%, to $16.1 million for the year ended December 31, 2019, compared to $13.8 million for the year ended December 31, 2018, due, in part, to the 7 gross (5.4 net) increase in producing wells during 2019. Our production costs on a per BOE basis increased by $1.02, or 13%, to $8.66 for the year ended December 31, 2019, as compared to $7.64 per BOE for the year ended December 31, 2018. The increase in production costs per BOE was primarily the result of increased equipment rentals related to artificial lift and workover charges.

Gathering, Processing and Transportation

Gathering, processing and transportation costs increased by $0.6 million to $4.0 million for the year ended December 31, 2019, compared to $3.4 million for the year ended December 31, 2018. This cost increase was primarily the result of higher sales volumes of natural gas. The cost on a per BOE basis increased 14% from $1.87 for the year ended December 31, 2018, to $2.13 for the year ended December 31, 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 $0.4 million to $3.3 million for the year ended December 31, 2019, compared to $3.7 million for the same period in 2018. On a per BOE basis, production taxes decreased to $1.77 per BOE for the year ended December 31, 2019, a 14% decrease from the $2.05 per BOE for the year ended December 31, 2018, primarily due to lower revenue for 2019 as compared to 2018.

General and Administrative Expenses (“G&A”)

G&A decreased by $4.9 million to $28.4 million for the year ended December 31, 2019, as compared to $33.3 million for the year ended December 31, 2018. The decrease of $4.9 million in G&A was primarily attributable to a decrease in stock-based compensation of $2.5 million, a decrease in personnel costs of $1.0 million including severance costs and directors fees, and a $1.4 million decrease in professional services.

Depreciation, Depletion, Amortization and Accretion (“DD&A”)

DD&A expense was $33.3 million for the year ended December 31, 2019, compared to $25.4 million for the year ended December 31, 2018; resulting in an increase of $7.9 million, or 31%. Our DD&A rate increased by 28% to $17.85 per BOE during the year ended December 31, 2019 from $14.00 per BOE for the year ended December 31, 2018. To a smaller degree, DD&A expense increased as a result of a 3% increase in sales volumes for the year ended December 31, 2019 as compared to the year ended December 31, 2018. The increase was primarily due to a net increase of proved oil and natural gas net book value, prior to impairment, and a 71% decrease in total proved reserves volumes on a BOE basis.

Impairment of Oil and Natural Gas Properties

The Company recorded charges for impairment of oil and natural gas properties of $228.3 million for the year ended December 31, 2019. The net book value of the Company’s oil and natural gas properties exceeded the ceiling limitation calculated as required under the full cost method of accounting at December 31, 2019 and September 30, 2019. December 31, 2019 discounted future net cash flows and proved reserves volumes decreased 63% and 71%, respectively, from our December 31, 2018 proved reserves report. As a result of the uncertainty in our ability to fund future development costs associated with proved undeveloped reserves, all proved undeveloped reserves were reclassified to unproved. The reclassification represented nearly 23%, or $75.3 million, of the decrease in discounted future net cash flows and approximately 50% of the decrease in proved volumes, or 21,487 MBOE. Oil and natural gas pricing, calculated as required by the SEC, decreased approximately 16% from December 31, 2018 as compared to December 31, 2019. Proved reserve volumes reported in the December 31, 2019 proved reserves report were over 20%, or 8,699 MBOE, lower due to the decrease in pricing. Discounted future net cash flows decreased more than 40%, or $131.5 million, as a result of the decrease in pricing used in estimating proved reserves.

Other Income (Expenses)

The following table shows a comparison of other expenses for the years ended December 31, 2019 and 2018:



	Years Ended December 31,
	2019			2018			Variance			%
	(In Thousands)
Other income (expense):
Loss on early extinguishment of debt	$	(1,299	)	$	(20,370	)	$	19,071		(94	)%
Gain (Loss) from commodity derivatives, net	(8,985		)	55			(9,040		)	(16,436	)%
Change in fair value of financial instruments	(3,573		)	58,343			(61,916		)	(106	)%
Interest expense	(11,426		)	(32,827		)	21,401			(65	)%
Other income	435			2			433			21,650	%
Total other income (expenses)	$	(24,848	)	$	5,203		$	(30,051	)	(578	)%

Loss on Early Extinguishment of Debt

In 2019, the Company repurchased certain overriding royalty interests in the acreage previously sold under the ORRI Agreement (as defined in Note 5 - Acquisitions and Divestitures to our consolidated financial statements), resulting in a $1.3 million loss on extinguishment of a portion of the financing arrangement.

On October 10, 2018, we converted approximately $68.3 million of our Second Lien Credit Agreement into a combination of 39,254 shares of Series D Preferred Stock, stated value of $1,000 per share, and 5,952,763 shares of common stock. As a result, we recorded a loss of approximately $12.3 million on early extinguishment of debt. Concurrently, we executed the Revolving Credit Agreement, from which we received proceeds of $60.0 million that were used to pay off the outstanding balance of the Riverstone First Lien Credit Agreement totaling $57.0 million, including accrued interest and prepayment penalties. As a result

of the prepayment of the Riverstone First Lien Credit Agreement, we recorded a loss of approximately $8.1 million on early extinguishment of debt.

Gain (Loss) from Commodity Derivatives, net

Loss on our commodity derivatives increased by $9.0 million during the year ended December 31, 2019, resulting primarily from changes in underlying commodity prices as compared to the hedged prices within derivative instruments and the monthly settlement of those instruments. Additionally, during the year ended December 31, 2019, our net loss from commodity derivatives consisted primarily of net losses of $3.4 million from settled positions and $5.6 million from mark-to-market adjustments on unsettled positions. During the year ended December 31, 2018, our net loss from commodity derivatives consisted primarily of net losses of $1.9 million from settled positions and $2.0 million from mark-to-market adjustments on unsettled positions.

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 to our consolidated financial statements). 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 to our consolidated financial statements).

As of December 31, 2019, we recognized an embedded derivative associated the ARM sales agreement as the agreement no longer meets the criteria for the “normal purchase normal sales” exception under ASC 815, “Derivatives and Hedging”, due to the Company not meeting the minimum quantities deliverable under the contract and the net settlement criteria being met (see Note 21 - Commitments and Contingencies to our consolidated financial statements). Upon recognition, we recorded a loss of $3.2 million on the embedded derivative.

Interest Expense

Interest expense for the year ended December 31, 2019 was $11.4 million compared to $32.8 million for the year ended December 31, 2018. For the year ended December 31, 2019, interest expense included $6.5 million from the Revolving Credit Agreement, $1.6 million of PIK interest, $0.9 million from financing arrangements, $1.7 million related to amortization of the debt discount on our Second Lien Term Loan and $0.8 million for amortization debt issuance costs. For the year ended December 31, 2018, we incurred interest expense of $32.8 million, which included $3.0 million for quarterly interest payments on notes payable and term loans, $12.2 million of PIK interest, $14.4 million related to amortization of debt discount on our Second Lien Term Loan and $3.2 million for amortization debt issuance costs. The Second Lien Term Loan was converted to common and preferred stock in March 2019, and, as a result, there was less paid-in-kind interest and amortization of debt discount during the 2019 period.

Going Concern 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. Our ability to fund planned capital expenditures and to make acquisitions depends upon commodity prices, our future operating performance, availability of borrowings under our Revolving Credit Agreement, and more broadly, on the availability of equity and debt financing, which is affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control. The Company has negative working capital, a history of net operating losses and cash flows used in operations. We cannot predict whether additional liquidity from equity or debt financings or borrowings under our Revolving Credit Agreement will be available on acceptable terms, or at all, in the foreseeable future.

From time to time, we raise capital through the sale of oil and natural gas properties that are not in our current drilling plans. 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. We may continue to enter into such sales in the future.

During the year ended December 31, 2019, we exchanged and converted 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 7.8 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 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, commodity prices and the lending policies of our lenders. We currently have four wells drilled and awaiting completion (referred to as “DUC” wells) that, when and if completed, would add to our current production cash flows in 2020.

As of December 31, 2019, we were fully drawn against the borrowing base under our Revolving Credit Agreement (as defined in Note 11 - Long-Term Debt to our Consolidated Financial Statements), with $115 million of indebtedness outstanding under our Revolving Credit Agreement. As provided for in the Seventh Amendment to our Revolving Credit Agreement and as a result of a decrease in commodity prices, on January 17, 2020, the borrowing base was decreased to $90.0 million.

As a result of the January 17, 2020 redetermination of the borrowing base, a borrowing base deficiency in the amount of $25 million (the “Borrowing Base Deficiency”) was created under the Revolving Credit Agreement. The Borrowing Base Deficiency constitutes the difference between the principal amount of borrowings currently outstanding under the Revolving Credit Agreement, $115 million, and the borrowing base as so redetermined, $90 million. On February 28, 2020, we paid $17.25 million towards the Borrowing Base Deficiency. Pursuant to the Fourteenth Amendment to the Revolving Credit Agreement, the remaining payment of $7.8 million is due June 5, 2020.

The Company is seeking additional funding and considering certain strategic transactions to enable it to pay the remaining Borrowing Base Deficiency amount of $7.8 million. There is no assurance, however, that funding or additional transactions will be completed or that the bank group will agree to further deficiency payment extensions. If the Company is unable to repay the remaining borrowing base deficiency as and when required under the Revolving Credit Agreement, an event of default would occur under the Revolving Credit Agreement.

Our next borrowing base redetermination is scheduled to occur on or about June 5, 2020. If the borrowing base is further reduced by the lenders in connection with this redetermination, we will be required to repay borrowings in excess of the borrowing base as we do not have sufficient additional oil and natural gas properties to eliminate the borrowing base deficiency by pledging additional oil and natural gas properties to secure our obligations under the Revolving Credit Agreement. Under the Revolving Credit Agreement, we have the option to affect such repayment either in full within 30 days after the redetermination or in monthly installments over a six-month period after the redetermination.

Our liquidity and ability to comply with debt covenants under our Revolving Credit Agreement have been negatively impacted by the recent decrease in commodity prices, which have fallen significantly since the beginning of 2020, due in part to failed OPEC negotiations as well as concerns about the COVID-19 pandemic, which has significantly decreased worldwide demand for oil and natural gas. Our Revolving Credit Agreement contains financial covenants that require the Company to maintain a ratio of Total Debt to EBITDAX (each as defined in the Revolving Credit Agreement) (the “Leverage Ratio”) of not more than 4.00 to 1.00 and a ratio of Current Assets to Current Liabilities (each as defined in the Revolving Credit Agreement) (the “Current Ratio”) of not less than 1.00 to 1.00 as of the last day of each fiscal quarter thereafter. See Note 11-Long-term Debt to our consolidated financial statements for additional information regarding the financial covenants under our Revolving Credit Agreement. As of December 31, 2019, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants under the Revolving Credit Agreement. Pursuant to the Twelfth Amendment (as defined in Note 11 - Long-Term Debt to our consolidated financial statements), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants as of December 31, 2019.

prices have been volatile, and may be subject to wide fluctuations in the future. Furthermore, the Company has negative working capital, a history of net operating losses and cash flows use in operations. If continued depressed prices persist, the Company will continue to experience operating losses, negative cash flows from operating activities, and negative working capital.

In order to improve our leverage position and current ratio to meet the financial covenants under the Revolving Credit Agreement, we are currently pursuing or considering a number of actions, which in certain cases may require the consent of current lenders and stockholders. In November 2019, our board of directors formed a Special Committee tasked with reviewing and evaluating strategic alternatives that may enhance the value of the Company, including alternatives that may be available to identify and access further sources of liquidity. The Special Committee hired financial and legal advisors to advise the Special Committee on these matters.

The Special Committee continues to explore financing alternatives and deleveraging transactions. We are also addressing operational matters such as adjusting our capital budget and improving cash flows from operations by continuing to reduce costs and intend to continue to pursue and consider other strategic alternatives.

There can be no assurance that we will be able to implement any of these plans successfully, or that such plans, if executed, will result in the ability to pay borrowing base deficiencies, generate sufficient liquidity to continue as a going concern or comply with our Revolving Credit Agreement covenants. These factors raise substantial doubt about our ability to continue as a going concern within twelve-month period following the date of issuance of these consolidated financial statements.

Our ability to fund our future operations, including drilling and completion capital expenditures, will largely be dependent upon our active management of our drilling and completion budget, and, if necessary, the 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 2020 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, until necessary funding is obtained, to focus on production and facilities optimization while the results and performance of the new wells are evaluated. In response to our efforts to strengthen our capital through reducing operating costs, during April 2020 the Company elected to shut-in 12 wells which were identified as uneconomic as a result of the continued decline in commodity prices in 2020 and 19 additional wells have been identified for short term shut-in through May and June. The 19 wells identified for short term shut-in are naturally flowing wells and could be turned back to sales quickly as market conditions dictate. 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.

Information about our cash flows for the years ended December 31, 2019 and 2018, are presented in the following table (in thousands):



	Years Ended December 31,
	2019			2018
Cash provided by (used in):
Operating activities	$	(25,824	)	$	92,132
Investing activities	(65,527		)	(242,935		)
Financing activities	73,967			154,478
Net change in cash and cash equivalents	$	(17,384	)	$	3,675

Operating Activities

For the year ended December 31, 2019, net cash used in operating activities was $25.8 million, compared to net cash provided by operating activities of $92.1 million for the year ended December 31, 2018. The $25.8 million used in operating activities was primarily made up of net loss of $272.1 million, non cash adjustments to net income of $282.5 million, and cash used by change in working capital of $36.2 million, primarily the result of payments of accounts payable outstanding at December 31, 2018.

Investing Activities

For the year ended December 31, 2019, net cash used in investing activities was $65.5 million, compared to $242.9 million for the same period in 2018. The $65.5 million in cash used for investing activities during the year ended December 31, 2019, was primarily attributable to the following:


•	cash payments of approximately $82.4 million for capital expenditures on oil and gas properties; partially offset by


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

Capital Expenditure Breakdown

During the year ended December 31, 2019, drilling and completion capital cost incurred was $93.1 million, comprised of $36.7 million on 2018 DUC wells and $40.3 million related to the 2019 drilling program, plus an additional $3.7 million related to the 2018 drilling program and $10.8 million for facility and water supply and disposal projects. Of the capital cost incurred on 2018 DUC wells, adjustments to Lilis’ working interests due to non-consent elections increased capital costs by $7.5 million while reducing accounts receivable from other working interest partners by that amount.

At December 31, 2019, we had four DUC wells compared to six DUC wells at December 31, 2018. Although additional costs were incurred on all six DUC wells during 2019, four wells were placed on production during 2019. Those four wells included the Oso #1H, Haley #1H, Haley #2H, and NE Axis #2H. In addition, three wells were drilled, completed and placed on production during the fourth quarter of 2019, those being the Kudu A#2H, Kudu B#2H and Grizzly A#2H.

During the second half of 2019, 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. If and when the Company obtains the capital required to do so, the Company expects to incorporate these improved techniques on all future wells with the goal of achieving similar cost savings.



	Year Ended December 31,
	2019		2018
Leasehold Acquisitions
Proved	$	—	$	20,040
Unproved	1,643		98,193
2017 Drilling & Completion Program	—		12,440
2018 Drilling & Completion Program	3,658		119,350
2018 Drilling & Completion Program-DUCs	36,738		24,887
2018 Working Interest Acquisitions	—		1,293
2019 Drilling & Completion Program	40,263		—
Facilities & Other Projects	10,824		9,484
Total Capital Spending	$	93,126	$	285,687

Financing Activities

For the year ended December 31, 2019, net cash provided by financing activities was $74.0 million compared to cash provided by financing activities of $154.5 million during the same period in 2018. The $74.0 million in net cash provided by financing activities included $56.9 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 (as defined in Note 5 - Acquisitions and Divestitures to our consolidated financial statements), offset by repayment of $18.0 million on the Revolving Credit Agreement.

Capital Structure

Revolving Credit Agreement

On October 10, 2018, we entered into a five-year, $500 million senior secured revolving credit agreement (the “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 provides for a senior secured reserves based revolving credit facility with an initial borrowing base of $95 million and also provides for issuance of letters of credit in an aggregate amount up to $5 million. The borrowing base is subject to semiannual redetermination in May and November of each year.

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.

The Revolving Credit Agreement matures on the earlier of the fifth anniversary of the closing date and the date that is 180 days prior to the maturity date of the Second Lien Credit Agreement (as defined below). Borrowings under the Revolving Credit Agreement are subject to mandatory repayment with the net proceeds of 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.

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 of not more than 4.00 to 1.00 and a ratio of current assets to current liabilities of not less than 1.00 to 1.00 (each as defined in the Revolving Credit Agreement).

As of December 31, 2019, the Company was not in compliance with the Current Ratio covenant or Leverage Ratio covenant under the Revolving Credit Agreement (as defined and described in Note 11 - Long-Term Debt to our consolidated financial statements). Pursuant to the Twelfth Amendment (as defined in Note 11 - Long-Term Debt to our consolidated financial statements), the Company obtained a waiver from the requisite lenders of its compliance with the Current Ratio and Leverage Ratio covenant, among other waivers, as of December 31, 2019.

Seventh Amendment to Revolving Credit Agreement

On January 17, 2020, the Company entered into a Seventh Amendment (the “Seventh Amendment”) to the Revolving Credit Agreement. The Seventh Amendment provided for the January 14, 2020 redetermination of the borrowing base under the Revolving Credit Agreement (the “Scheduled Redetermination”). As so redetermined, the borrowing base was set at $90 million. As a result of the Scheduled Redetermination, a borrowing base deficiency in the amount of $25 million existed under the Revolving Credit Agreement (the “Borrowing Base Deficiency”). The Seventh Amendment required repayment of the Borrowing Base Deficiency in four equal monthly installments, with the first payment of $6.25 million scheduled to occur on January 24, 2020.

Eighth Amendment to Revolving Credit Agreement

On January 23, 2020, the Company entered into an Eighth Amendment (the “Eighth Amendment”) to the Revolving Credit Agreement. The Eighth Amendment, among other things, amended the Revolving Credit Agreement to provide that the due date for the first Installment Payment was extended from January 24, 2020 to February 7, 2020 and that the due dates for the subsequent Installment Payments were February 14, 2020, March 16, 2020 and April 14, 2020.

Ninth Amendment to Revolving Credit Agreement

On February 6, 2020, the Company entered into an Ninth Amendment (the “Ninth Amendment”) to the Revolving Credit Agreement. The Ninth Amendment amended the Revolving Credit Agreement to provide that the due date for the first Installment Payment was extended from February 7, 2020 to February 18, 2020 and the due date for the second Installment Payment was extended from February 14, 2020 to February 18, 2020. The due dates for the two subsequent Installment Payments remained March 16, 2020 and April 14, 2020.

Tenth Amendment to Revolving Credit Agreement

On February 14, 2020, the Company entered into an Tenth Amendment (the “Tenth Amendment”) to the Revolving Credit Agreement. The Tenth Amendment amended the Revolving Credit Agreement to provide that the due date for the first two Installment Payments was extended from February 18, 2020 to February 28, 2020 and the due dates for the two subsequent Installment Payments remained March 16, 2020 and April 14, 2020.

Eleventh Amendment to Revolving Credit Agreement

On March 13, 2020, the Company entered into an Eleventh Amendment (the “Eleventh Amendment”) to the Revolving Credit Agreement. The Eleventh Amendment amended the Revolving Credit Agreement to extend the due date for the $1.50 million installment of the Borrowing Base Deficiency from March 16, 2020 to March 30, 2020. The due date for the final installment of the Borrowing Base Deficiency remained April 14, 2020.

Twelfth Amendment to Revolving Credit Agreement

On March 30, 2020, the Company entered into an Twelfth Amendment (the “Twelfth Amendment”) to the Revolving Credit Agreement. The Twelfth Amendment amended the Revolving Credit Agreement to, among other things extend the due date for the $1.50 million installment of the Borrowing Base Deficiency from March 30, 2020 to April 14, 2020. The due date for the final installment of the Borrowing Base Deficiency remains April 14, 2020. The lenders under the Revolving Credit Agreement also waived the requirement under the Revolving Credit Agreement that the Company comply with a leverage ratio and a current ratio, in each case, as of December 31, 2019, and granted certain other waivers, including the requirement to comply with certain hedging obligations set forth in the Revolving Credit Agreement until June 30, 2020. Additionally, the lenders consented to an extension of an additional 45 days for the Company to provide its audited annual financial statements for the fiscal year ended December 31, 2019, and waived the requirement that such financial statements be delivered without a “going concern” or like qualification or exception.

Thirteenth Amendment to Revolving Credit Agreement

On April 14, 2020, the Company entered into a Thirteenth Amendment (the “Thirteenth Amendment”) to the Revolving Credit Agreement. The Thirteenth Amendment amended the Revolving Credit Agreement to extend the due date for the final $7.75 million installment of the Borrowing Base Deficiency from April 14, 2020 to April 21, 2020.

Fourteenth Amendment to Revolving Credit Agreement

On April 21, 2020, the Company entered into a Fourteenth Amendment (the “Fourteenth Amendment”) to the Revolving Credit Agreement. The Fourteenth Amendment, among other things, amended the Revolving Credit Agreement to extend the due date for the final $7.75 million installment of the Borrowing Base Deficiency from April 21, 2020 to June 5, 2020. The lenders under the Revolving Credit Agreement also waived the requirement under the Revolving Credit Agreement that the Company comply with a leverage ratio and a current ratio, in each case, as of March 31, 2020. Additionally, the lenders consented to defer the timing of the scheduled spring redetermination of the borrowing base under the Revolving Credit Agreement from on or about May 1, 2020 to on or about June 5, 2020.

Second Lien Credit Agreement

On April 26, 2017, the Company entered into a second lien credit agreement, dated as of April 26, 2017, by and among the Company, certain subsidiaries of the Company, as guarantors (the “Guarantors”), Wilmington Trust, National Association, as administrative agent (the “Agent”), and the lenders party thereto (the “Lenders”), including Värde, as amended (the “Second Lien Credit Agreement”) comprised of convertible loans in an aggregate initial principal amount of up to $125 million in two tranches. The first tranche consisted of an $80 million term loan (the “Second Lien 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 (the “Delayed Draw Term Loan”

and, together with the Second Lien Term Loan, the “Second Lien Loans”). The Second Lien Term Loan was subsequently converted into common stock and preferred stock in two separate transactions on October 2018 and March 2019 as described below.

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

On October 10, 2018, 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, the Company entered into a transaction by and among the Company and certain private funds affiliated with the Värde Parties, pursuant to which the Company agreed to issue to the Värde Parties an aggregate of 5,952,763 shares of the Company’s common stock, par value $0.0001 per share, which includes 5,802,763 shares of common stock at an exchange price of $5.00 per share of common stock plus an additional 150,000 shares of common stock, and 39,254 shares of a newly created series of preferred stock of the Company, designated as “Series D 8.25% Convertible Participating Preferred Stock” (the “Series D Preferred Stock”);

On March 5, 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, the Company 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.

See Note 13 - Related Party Transactions and Note 15 - Preferred Stock to our consolidated financial statements for additional information about Related Party Transactions and the Company’s Preferred Stock.

Related Party Transactions

On March 5, 2019, pursuant to the 2019 Transaction Agreement and the related payoff letter, the Company agreed to issue to the Värde Parties shares of two new series of its preferred stock and shares of its common stock, as consideration for the termination of the Second Lien Credit Agreement with the Värde Parties and the satisfaction in full, in lieu of repayment in cash, of the Second Lien Term Loan under the Second Lien Credit Agreement. See Note 11 - Long-Term Debt and Note 15 - Preferred Stock to our consolidated financial statements for additional information.

On July 31, 2019, the Company entered into two agreements with affiliates of Värde for the sale of an overriding royalty interest and a non-operated working interest in undeveloped assets. WLR’s (as defined in Note 5 - Acquisitions and Divestitures to our consolidated financial statements) proportionate share of revenue of $0.4 million for the year ended December 31, 2019 is included in interest expense on the Company’s consolidated statements of operations. Three of the properties included in the WI Agreement were producing as of December 31, 2019 and net revenue (revenue less production costs) of $0.5 million is included in interest expense on the Company’s consolidated statements of operations. See Note 5 - Acquisitions and Divestitures to our consolidated financial statements for additional information.

On August 16, 2019, the Company entered into an agreement with an affiliate of Värde to repurchase the overriding royalty interest for the New Mexico acreage sold. See Note 5 - Acquisitions and Divestitures to our consolidated financial statements for additional information.

On April 21, 2020, Värde Investment Partners, L.P., an affiliate of Värde Partners, Inc., became a lender under our Revolving Credit Agreement by acquiring, from a prior lender, loans and commitments under the Revolving Credit Agreement in the principal amount of approximately $25.7 million. The loans and commitments acquired by Värde Investment Partners, L.P. are subject to certain subordination provisions set forth in the Revolving Credit Agreement, as amended by the Fourteenth Amendment thereto dated April 21, 2020. For additional information regarding our Revolving Credit Agreement, as amended, see Note 11 - Long-Term Debt to our consolidated financial statements included in this Annual Report and “Item 7 - Management’s

Discussion and Analysis of Financial Condition and Results of Operations - Revolving Credit Agreement” in Part II of this Annual Report.

Subsequent Events

Sale of Certain Undeveloped Acreage in New Mexico

On February 28, 2020, the Company closed the sale of approximately 1,185 undeveloped net acres in Lea County, New Mexico, for net cash proceeds of approximately $24.1 million, subject to customary purchase price adjustments. The proceeds were used to fund a substantial portion of the Borrowing Base Deficiency with the balance to be used for general corporate purposes.

COVID-19

On January 30, 2020, the World Health Organization (“WHO”) announced a global health emergency due to the COVID-19 outbreak, which originated in Wuhan, China, and the risks to the international community as the virus spreads globally beyond its point of origin. In March 2020, the WHO classified the COVID-19 outbreak as a pandemic, based on the rapid increase in exposure globally.

In addition, in March 2020, members of OPEC failed to agree on production levels which has caused an increased supply and has led to a substantial decrease in oil prices and an increasingly volatile market. The oil price war ended with a deal to cut global petroleum output but did not go far enough to offset the impact of COVID-19 on demand. There has been an increase in supply which has pushed prices down further since March. If the depressed pricing continues for an extended period it will lead to i) further reductions in the borrowing base under our credit facility which would require us to make additional borrowing base deficiency payments, ii) reductions in reserves, and iii) additional impairment of proved and unproved oil and gas properties. We also expect disclosures of supplemental oil and gas information to be impacted by price declines.

In response to recent commodity prices and our efforts to strengthen our capital through reducing operating costs,during April 2020 the Company elected to shut-in 12 wells which were identified as uneconomic as a result of the continued decline in commodity prices in 2020 and 19 additional wells have been identified for short term shut-in through May and June. The 19 wells identified for short term shut-in are naturally flowing wells and could be turned back to sales quickly as market conditions dictate. The Company has also implemented an employee furlough program to further reduce general and administrative costs. The furloughed employees will not receive compensation from the Company during the furlough period; however, subject to local regulations, these employees will be eligible for unemployment benefits. The furlough period is uncertain at this time and will be reassessed as business conditions dictate.

The full impact of the COVID-19 outbreak and the decline in oil prices continues to evolve as of the date of this Annual Report. As such, it is uncertain as to the full magnitude that these events will have on the Company’s financial condition, liquidity, and future results of operations.

Management is actively monitoring the global situation on its financial condition, liquidity, operations, suppliers, industry, and workforce. Given the daily evolution of the COVID-19 outbreak and the global responses to curb its spread, the Company is not able to estimate the effects of the COVID-19 outbreak on its results of operations, financial condition, or liquidity for fiscal year 2020.

These matters could have a continued material adverse impact on economic and market conditions and trigger a period of global economic slowdown, which may impair the Company’s asset values, including reserve estimates. Further, consumer demand has decreased since the spread of the outbreak and new travel restrictions placed by governments in an effort to curtail the spread of the coronavirus. Although the Company cannot estimate the length or gravity of the impacts of these events at this time, if the pandemic and/or decreased oil prices continue, they will have a material adverse effect on the Company’s results of future operations, financial position, and liquidity in fiscal year 2020.

Coronavirus Aid, Relief, and Economic Security Act

On March 27, 2020, President Trump signed into law the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”). The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer side social security payments, net operating loss carryback periods, alternative minimum tax credit refunds, modifications to the net interest deduction limitations, increased limitations on qualified charitable contributions, and technical corrections to tax depreciation methods for qualified improvement property.

It also appropriated funds for the SBA Paycheck Protection Program loans that are forgivable in certain situations to promote continued employment, as well as Economic Injury Disaster Loans to provide liquidity to small businesses harmed by COVID-19. There is no assurance we are eligible for these funds or will be able to obtain them.

We continue to examine the impact that the CARES Act may have on our business. Currently, we are unable to determine the impact that the CARES Act will have on our financial condition, results of operations, or liquidity.

Effects of Inflation and Pricing

The oil and gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry puts pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Material changes in prices impact the current revenue stream, estimates of future reserves, borrowing base calculations of bank loans and the value of properties in purchase and sale transactions. Material changes in prices, such as those experienced to date in 2020, can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel. We anticipate business costs will vary in accordance with commodity prices for oil and natural gas, and the associated increase or decrease in demand for services related to production and exploration.

Off-Balance Sheet Arrangements

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

Commitments and Contractual Obligations

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



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

⁽¹⁾ Extending to the later of December 2024 or 5 years from the EPIC Crude Oil pipeline in-service date (February 2025).

Further, ARM has agreed to purchase crude from the Company based upon Magellan East Houston pricing with a fixed “differential basis”. As of December 31, 2019, the agreement no longer meets the criteria for the “normal purchase normal sales” exception under ASC 815, “Derivatives and Hedging”, due to the Company not meeting the minimum quantities deliverable under the contract and the net settlement criteria being met. See Note 9 - Derivatives to our consolidated financial statements for information regarding the recognition of the net settlement mechanism as an embedded derivative over the remainder of the contract.

Critical Accounting Policies and Estimates

The preparation of our consolidated financial statements in conformity with generally accepted accounting principles in the United States (“GAAP”) requires our management to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities at the date of our financial statements and the reported amounts of revenues and expenses during the reporting period. The following is a summary of the significant accounting policies and related estimates that affect our financial disclosures.

Critical accounting policies are defined as those significant accounting policies that are most critical to an understanding of a company’s financial condition and results of operation. We consider an accounting estimate or judgment to be critical if (i) it

requires assumptions to be made that were uncertain at the time the estimate was made, and (ii) changes in the estimate or different estimates that could have been selected could have a material impact on our results of operations or financial condition.

Use of Estimates

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

Oil and Natural Gas Reserves

We follow the full cost method of accounting. All of our oil and natural gas properties are located within the United States and, therefore, all costs related to the acquisition and development of oil and natural gas properties are capitalized into a single cost center referred to as a full cost pool. Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and natural gas reserves. Under the full cost method of accounting, capitalized oil and natural gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves less the future cash outflows associated with the asset retirement obligations that have been accrued on the balance sheet plus the cost, or estimated fair value if lower, of unproved properties. Should capitalized costs exceed this ceiling, impairment would be recognized. Under the applicable SEC rules, we prepared our oil and natural gas reserves estimates as of December 31, 2019, using the average, first-day-of-the-month price during the 12-month period ended December 31, 2019.

Estimating accumulations of oil and natural gas is complex and is not exact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserves estimate is a function of the quality and quantity of available data; the interpretation of that data; the accuracy of various mandated economic assumptions; and the judgment of the persons preparing the estimate.

We believe estimated reserves quantities and the related estimates of future net cash flows are among the most important estimates made by an exploration and production company such as ours because they affect the perceived value of our Company, are used in comparative financial analysis ratios, and are used as the basis for the most significant accounting estimates in our financial statements, including the quarterly calculation of depletion, depreciation and impairment of our proved oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas, and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. We determine anticipated future cash inflows and future production and development costs by applying benchmark prices and costs, including transportation, quality and basis differentials, in effect at the end of each quarter to the estimated quantities of oil and natural gas remaining to be produced as of the end of that quarter. We reduce expected cash flows to present value using a discount rate that depends upon the purpose for which the reserves estimates will be used. For example, the standardized measure calculation requires us to apply a 10% discount rate. Although reserves estimates are inherently imprecise and estimates of new discoveries and undeveloped locations are more imprecise than those of established proved producing oil and natural gas properties, we make considerable effort to estimate our reserves, including through the use of independent reserves engineering consultants. We expect that quarterly reserves estimates will change in the future as additional information becomes available or as oil and natural gas prices and operating and capital costs change. We evaluate and estimate our oil and natural gas reserves as of December 31, and quarterly throughout the year. For purposes of depletion, depreciation, and impairment, we adjust reserves quantities at all quarterly periods for the estimated impact of acquisitions and dispositions. Changes in depletion, depreciation or impairment calculations caused by changes in reserves quantities or net cash flows are recorded in the period in which the reserves or net cash flow estimate changes.

Oil and Natural Gas Properties-Full Cost Method of Accounting

We use the full cost method of accounting whereby all costs related to the acquisition and development of oil and natural gas properties are capitalized into a single cost center referred to as a full cost pool. These costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling, and overhead charges directly related to acquisition and exploration activities.

Capitalized costs, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves as determined by independent petroleum engineers. For this purpose, we convert our petroleum products and reserves to a common unit of measurement.

Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. This undeveloped acreage is assessed quarterly to ascertain whether impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to the amortization base and becomes subject to the depletion calculation.

Proceeds from the sale of oil and natural gas properties are applied against capitalized costs, with no gain or loss recognized, unless the sale would alter the rate of depletion by more than 25%. Royalties paid, net of any tax credits received, are netted against oil and natural gas sales.

Under the full cost method of accounting, capitalized oil and natural gas property costs, less accumulated depletion and net of deferred income taxes, may not exceed an amount equal to the present value using the preceding 12-months’ average price based on closing prices on the first day of each month, adjusted for price differentials, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves, plus the cost, or estimated fair value if lower, of unproved properties. Should capitalized costs exceed this ceiling, we would recognize impairment.

Subsequent to December 31, 2019, commodity prices declined significantly, which we expect to significantly reduce the undiscounted expected cash flows from our proved reserves. Declines in commodity prices used for our full cost ceiling test will result in additional impairments of our proved properties during 2020. If there are significant delays in the completion of our drilling program due to capital constraints resulting from current market conditions, we will lose a portion of our acreage through lease expirations that will result in impairments recorded throughout 2020 related to those expirations.

Derivative Instruments

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

The Company has recognized certain conversion features within its Second Lien Term Loan as embedded derivatives that have been bifurcated from the Second Lien Term Loan, as defined in Note 11 - Long-Term Debt to our consolidated financial statements in Item 16 of this Annual Report on Form 10-K and accounted for separately from the debt.

The Company has recognized our crude oil sales agreement with ARM no longer meets the criteria for the “normal purchase normal sales” exception under ASC 815, “Derivatives and Hedging”, due to the Company not meeting the minimum quantities deliverable under the contract and the net settlement criteria being met. As a result, an embedded derivative exists as it is no longer probable the contract will only result in physical deliveries of crude oil and may not settle. See Note 9 - Derivatives to our consolidated financial statements in Item 16 of this Annual Report on Form 10-K.

Revenue Recognition

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

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

Income Taxes

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

The Company recognizes its tax benefits only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely to be realized upon settlement. A liability for “unrecognized tax benefits” is recorded for any tax benefits claimed that do not meet these recognition and measurement standards. As of December 31, 2019 and 2018, the Company has determined that no liability is required to be recognized.

The Company’s policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense. No interest or penalties were required to be accrued at December 31, 2019 and 2018. Further, the Company does not expect that the total amount of unrecognized tax benefits will significantly increase or decrease during the next 12 months.

Recently Issued Accounting Pronouncements

For a discussion of recently adopted accounting standards and recent accounting standards not yet adopted, see “Note 3 - Basis of Presentation and Summary of Significant Accounting Policies” to our Consolidated Financial Statements in Item 16 of this Annual Report.

Item 7A. 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 year ended December 31, 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. 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.

During the year ended December 31, 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 in the period ranged from a low of $0.24 per gallon to a high of $0.56 per gallon. Natural gas prices during the period 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 price of oil and natural gas has fallen significantly since the beginning of 2020, due in part to OPEC negotiations as well as concerns about the COVID-19 pandemic and its impact on the worldwide economy and global demand for oil and gas. The resulting precipitous decline in oil and gas pricing experienced during March 2020 and through the date of this Annual Report, if prolonged, or a further deterioration of the market price for oil and natural gas will further negatively impact our ability to continue to operate as a going concern.

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 December 31, 2019, we had $115.0 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 $9.1 million at December 31, 2019, and through actual and accrued receivables from our joint interest partners of approximately $9.5 million at December 31, 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 year ended December 31, 2019, sales to three customers, ARM Energy Management, LLC, Texican Crude & Hydrocarbon, LLC, and Lucid Energy Delaware, LLC, accounted for approximately, 68%, 19% and 12% of our revenue, respectively.

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.

Item 8. Financial Statements and Supplementary Data

Our financial statements appear immediately after the signature page of this Annual Report and are incorporated herein by reference. See “Index to Financial Statements” included in this Annual Report.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the Exchange Act. Internal control over financial reporting is an integral component of the Company’s disclosure controls and procedures. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon their evaluation, our Chief Executive Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2019.

Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Exchange Act). Our internal control structure is designed to provide reasonable assurance to our management and board of directors regarding the reliability of our financial reporting and the preparation and fairness of our financial statement preparation in accordance with U.S. generally accepted accounting principles.

Our management, with the participation of our Chief Executive Officer assessed the effectiveness of our internal control over financial reporting, as of December 31, 2019, based on the criteria for effective internal control over financial reporting established in “Internal Control - Integrated Framework (2013)” which is issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment and those criteria, our management determined that our internal control over financial reporting was effective as of December 31, 2019.

Changes in Internal Control Over Financial Reporting

There was no change in our internal control over financial reporting during the year ended December 31, 2019, that materially affected or is reasonably likely to materially affect our internal control over financial reporting.

Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The following table sets forth the names, ages and positions of the persons who are our directors and executive officers as of April 30, 2020:



Name	Age	Position
Michael G. Long	67	Chairman of the Board of Directors
Nuno Brandolini	66	Director
John Johanning	34	Director
Markus Specks	35	Director
Nicholas Steinsberger	56	Director
Joseph C. Daches	53	Chief Executive Officer, President and Chief Financial Officer

Directors hold office for a period of one year from their election at the annual meeting of stockholders and until a particular director’s successor is duly elected and qualified. Officers are elected by, and serve at the discretion of, our Board of Directors (the “Board” or the “Board of Directors”). None of the above individuals has any family relationship with any other individual listed above.

Below are summaries of the background and business experience, attributes, qualifications and skills of the current directors and executive officers of the Company:

Michael G. Long: Chairman of the Board of Directors. Mr. Long joined our Board on April 10, 2018 and has served as Chairman of the Board since March 2020. Mr. Long is an experienced financial executive with over 35 years of experience in oil and gas related management, corporate finance, capital markets, risk management and strategic planning activities for both private and public oil and gas companies. Mr. Long previously served as the Executive Vice President and Chief Financial Officer for Sanchez Energy Corporation and privately held Sanchez Oil and Gas Corporation and its affiliates. Mr. Long also held the positions of EVP and CFO of Edge Petroleum Corporation and Vice President of Finance for W&T Offshore.

Director Qualifications:

Leadership Experience - Served as Executive Vice President and Chief Financial Officer of Sanchez Energy Corporation, Executive Vice President and Chief Financial Officer of Edge Petroleum Corporation, and Vice President of Finance for W&T Offshore.

Industry Experience - Extensive experience in corporate finance, capital markets, risk management and strategic planning activities.

Nuno Brandolini: Director. Mr. Brandolini joined our Board in February 2014 and served as Chairman of the Board from April 2014 until January 2016 when Mr. Ormand was appointed as Chairman of our Board. Mr. Brandolini served as a member of the general partner of Scorpion Capital Partners, L.P., a private equity firm organized as a small business investment company, until June 2014. Prior to forming Scorpion Capital and its predecessor firm, Scorpion Holding, Inc., in 1995, Mr. Brandolini served as managing director of Rosecliff, Inc., a leveraged buyout fund co-founded by Mr. Brandolini in 1993. Mr. Brandolini served previously as a vice president in the investment banking department of Salomon Brothers, Inc., and a principal with the Batheus Group and Logic Capital, two venture capital firms. Mr. Brandolini began his career as an investment banker with Lazard Freres & Co. Mr. Brandolini is a director of Cheniere Energy, Inc. (NYSE American: LNG), a Houston-based company primarily engaged in LNG related businesses. Mr. Brandolini received a law degree from the University of Paris and an M.B.A. from the Wharton School.

Director Qualifications:

Leadership Experience - Executive positions with several private equity firms, and Board position with Cheniere Energy, Inc.

Industry Experience - Serves on the Board of Cheniere Energy, Inc., as well as has personal investments in the oil and gas industry.

John Johanning: Director. Mr. Johanning joined our Board in March 2018. Mr. Johanning was designated as a director by the Värde Parties pursuant to a Securities Purchase Agreement dated January 30, 2018, and he was appointed to our Board in March 2018. Mr. Johanning is the Technical Director of Värde Partners, Inc.’s (“Värde”) energy business. Mr. Johanning joined Värde in May 2017 and presides over the Petroleum Engineering and Geoscience aspects of Värde’s investments in energy. Mr. Johanning is involved in the performance of current Värde investments across active onshore US basins as well as new business decisions in both opportunity screening and asset and company valuations. Prior to joining Värde, from January 2014 until May 2017, Mr. Johanning was a Vice President at Evercore Partners (“Evercore”) in Houston, Texas, where he was influential in numerous transactions totaling over $10 billion in transaction value. While at Evercore, Mr. Johanning advised numerous energy companies and financial sponsors on value-maximizing transactions. Mr. Johanning’s advisory mandates ranged over a variety of different transaction types including acquisitions and divestitures of assets, corporate mergers, and capital raises. Mr. Johanning also worked across all oilfield sectors, gaining transactional experience in the upstream, midstream, downstream and oilfield service sectors of the business. Mr. Johanning began his career as a Reservoir Engineer at BP from 2008 to 2014. Based in Houston, he developed oil and gas assets across several US Basins, including the Permian of West Texas and Southeast New Mexico and the Texas Gulf Coast Basin, among others. While on the South Texas Reservoir Management team, Mr. Johanning was responsible for the resource appraisal of a 400,000+ gross acre Eagle Ford Shale position that was deeply rooted in geological and well completion data. While at BP, Mr. Johanning gained a detailed technical understanding of oil and gas assets through the various facets of the business, including Production Engineering, Reservoir Engineering, Drilling and Completions, Geology and Geophysics, as well as Land, Legal and Finance functions. Mr. Johanning graduated from The University of Texas in at Austin in 2008 with a B.S. in Petroleum Engineering.

Director Qualifications:

Leadership Experience - Served as Vice President at Evercore Partners and currently presides over the Petroleum Engineering and Geoscience aspects of Värde Partners, Inc. as the Technical Director.

Industry Experience - Possesses particular knowledge and experience in the operations of oil and gas companies and has transactional experience in the upstream, midstream, downstream and oil field service sectors of the business, including acquisitions and divestitures of assets, corporate mergers, and capital raises.

Markus Specks: Director. Mr. Specks joined our Board in March 2018. Mr. Specks was designated as a director by the Värde Parties pursuant to a Securities Purchase Agreement dated January 30, 2018, and he was appointed to our Board in March 2018. Mr. Specks is a Managing Director of Värde Partners, Inc. and Head of the firm’s Houston office. Mr. Specks leads Värde’s energy business and has experience managing credit, equity, and structured asset-level investments across the energy sector. He serves on Värde’s Investment Committee as well as several boards of private energy companies. Prior to joining Värde in 2008, Mr. Specks worked in investment banking at Lazard, focusing on middle-market M&A advisory. Mr. Specks holds a B.A. in Government from Lawrence University in Wisconsin.

Director Qualifications:

Leadership Experience - Managing Director of Värde Partners, Inc. and Head of the firm’s Houston office.

Industry Experience - Possesses particular knowledge and experience in developing companies and capital markets, particularly with oil and gas companies.

Nicholas Steinsberger: Director. Mr. Steinsberger joined our Board on May 3, 2018. He is currently COO and Managing Director of ValPoint Operating, a small private equity backed company working in western Oklahoma. Mr. Steinsberger is a highly experienced petroleum engineer and global expert in shale drilling and completions who pioneered the use of slick water fracing. He began his career with Mitchell Energy and served as the Completion Manager for Mitchell from 1995 to 2002, where he piloted the Company’s fracking technique and developed the slick water frac, pioneering the current oil and gas shale boom. Mr. Steinsberger then served as the Completion Manager for Devon Energy after Devon’s acquisition of Mitchell Energy. In 2005, he founded Steinsberger Tight Gas Consulting, where he has drilled and completed wells in the Barnett, Fayetteville, Woodford, Wolfcamp, Utica, Bakken and Marcellus Shales. Mr. Steinsberger is regarded as an expert in the field of unconventional well completion and is responsible for the drilling and completion of over 1,000 wells in his career. He holds a B.S. in Petroleum Engineering from the University of Texas.

Director Qualifications:

Leadership Experience - COO and Managing Director of ValPoint Operating; Founder, President and CEO of Steinsberger Tight Gas Consulting.

Industry Experience - Possesses significant knowledge regarding technical aspects of drilling and completions and is also very active in the oil and gas industry.

Joseph C. Daches: Chief Executive Officer. Mr. Daches was appointed Chief Executive Officer of the Company on November 13, 2019. He was Chief Financial Officer and Treasurer of Lilis since January 23, 2017, and President of Lilis since August 16, 2018. Mr. Daches has more than 25 years’ experience in management and working with boards of directors, banks and attorneys, primarily within the energy industry. Mr. Daches has helped guide several oil and gas companies through financial strategy activities, capital raises, and both public and private offerings. Mr. Daches possesses significant business experience and knowledge related to the oil and gas industry, including A&D transactions, oil and gas reporting, SEC reporting, corporate governance and compliance, budgeting and business valuations. Prior to joining the Company, Mr. Daches held the position of CFO at MHR, where he concluded his tenure by successfully guiding MHR through a restructuring and upon emergence was appointed Co-CEO by the new board of directors. Prior to joining MHR, Mr. Daches served as Executive Vice President and Chief Accounting Officer of Energy & Exploration Partners, Inc. since September 2012 and as a director of that company since April 2013. He previously served as a partner and Managing Director of the Willis Consulting Group, LLC, from January 2012 to September 2012. From October 2003 to December 2011, Mr. Daches served as the Director of E&P Advisory Services at Sirius Solutions, LLC, where he was primarily responsible for financial reporting, technical and oil and gas accounting, and the overall management of the E&P advisory services practice. Mr. Daches earned a Bachelor of Science in Accounting from Wilkes University in Pennsylvania, and he is a certified public accountant in good standing with the Texas State Board of Public Accountancy.

Corporate Governance

The Board of Directors and Committees

Our Board conducts its business through meetings and through its committees. Our Board held eight meetings in 2019 and took action by unanimous written consent on six occasions. Each director attended at least 75% of (i) the meetings of the Board held after such director’s appointment and (ii) the meetings of the committees on which such director served, after being appointed to such committee. Our policy regarding directors’ attendance at the annual meetings of stockholders is that all directors are expected to attend, absent extenuating circumstances. In 2019, we had two directors attend our Annual Meeting.

Board Leadership Structure

The Board selected Mr. Long to hold the position of Chairman of the Board on March 12, 2020. Mr. Long’s experience in the industry and various executive leadership roles has afforded him intimate knowledge of the issues, challenges and opportunities facing the Company.

The Board’s Role in Risk Oversight

It is management’s responsibility to assess and manage risk and bring to the Board’s attention any material risks to our Company. While our management team is responsible for assessing and managing material risks, our Board and Board committees generally oversee risk management. The Board also has oversight responsibility for our risk policies and processes relating to the financial statements and financial reporting processes and the guidelines, policies and processes for mitigating those risks.

Corporate Governance Guidelines

Our Board has developed and adopted Corporate Governance Guidelines to establish a common set of expectations to assist our Board and its committees in performing their duties. The Corporate Governance Guidelines provide guidance to our directors on various subjects, including our directors’ responsibilities, director qualification standards, director compensation, and access to management and independent advisors. A copy of our Corporate Governance Guidelines is available on our website at www.lilisenergy.com under “Investor Relations - Corporate Governance.”

Committees of the Board of Directors

Pursuant to our bylaws, our Board is permitted to establish committees from time to time as it deems appropriate. To facilitate independent director review and to make the most effective use of our directors’ time and capabilities, our Board has

established an Audit Committee and a Special Committee. The membership and principal functions of these committees are described below.

In connection with the resignation of certain directors, effective as of April 15, 2020, our Board does not have a standing Nominating and Corporate Governance Committee or a standing Compensation Committee.

Audit Committee

Currently, our Audit Committee consists of Mr. Long, who is the chairman of the Audit Committee, and Mr. Brandolini. Our Board of Directors determined that each of Mr. Long and Mr. Brandolini are independent as required by NYSE American for audit committee members. In addition, our Board of Directors determined that Mr. Long meets the requisite SEC criteria to qualify as an audit committee financial expert. The Audit Committee met five times during the year ended December 31, 2019, and acted by written consent once.

The Audit Committee selects, compensates and evaluates an independent public accounting firm to act as the Company’s independent auditors, as well as any other necessary registered public accounting firms. In addition, the Audit Committee reviews all critical accounting policies and practices to be used in the Company’s audit and reviews all alternative treatments of financial information within generally accepted accounting principles. The Audit Committee also reviews with management and our independent auditors any major issues regarding accounting principles and financial statement presentation and any significant financial reporting issues and judgments. Under its charter, the Audit Committee monitors compliance with our Code of Business Conduct.

The Audit Committee is governed by a written charter that is reviewed, and amended if necessary, on an annual basis. A copy of the charter is available on our website at www.lilisenergy.com under “Investor Relations - Corporate Governance.”

Consideration and Determination of Executive and Director Compensation

Our Board does not currently have a standing Compensation Committee. Due to the reduced size of the Board following the resignations of three directors, effective as of April 15, 2020, the Board determined that it would be appropriate for the Compensation Committee to be dissolved and for the responsibilities of the Board’s former Compensation Committee to be assigned to its directors that meet the independence standards of the NYSE American LLC. As such, Mr. Long, Mr. Brandolini, Mr. Johanning and Mr. Specks, as the four independent members of the Board, participate in the consideration of officer and director compensation.

The independent members of the Board review, approve and modify our executive compensation program, plans and awards provided to our directors, executive officers and key employees. The independent members of the Board also review and approve short-term and long-term incentive plans and other stock or stock-based incentive plans. In addition, the independent members of the Board review our compensation and benefit philosophy, plans and programs on an as-needed basis. In reviewing our compensation and benefits policies, the independent members of the Board may consider the recruitment, development, promotion, retention and compensation of our executive and senior officers; trends in management compensation; and any other factors that it deems appropriate.

The independent members of the Board, at least annually, review and approve the corporate goals and objectives applicable to the compensation of the Company’s CEO, evaluates the CEO’s performance in light of those goals and objectives, and determine and approve the CEO’s compensation level based on the evaluation. The CEO is not permitted to be present during any Board deliberations or voting with respect to his compensation. The independent members of the Board also, at least annually, review and approve the annual base salaries and incentive opportunities of the executive officers (other than the CEO) and review and approve all other incentive awards and opportunities, including both cash-based and equity based awards and opportunities.

Consideration of Director Nominees

Our Board does not currently have a standing Nominating and Corporate Governance Committee. Due to the reduced size of the Board following the resignations of three directors, effective as of April 15, 2020, the Board determined that it would be appropriate for the Nominating and Corporate Governance Committee to be dissolved and for the responsibilities of the Board’s former Nominating and Corporate Governance Committee to be assigned to its directors that meet the independence standards of the NYSE American LLC. As such, Mr. Long, Mr. Brandolini, Mr. Johanning and Mr. Specks, as the four independent members of the Board, participate in the consideration of director nominations.

The primary responsibilities of the independent members of the Board with respect to director nominations include identifying, evaluating and recommending, for the approval of the entire Board, potential candidates to become members of the Board, recommending membership on standing committees of the Board, developing and recommending to the entire Board corporate governance principles and practices for our company and assisting in the implementation of such policies.

Special Committee

In November 2019, our board of directors formed a committee of independent directors (the “Special Committee”) tasked with reviewing and evaluating strategic alternatives that may enhance the value of the Company, including alternatives that may be available to identify and access further sources of liquidity.

Communications with the Board of Directors

Stockholders may communicate with our Board or any of the Company’s directors by sending written communications addressed to the Board or any of the directors, at Lilis Energy, Inc., 201 Main Street, Suite 700, Fort Worth, TX 76102, Attention: General Counsel. All communications are compiled by the General Counsel and forwarded to the Board or the individual director(s) accordingly.

Code of Ethics and Corporate Governance Guidelines

Our Board has adopted a Code of Business Conduct that applies to all of our officers and employees, including our chief executive officer, chief financial officer or controller, and persons performing similar functions. Our Code of Business Conduct codifies the business and ethical principles that govern all aspects of our business.

Our Board has developed and adopted Corporate Governance Guidelines to establish a common set of expectations to assist the Board, and its committees in performing their duties. The Corporate Governance Guidelines provide guidance to our directors on various subjects, including our director’s responsibilities, director qualification standards, director compensation, and access to management and independent advisors.

A copy of our Code of Business Conduct and Corporate Governance Guidelines are available on our website at www.lilisenergy.com under “Investor Relations - Corporate Governance.” We will undertake to provide a copy of our Code of Business Conduct and Corporate Governance Guidelines to any person, at no charge, upon a written request. All written requests should be directed to: Lilis Energy, Inc., 201 Main Street, Suite 700, Fort Worth, TX 76102, Attention: General Counsel. If any substantive amendments are made to our Code of Business Conduct, or if any waiver (including any implicit waiver) is granted from any provision of the Code of Business Conduct to our chief executive officer, chief financial officer or controller, we will disclose the nature of such amendment or waiver on our website at www.lilisenergy.com under “Investor Relations - Corporate Governance” or, if required, in a Current Report on Form 8-K.

Delinquent Section 16(a) Reports

Our executive officers and directors and persons who own more than 10% of our common stock are required to file reports with the SEC, disclosing the amount and nature of their beneficial ownership in our common stock, as well as changes in that ownership. Based solely on our review of reports and written representations that we have received, we believe that all required reports were timely filed during 2019, except for the following:

Mark Christensen filed one Form 4, reporting one transaction, subsequent to the time prescribed by Section 16(a) of the Exchange Act.

Joseph C. Daches filed one Form 4, reporting three transactions, subsequent to the time prescribed by Section 16(a) of the Exchange Act.

Item 11. Executive Compensation

Executive Compensation for Fiscal Year 2019

We are currently considered a “smaller reporting company” for purposes of the SEC’s executive compensation and other disclosure rules. In accordance with such rules, we are required to provide a Summary Compensation Table and an Outstanding Equity Awards at Fiscal Year End Table, as well as limited narrative disclosures.

The compensation earned by our executive officers for the year ended December 31, 2019, consisted of base salary, short-term incentive compensation consisting of cash bonus payments and long-term incentive compensation consisting of awards of stock grants.

Summary Compensation Table

The table below sets forth compensation paid to our chief executive officer, chief financial officer and our other most highly compensated executive officer during the fiscal years ended December 31, 2019 and 2018, which we refer to as our named executive officers (“NEOs”) for the years ended December 31, 2019 and 2018.



Name and Principal Position	Year	Salary ($)⁽¹⁾	Bonus ($)⁽²⁾	Stock Awards ($)⁽³⁾	Option Awards ($)	All Other Compensation ($)⁽⁴⁾	Total ($)
Joseph C. Daches⁽⁵⁾	2019	450,000	800,000	1,194,000	—	38,387	2,482,387
(Chief Executive Officer, President and Chief Financial Officer)	2018	420,513	600,000	—	—	43,883	1,064,396
Ronald D. Ormand⁽⁶⁾	2019	239,743	800,000	1,592,000	—	1,034,730	3,666,473
(Former Chief Executive Officer)	2018	500,000	1,250,000	—	—	24,326	1,750,000
James W. Denny, III⁽⁷⁾	2019	199,993	200,000	298,500		227,515	926,008
(Executive Vice President, Operations)	2018	255,458	100,000	876,000	—	23,271	1,254,729


⁽¹⁾	The base salary amounts in this column represent actual base compensation paid or earned through the end of the applicable year.


⁽²⁾	The amounts in this column include annual bonuses paid for the applicable year.

⁽³⁾

The amounts in this column represent the aggregate grant date fair value of stock awards granted during the applicable year. The grant date fair values for restricted stock awards were computed in accordance with FASB ASC Topic 718. The amounts reported in this column reflect the accounting cost for the stock awards and do not necessarily correspond to the actual economic value that may be received for the stock awards.


⁽⁴⁾	For 2019, this amount includes $8,682 and $25,738 paid for reimbursement of health insurance premiums to Mr. Ormand and Mr. Daches, respectively. The amount also includes $1,026,048 for severance and COBRA for Mr. Ormand. This also includes 401K matching for Mr. Daches in the amount of $10,153 for 2018 and $10,375 in 2019, and Mr. Denny in the amount of $5,305 in 2018 and $5,221 in 2019.


⁽⁵⁾	On November 13, 2019, Mr. Daches was appointed Chief Executive Officer. He has been Chief Financial Officer since January 23, 2017, and President since August 16, 2018.


⁽⁶⁾	On June 6, 2019, Mr. Ormand resigned as Chief Executive Officer and as Executive Chairman of the Board.


⁽⁷⁾	On June 28, 2019, Mr. Denny ceased serving as the Executive Vice President, Operations.

Outstanding Equity Awards at Fiscal Year-End



	Option Awards					Stock Awards
Name	Number of Securities Underlying Unexercised Options (#) Exercisable	Number of Securities Underlying Unexercised Options (#) Unexercisable	Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)	Option Exercise Price ($)	Option Expiration Date	Number of Shares or Units of Stock That Have Not Vested (#)	Market Value of Shares or Units of Stock That Have Not Vested ($)⁽¹⁾	Market or Payout Value of Unearned Shares, Units or Other Rights That have Not Vested

Joseph C. Daches	750,000	—	—	2.98	12/15/2026	396,000	150,480	—
Ronald D. Ormand⁽²⁾	250,000	—	—	2.98	12/15/2026	—	—	—
James W. Denny, III⁽³⁾	—	—	—	—	—	—	—	—

Vesting of options and stock awards reflected in this table is subject to continuous service with our Company, except that unvested awards may vest upon termination by us without cause, termination by the officer for good reason, or termination due to the officer’s disability or death (in each case as set forth in the applicable award agreement or employment agreement).


⁽¹⁾	The market value of the stock awards is based on the closing price per share of our common stock on the NYSE American on December 31, 2019, which was $0.38.


⁽²⁾	Mr. Ormand held 693,000 shares of unvested restricted stock as of his retirement, which vesting was accelerated upon his retirement on June 5, 2019.


⁽³⁾	Mr. Denny forfeited 165,000 unvested shares of restricted common stock upon his separation from the Company on June 28, 2019.

Employment Agreements and Other Compensation Arrangements

2012 Equity Incentive Plan (“2012 EIP”) (formerly the Recovery Energy, Inc. 2012 Equity Incentive Plan)

Our Board and stockholders approved our 2012 EIP in August 2012. The 2012 EIP provided for grants of equity incentives to: attract, motivate and retain the best available personnel for positions of substantial responsibility; provide additional incentives to our employees, directors and consultants; and promote the success and growth of our business. Equity incentives that were available for grant under our 2012 EIP included stock options, stock appreciation rights (SARs), restricted stock awards, restricted stock units (RSUs), and unrestricted stock awards.

Our 2012 EIP is administered by the independent members of our Board, subject to the ultimate authority of our Board, which has full power and authority to take all actions and to make all determinations required or provided for under the 2012 EIP.

Under our 2012 EIP, 1,000,000 shares of our common stock were available for issuance. As a result of the adoption of our 2016 Omnibus Incentive Plan (“2016 Plan”), awards are no longer made under the 2012 EIP, as discussed below.

2016 Omnibus Incentive Plan

Background

Our 2016 Plan was approved by our Board effective April 20, 2016 and approved by our stockholders at the Company’s 2016 annual meeting on May 23, 2016. Our 2016 Plan replaced our 2012 EIP.

The purposes of our 2016 Plan are to create incentives that are designed to motivate eligible directors, officers, employees and consultants to put forth maximum effort toward our success and growth, and to enable us to attract and retain experienced individuals who by their position, ability and diligence are able to make important contributions to our success.

On a go forward basis, the Company intends to base compensation on certain performance matrices relating to employees positions or roles and standards utilized by its peers in the industry. By using measurable goals, the Company can more easily validate award increases based on employee and Company performance combined and assure that the Company remains competitive.

Eligibility

Awards may be granted under our 2016 Plan to our officers, employees, directors, consultants and advisors and its affiliates. Tax-qualified incentive stock options may be granted only to our employees.

Administration

Our 2016 Plan may be administered by our Board or a compensation committee of the Board. The independent members of our Board, in their discretion, generally select the individuals to whom awards may be granted, the time or times at which awards are granted and the terms and conditions of awards.

Number of Authorized Shares

When initially approved by our stockholders, 50,000,000 shares of our common stock were made available for issuance under our 2016 Plan. As a result of our 1-for-10 reverse stock split, which took effect on June 23, 2016, the number of shares available for issuance under our 2016 Plan was automatically reduced to 5,000,000. On August 25, 2016, our Board approved an amendment to our 2016 Plan to increase the maximum number of shares that may be issued from 5,000,000 to 10,000,000, and our stockholders approved that amendment at a special meeting on November 3, 2016. On May 15, 2017, our Board approved a second amendment to the 2016 Plan to increase the maximum number of shares of our common stock that may be issued under the 2016 Plan from 10,000,000 to 13,000,000, and our stockholders approved that amendment at the 2017 Annual Meeting. In 2018, our Board and our stockholders approved a third amendment to the 2016 Plan to increase the maximum number of shares of our common stock that may be issued under the 2016 Plan from 13,000,000 to 18,000,000.

Up to 18,000,000 shares may be granted as tax-qualified incentive stock options under our 2016 Plan. The shares issuable under our 2016 Plan consist of authorized and unissued shares, treasury shares or shares purchased on the open market or otherwise.

If any award is canceled, terminates, expires or lapses for any reason prior to the issuance of shares or if shares are issued under our 2016 Plan and thereafter are forfeited to us, the shares subject to those awards and the forfeited shares will not count against the aggregate number of shares available for grant under the plan. In addition, the following items will not count against the aggregate number of shares available for grant under our 2016 Plan: (1) the payment in cash of dividends or dividend equivalents under any outstanding award, (2) any award that is settled in cash rather than by issuance of shares, (3) shares surrendered or tendered in payment of the option price or purchase price of an award or any taxes required to be withheld in respect of an award or (4) awards granted in assumption of or in substitution for awards previously granted by an acquired company.

Limits on Awards to Nonemployee Directors

The maximum number of shares subject to awards under our 2016 Plan granted during any calendar year to any nonemployee member of our Board, taken together with any cash fees paid to the director during the fiscal year, may not exceed $500,000 in total value (calculating the value of any such awards based on the grant date fair value of such awards for financial reporting purposes).

Types of Awards

Our 2016 Plan permits the granting of any or all of the following types of awards: stock options, which entitle the holder to purchase a specified number of shares at a specified price; SARs, which, upon exercise, entitle the holder to receive payment per share in stock or cash equal to the excess of the share’s fair market value on the date of exercise over the grant price of the SAR; restricted stock, which are shares of common stock subject to specified restrictions; RSUs, which represent the right to receive shares of our common stock in the future; other types of equity or equity-based awards; and performance awards, which entitle participants to receive a payment from us, the amount of which is based on the attainment of performance goals established by the independent members of our Board over a specified award period.

No Repricing

Without stockholder approval, the independent members of our Board are not authorized to (1) lower the exercise or grant price of a stock option or SAR after it is granted, except in connection with certain adjustments to our corporate or capital structure permitted by our 2016 Plan, such as stock splits, (2) take any other action that is treated as a repricing under generally accepted accounting principles or (3) cancel a stock option or SAR at a time when its exercise or grant price exceeds the fair market value of the underlying stock, in exchange for cash, another stock option or SAR, restricted stock, RSUs or other equity award, unless the cancellation and exchange occur in connection with a change in capitalization or other similar change.

Clawback

All awards granted under our 2016 Plan will be subject to all applicable laws regarding the recovery of erroneously awarded compensation, any implementing rules and regulations under such laws, any policies we adopt to implement such requirements and any other compensation recovery policies as we may adopt from time to time.

Transferability

2016 Plan awards are not transferable other than by will or the laws of descent and distribution, except that in certain instances transfers may be made to or for the benefit of designated family members of the participant for no value.

Effect of Change in Control

Under our 2016 Plan, in the event of a change in control, outstanding awards will be treated in accordance with the applicable transaction agreement. If no treatment is provided for in the transaction agreement, each award holder will be entitled to receive the same consideration that stockholders receive in the change in control for each share of stock subject to the award holder’s awards, upon the exercise, payment or transfer of the awards, but the awards will remain subject to the same terms, conditions and performance criteria applicable to the awards before the change in control, unless otherwise determined by the independent members of our Board. In connection with a change in control, outstanding stock options and SARs can be canceled in exchange for the excess of the per share consideration paid to stockholders in the transaction, minus the applicable exercise price.

Subject to the terms and conditions of the applicable award agreement, awards granted to nonemployee directors will fully vest upon a change in control.

Subject to the terms and conditions of the applicable award agreement, for awards granted to all other service providers, vesting of awards will depend on whether the awards are assumed, converted or replaced by the resulting entity.

For awards that are not assumed, converted or replaced, the awards will vest upon the change in control. For performance awards, the amount vesting will be based on the greater of (1) the achievement of all performance goals at the “target” level or (2) the actual level of achievement of performance goals as of our fiscal quarter end preceding the change in control and will be prorated based on the portion of the performance period that had been completed through the date of the change in control.

For awards that are assumed, converted or replaced by the resulting entity, no automatic vesting will occur upon the change in control. Instead, the awards, as adjusted in connection with the transaction, will continue to vest in accordance with their terms and conditions. In addition, the awards will vest if the award recipient has a separation from service within two years after a change in control other than for cause or by the award recipient for good reason. For performance awards, the amount vesting will be based on the greater of (1) achievement of all performance goals at the “target” level or (2) the actual level of achievement of performance goals as of fiscal quarter end preceding the change in control, and will be prorated based on the portion of the performance period that had been completed through the date of the separation from service.

Term, Termination and Amendment of 2016 Plan

Unless earlier terminated by our Board, our 2016 Plan will terminate, and no further awards may be granted, 10 years after the date on which it was initially approved by stockholders. Our Board may amend, suspend or terminate our 2016 Plan at any time, except that, if required by applicable law, regulation or stock exchange rule, stockholder approval will be required for any amendment. The amendment, suspension or termination of our 2016 Plan or the amendment of an outstanding award generally may not, without a participant’s consent, materially impair the participant’s rights under an outstanding award.

Equity Grants for Fiscal Year 2019

During the year ended December 31, 2019, we granted 3,684,372 shares of restricted common stock and 135,000 options to purchase shares of common stock to our employees and directors. Also, during 2019, 1,650 stock options and 257,730 shares of restricted stock previously issued and unvested were forfeited or canceled in connection with the termination of certain employees, the departure of certain directors and/or shares canceled to cover tax withholding on vested restricted shares. Options issued to employees and directors generally vest in equal installments over specified time periods during the service period or upon achievement of certain performance-based operating thresholds.

On February 14, 2019, Mr. Daches received a grant of restricted stock under our 2016 Plan covering 600,000 shares of our common stock. The restricted stock vests over two years, with 34% vesting on the date of the grant, 33% vesting on the first anniversary of the date of the grant, and 33% vesting on the second anniversary of the date of the grant, subject to continued service.

On February 14, 2019, Mr. Ormand received a grant of restricted stock under our 2016 Plan covering 800,000 shares of our common stock. The restricted stock vests over two years, with 34% vesting on the date of the grant, 33% vesting on the first anniversary of the date of the grant, and 33% vesting on the second anniversary of the date of the grant, subject to continued service. Mr. Ormand held 693,000 shares of unvested restricted stock as of his retirement, which vesting was accelerated upon his retirement on June 5, 2019.

On February 14, 2019, Mr. Denny received a grant of restricted stock under our 2016 Plan covering 150,000 shares of our common stock. The restricted stock vests over two years, with 34% vesting on the date of the grant, 33% vesting on the first anniversary of the date of the grant, and 33% vesting on the second anniversary of the date of the grant, subject to continued service. Mr. Denny forfeited 99,000 unvested shares of restricted common stock upon his separation from the Company on June 28, 2019.

Equity Grants for Fiscal Year 2018

During the year ended December 31, 2018, we granted 1,194,944 shares of restricted common stock and 352,500 options to purchase shares of common stock to our employees and directors. Also, during 2018, 1,601,045 stock options and 1,280,480 shares of restricted stock previously issued and unvested were forfeited or canceled in connection with the termination of certain employees, the departure of certain directors and/or shares canceled to cover tax withholding on vested restricted shares. Options issued to employees and directors generally vest in equal installments over specified time periods during the service period or upon achievement of certain performance-based operating thresholds.

On May 3, 2018, Mr. Denny received a grant of restricted stock under our 2016 Plan covering 200,000 shares of our common stock. The restricted stock vests over two years, with 34% vesting on the date of the grant, 33% vesting on the first anniversary of the date of the grant, and 33% vesting on the second anniversary of the date of the grant, subject to continued service. Mr. Denny forfeited 66,000 unvested shares of restricted common stock upon his separation from the Company on June 28, 2019.

Employment Agreements

Mr. Daches

On December 17, 2019, we entered into an employment agreement with Mr. Daches, effective as of January 1, 2020, in connection with his appointment as our Chief Executive Officer. The initial term of the agreement is scheduled to end on January 1, 2022, and the agreement will renew automatically for additional one-year periods beginning on January 1, 2022, unless either party gives notice of non-renewal at least 180 days before the end of the then-current term. This agreement replaces in its entirety Mr. Daches’ prior employment agreement with the Company.

Mr. Daches’ annual base salary under this agreement (which will be reviewed periodically by the Board for adjustments) will not be less than $515,000. Mr. Daches will also be eligible to receive bonuses and awards of equity and non-equity compensation and to participate in the annual and long-term compensation plans of the Company, in each case as determined by our Board. The target annual bonus for Mr. Daches set forth in his agreement is no less than 100% of base salary and restricted shares equal to 200% of base salary. In 2019, Mr. Daches received a $200,000 cash bonus for his appointment as Interim Chief Executive Officer. Under Mr. Daches’ prior employment agreement, he received an annual salary of $480,000 during 2019.

Mr. Ormand

On July 5, 2016, we entered into an employment agreement with Ronald D. Ormand, effective as of July 11, 2016. The initial term of the agreement was scheduled to end on December 31, 2017, and the agreement renewed automatically for additional one-year periods beginning on December 31, 2017, unless either party gave notice of non-renewal at least 180 days before the end of the then-current term.

Mr. Ormand’s base salary under his agreement (which was reviewed by the Board for adjustments) was $300,000 for the first year of the agreement, $350,000 for the second year of the agreement, and $400,000 for the third year of the agreement. Mr. Ormand was eligible to receive a cash bonus equal to a percentage of his base salary (ranging from 0% to 400%) depending on the level of achievement of certain BOE per day, EBITDAX and cash on hand performance measures. Mr. Ormand was also eligible to receive awards of equity and non-equity compensation and to participate in our annual and long-term incentive plans, in each case as determined by our Board in its discretion.

On June 6, 2019, Mr. Ormand retired as Chief Executive Officer and Executive Chairman of the Board. In connection with his retirement, Mr. Ormand entered into a separation agreement with the Company, pursuant to which he received $1,026,048 as separation payment.

Potential Payments Upon Termination or Change-In-Control

Mr. Daches

Under his employment agreement, upon a termination by the Company without cause or a termination by him for good reason, Mr. Daches will be entitled to a lump sum severance payment equal to 12 months of base salary and 12 months of COBRA premiums. Upon a termination by the Company without cause or a termination by Mr. Daches for good reason within 18 months after a change in control, he will be entitled to a lump sum severance payment equal to 24 months of base salary and 24 months of COBRA premiums. All severance payments under Mr. Daches’ employment agreement are subject to his execution of a release of claims against the Company.

Stock Options

Mr. Daches holds unvested options under our 2016 Plan, all of which become fully exercisable (1) immediately upon the officer’s separation from service other than for cause or for good reason, and (2) immediately prior to, and contingent upon, a change in control prior to the officer’s separation from service.

Retirement and Other Benefits

All employees, including our named executive officers, may participate in our 401(k) retirement savings plan (“401(k) Plan”). Each employee may make before tax contributions in accordance with Internal Revenue Service limits. We provide this 401(k) Plan to help our employees save a portion of their cash compensation for retirement in a tax efficient manner. In prior years, we have made a matching contribution in an amount equal to 100% of the employee’s elective deferral contribution up to 4% of the employee’s annual compensation.

Compensation of Nonemployee Directors

The compensation of our non-employee directors is reviewed and approved by the Board. We use a combination of cash and stock-based incentive compensation to attract and retain qualified candidates to serve on our Board. In determining director compensation, we consider the significant amount of time the directors spend fulfilling their duties, as well as the competitive market for skilled directors.

Beginning January 1, 2017, our Board adopted an amended nonemployee director compensation program (the “Director Compensation Program”). Our Director Compensation Program sets forth an annual equity date (which will be the first business day on or after January 31 of each year) pursuant to which each nonemployee director will receive an annual stock award, subject to substantially the same terms and conditions set forth above. In addition, the Director Compensation Program establishes annual limits on the number of shares subject to our equity compensation plan awards that may be granted during any calendar year to any director, which, taken together with any cash fees paid to the director during the year, cannot exceed $500,000 in total value.

Our Director Compensation Program is comprised of the following components:

Initial Grant: Each nonemployee director receives 10,000 restricted shares of common stock on the first anniversary of the date of the director’s appointment, which would vest in three equal installments over a three-year period, (subject to the continued service of the director and certain accelerated vesting provisions);

Initial Option Award: Each nonemployee director receives a one-time initial grant of 25,000 stock options, which would vest immediately, and 20,000 options that would vest in equal installments over a three-year period beginning on the first anniversary of the grant date;

Annual Stock Award: Each nonemployee director would receive an annual stock award equal to $150,000 divided by the most recent per share closing price of the common stock prior to the date of each annual grant, payable on each anniversary of the date an independent director was initially appointed to our Board, and subject to certain accelerated vesting provisions;

Annual Fees: On a quarterly basis, beginning at the end of the first full quarter following the appointment of the nonemployee director to the Board, each director receives $15,000 in cash compensation;

Chairman and Committee Chairman Fees: On a quarterly basis, beginning at the end of the first full quarter following the appointment of the nonemployee director to Chairman of the Board, Chairman of the Audit Committee, Chairman of the Compensation Committee, Chairman of the Reserves Committee, and Chairman of the Nominating and Governance Committee, the director receives $12,500, $6,250, $6,250, $6,250, and $2,500 respectively, in cash compensation; and

Committee Fees: On a quarterly basis, beginning at the end of the first full quarter following the appointment of the nonemployee director to the Audit Committee, the Compensation Committee, the Reserves Committee, and the Nominating and Governance Committee, the director receives $3,125, $2,500, $2,500, and $1,875, respectively, in cash compensation.

Our Board evaluates the fees and compensation paid to the directors for their service on our Board on an annual basis.

Effective as of April 15, 2020, the Board dissolved its Reserves Committee, Compensation Committee and Nominating and Corporate Governance Committee. With respect to such committees, we do not expect to pay any additional committee chairman fees or committee fees during 2020.

As previously disclosed, the Company has formed a Special Committee. On a quarterly basis, beginning at the end of the first full quarter following the appointment of the nonemployee director to Chairman of the Special Committee or member of the Special Committee, the director receives $6,250 and $3,125, respectively, in cash compensation.

2019 Director Compensation

In 2019, each non-employee director received compensation consistent with our Director Compensation Program, consisting of an annual stock award, with additional fees being paid to the chairman of the Audit Committee, the chairman of the Compensation Committee, the chairman of the Reserves Committee, and the chairman of the Nominating and Governance Committee. Each member who served on a committee received an additional fee in connection for service on such committee. The fees received by our directors are pro-rated based on the time of their service with the Company. Each non-employee director is reimbursed for reasonable out-of-pocket costs incurred to attend Board meetings.



Name	Fees Earned or Paid in Cash Compensation ($)	Stock Awards ($)⁽¹⁾	Option Awards ($)	All Other Compensation ($)	Total ($)
Michael G. Long⁽²⁾	95,000	121,700	97,650	—	314,350
Nuno Brandolini⁽³⁾	80,000	150,000	—	—	230,000
Mark Christensen⁽⁴⁾	60,000	150,000	—	—	210,000
R. Glenn Dawson⁽⁵⁾	103,750	150,000	—	276,875	530,625
John Johanning⁽⁶⁾	182,500	—	—	—	182,500
Ronald D. Ormand⁽⁷⁾	30,000	—	—	—	30,000
Markus Specks⁽⁸⁾	181,875	—	—	—	181,875
Nicholas Steinsberger⁽⁹⁾	55,000	124,200	97,650	185,000	461,850
David M. Wood⁽¹⁰⁾	81,875	163,310	97,650	—	342,835

⁽¹⁾

Represents restricted stock awards. Awards in this column are reported at grant date fair value in accordance with FASB ASC Topic 718. The amounts reported reflect the accounting cost for the awards and do not correspond to the actual economic value that may be received for the awards. On January 31, 2019, Mr. Brandolini, Mr. Christensen and Mr. Dawson were each granted 69,124 shares of restricted stock, Mr. Steinsberger was awarded 47,235 shares of restricted stock, Mr. Long was awarded 46,083 shares of restricted stock and Mr. Wood was awarded 161,681 shares of restricted stock. These awards all vested in full immediately. Mr. Long and Mr. Steinsberger also each received 10,000 shares of restricted stock that have a 3-year vesting, with the first vesting date being the first anniversary of the award.

⁽²⁾

Mr. Long was appointed to the Board on April 10, 2018. In 2019, Mr. Long received a fee of $15,000 per quarter for his service as a Director, $6,250 per quarter for his service as Chairman of the Audit Committee, and $2,500 per quarter for his service as a member of the Compensation Committee. Mr. Long also received an annual stock award grant of $100,000, which at the grant date stock price of $2.17 per share resulted in 46,083 shares of the Company’s common stock. Mr. Long also received a non-qualified incentive stock award for 45,000 of the Company’s common stock that vests over three years.

⁽³⁾

Mr. Brandolini was appointed to the Board on February 13, 2014. In 2019, Mr. Brandolini received a fee of $15,000 per quarter for his service as a Director, $2,500 per quarter for his service as Chairman of the Nominating and Corporate Governance Committee, and $2,500 per quarter for his service as a member of the Compensation Committee. Mr. Brandolini also received an annual stock award grant of $150,000, which at the grant date stock price of $2.17 per share resulted in 69,124 shares of the Company’s common stock.

⁽⁴⁾

Mr. Christensen was appointed to the Board on September 6, 2017. In 2019, Mr. Christensen received a fee of $15,000 per quarter for his service as a Director. Mr. Christensen also received an annual stock award grant of $150,000, which at the grant date stock price of $2.17 per share resulted in 69,124 shares of the Company’s common stock. Effective as of April 15, 2020, Mr. Christensen resigned from the Board.

⁽⁵⁾

Mr. Dawson was appointed to the Board on January 13, 2016. In 2019, Mr. Dawson received a fee of $15,000 per quarter for his service as a Director, $6,250 for his service as Chairman of the Compensation Committee, and $3,125 per quarter for his service as member of the Audit Committee. In 2019, Mr. Dawson received a quarterly fee of $60,000 per quarter on an interim basis for his service as Chairman of the Reserves Committee due to additional oversight responsibility requested by the Board (as described in the Amended and Restated Reserves Committee Charter) to be performed until requisite Company personnel is available to handle such responsibilities, which such fee for service as the Chairman of the Reserves Committee was approved by all members of the Board. Mr. Dawson also received an annual stock award grant of $150,000, which at the

grant date stock price of $2.17 per share resulted in 69,124 shares of the Company’s common stock. Effective as of April 15, 2020, Mr. Dawson resigned from the Board.

⁽⁶⁾

Mr. Johanning was appointed to the Board on March 1, 2018. In 2019, Mr. Johanning received a fee of $15,000 per quarter for service as a Director and $2,500 per quarter for his service as a member of the Reserves Committee. In lieu of the prorated annual stock award equal to $150,000, Mr. Johanning elected to receive a cash payment of $112,500, which is equal to $150,000 prorated for Mr. Johanning joining the Board in March 2018. The quarterly fees were paid directly to Värde.


⁽⁷⁾	Mr. Ormand became a nonemployee Director on the Board on June 6, 2019. Beginning with the third quarter of 2019, Mr. Ormand received a fee of $15,000 per quarter for his service as a Director. Effective as of April 15, 2020, Mr. Ormand resigned from the Board.

⁽⁸⁾

Mr. Specks was appointed to the Board on March 1, 2018. In 2019, Mr. Specks received a fee of $15,000 per quarter for his service as a Director and $1,875 per quarter for his service as a member of the Nominating and Corporate Governance Committee. In lieu of the prorated annual stock award equal to $150,000, Mr. Specks elected to receive a cash payment of $112,500, which is equal to $150,000 prorated for Mr. Specks joining the Board in March 2018. The quarterly fees were paid directly to Värde.

⁽⁹⁾

Mr. Steinsberger was appointed to the Board on May 3, 2018. In 2019, Mr. Steinsberger received $15,000 per quarter for his service as a Director and $2,500 per quarter for his service as a member of the Reserves Committee. For the first quarter of 2019, in lieu of his $15,000 cash payment for service as a Director, Mr. Steinsberger elected to receive a grant award of 6,912 shares of the Company’s common stock, which at the grant date stock price of $2.17 per share was equal to $15,000. Mr. Steinsberger also received an annual stock award grant of $87,500, which at the grant date stock price of $2.17 per share resulted in 40,323 shares of the Company’s common stock. Mr. Steinsberger also received a non-qualified incentive stock award for 45,000 of the Company’s common stock that vests over three years. Mr. Steinsberger also received $60,000 per quarter for consulting with the Company; see “Item 13. Certain Relationships and Related Transactions, and Director Independence - Related Party Transactions” below for more information.

⁽¹⁰⁾

Mr. Wood was appointed to the Board on June 1, 2018 and resigned from the Board on March 12, 2020. Mr. Wood received a fee of $15,000 per quarter for his service as a Director, $1,875 for his service as a member on the Nominating Committee and $3,125 per quarter for his service as a member of the Audit Committee. Mr. Wood also received an annual stock award grant of $75,000, which at the grant date stock price of $2.17 per share resulted in 34,562 shares of the Company’s common stock. Mr. Wood received a grant award of 127,119 shares of the Company’s stock for his compensation as Chairman, which at the grant date stock price of $0.52 per share was equal to $66,101, as approved by the Board. Mr. Wood also received a non-qualified incentive stock award for 45,000 of the Company’s common stock that vests over three years. Effective as of March 13, 2020, Mr. Wood resigned from the Board.

Indemnification of Directors and Officers

Pursuant to our certificate of incorporation we provide indemnification of our directors and officers to the fullest extent permitted under Nevada law. We believe that this indemnification is necessary to attract and retain qualified directors and officers.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The following table sets forth certain information with respect to beneficial ownership of our common stock as of April 30, 2020 by each of our executive officers and directors and each person known to be the beneficial owner of 5% or more of the outstanding common stock.

This table is based upon the total number of shares outstanding as of April 30, 2020. Unless otherwise indicated, the persons and entities named in the table have sole voting and sole investment power with respect to the shares set forth opposite the stockholder’s name. Beneficial ownership is determined in accordance with Rule 13d-3 under the Exchange Act. In computing the number of shares beneficially owned by a person or a group and the percentage ownership of that person or group, shares of our common stock subject to options or warrants currently exercisable or exercisable within 60 days after April 30, 2020, are deemed outstanding by such person or group, but are not deemed outstanding for the purpose of computing the percentage ownership of any other person. All share amounts that appear in this report have been adjusted to reflect a 1-for-10 reverse stock split of our outstanding common stock effected on June 23, 2016. Unless otherwise indicated, the address of each stockholder listed in the table is c/o Lilis Energy, Inc., 201 Main Street, Suite 700, Fort Worth, Texas 76102.



Name and Address of Beneficial Owner	Lilis common stock Held Directly	Lilis common stock Acquirable Within 60 Days⁽¹⁾	Total Beneficially Owned	Percent of Class Beneficially Owned
Directors and Named Executive Officers
Joseph Daches, Chief Executive Officer, President, and Chief Financial Officer	1,149,560	750,000	1,899,560	1.7
Michael Long, Chairman of the Board	67,083	25,000	92,083	*
Nuno Brandolini, Director	704,709	45,000	749,709	*
John Johanning, Director	—	—	—	*
Ronald D. Ormand, Former Director ⁽²⁾	4,829,064	295,000	5,124,064	4.5
Markus Specks, Director	—	—	—	*
Nicholas Steinsberger, Director	67,235	25,000	92,235	*
Directors and Officers as a Group (7 persons) ⁽³⁾	6,817,651	1,140,000	7,957,651	7.0

5% Stockholders
Värde Partners, Inc.⁽⁵⁾ 901 Marquette Avenue South Suite 330, Minneapolis, MN 55402	23,594,401	24,000,000 ⁽⁴⁾	47,594,401	41.4


*	Represents beneficial ownership of less than 1% of the outstanding shares of common stock.


⁽¹⁾	Represents shares of common stock subject to options and warrants exercisable within 60 days.


⁽²⁾	Consists of: (i) 2,706,792 shares of common stock held by Perugia Investments, LP (“Perugia”) and (ii) 2,122,272 shares of common stock held directly by Mr. Ormand. Mr. Ormand is manager of Perugia and has shared voting and dispositive power over the securities held by Perugia.


⁽³⁾	The directors and officers as a group beneficially own a total of 7,957,651 shares of common stock, which represents 7.0% of our currently issued and outstanding common stock.


⁽⁴⁾	Based on the Schedule 13D/A filed on March 8, 2019. This represents shares of common stock which may be issued pursuant to the conversion of the shares Series E Preferred Stock within 60 days as if such Series E Preferred Stock had been converted on the date of borrowing or issuance, as applicable.

⁽⁵⁾

Värde Partners, Inc. is the ultimate owner of the general partners (the “General Partners”), of each of The Värde Fund XI (Master), L.P., The Värde Fund XII (Master), L.P., The Värde Skyway Fund, L.P., The Värde Skyway Mini-Master Fund, L.P., Värde Investment Partners (Offshore) Master, L.P., The Värde Fund VI-A, L.P., Värde Investment Partners, L.P., and Värde Investment Partners (Offshore) Master, L.P. (the “Värde Entities”), or of the General Partners’ general partners or managing members. Mr. George Hicks and Mr. Ilfryn Carstairs are the co-chief executive officers of Värde Partners, Inc. As such, each of Värde Partners, Inc., Mr. Hicks and Mr. Carstairs may be deemed to have beneficial ownership of the shares owned by each of the Värde Entities. Each of Värde Partners, Inc., Mr. Hicks, and Mr. Carstairs disclaims beneficial ownership of the securities held indirectly through the Värde Entities except to the extent of their pecuniary interest therein, and this disclosure shall not be deemed an admission that any such reporting person is the beneficial owner for purposes of this Proxy Statement or for any other purpose.

To our knowledge, except as noted above, no person or entity is the beneficial owner of 5% or more of our common stock.

Equity Compensation Plan Information

໿



Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights (a)	Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights (b)	Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (excluding securities reflected in column (a)) (c)
Equity compensation plans approved by security holders	3,588,350	4.05	5,372,127
Equity compensation plans not approved by security holders	—	—	—
Total	3,588,350	4.05	5,372,127

For additional information regarding the Company’s benefit plans and share-based compensation expense, see Note 17 - Share Based and Other Compensation to our consolidated financial statements included in this Annual Report.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Related Party Transactions

We describe below transactions and series of similar transactions, since January 1, 2018, to which we were a party, in which:

The amounts involved exceeded or will exceed the lesser of $120,000 or one percent (1%) of our average total assets at year-end for the last two completed fiscal years; and

Any of our directors, executive officers, or holders of more than 5% of our capital stock, or any member of the immediate family of, or person sharing the household with, any of the foregoing persons, who had or will have a direct or indirect material interest.

Transactions with the Värde Parties

On January 30, 2018, we entered into a Securities Purchase Agreement with certain private funds affiliated with Värde Partners, Inc. (the “Series C Purchasers”), pursuant to which, on January 31, 2018, the Series C Purchasers purchased 100,000 shares of our newly created series of preferred stock of the Company, designated as “Series C 9.75% Convertible Participating Preferred Stock” (the “Series C Preferred Stock”), for a purchase price of $1,000 per share, or an aggregate of $100,000,000. Värde Partners, Inc. is the lead lender, and certain private funds affiliated with Värde Partners, Inc. are lenders, under the Company’s Second Lien Credit Agreement.

On October 10, 2018, we entered into a transaction agreement (the “2018 Transaction Agreement”) by and among the Company and the Värde Parties, pursuant to which we agreed to issue to the Värde Parties (i) an aggregate of 5,952,763 shares of the Company’s common stock, par value $0.0001 per share, which includes 5,802,763 shares of common stock at an exchange price of $5.00 per share of common stock plus an additional 150,000 shares of 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” (the “Series D 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, and issue and sell to the Värde Parties 25,000 shares of a newly created subseries of the Company’s Series 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 million. Värde Partners, Inc. is the lead lender, and certain private funds affiliated with Värde Partners, Inc. are lenders, under the Company’s Second Lien Credit Agreement. For more

information about the 2018 Transaction Agreement, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Preferred Stock Issuance” under Item 7 of this Annual Report.

On March 5, 2019, we entered into the transaction agreement (the “2019 Transaction Agreement”) by and among the Company and the Värde Parties, pursuant to which we agreed to issue to the Värde Parties an aggregate of (i) 9,891,638 shares of the Company’s common stock, par value $0.0001 per share (the “Term Loan Exchanged 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” (the “Series E Preferred Stock” or the “Exchanged Series E Shares”), 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” (the “Series F Preferred Stock” or the “Exchanged Series F Shares”, as consideration for the termination of the Second Lien Credit Agreement (as defined in the 2019 Transaction Agreement) and the satisfaction in full, in lieu of repayment in full in cash, of $133.6 million pursuant to the Payoff Letter (as defined in the 2019 Transaction Agreement) and issue 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.

Värde Partners, Inc. was the lead lender, and certain private funds affiliated with Värde Partners, Inc. were lenders, under the Company’s Second Lien Credit Agreement. Värde Partners, Inc. and its applicable affiliated funds beneficially own over 5% of our common stock. For more information about the 2018 Transaction Agreement, see “Note 14 Preferred Stock - Preferred Stock Issuance” to our consolidated financial statements included in this Annual Report.

VPD Acquisition

On February 28, 2018, pursuant to an agreement we entered into with VPD Texas, L.P. (“VPD”) dated that date, we acquired from VPD a 50% undivided leasehold interest in certain oil and gas properties and assets in Loving and Winkler Counties, Texas for a purchase price of approximately $10.5 million. VPD is affiliated with Värde Partners, Inc., which is the lead lender under the Second Lien Credit Agreement, and Värde Partners, Inc. and certain affiliated funds hold all of the issued and outstanding shares of Series C Preferred Stock. As such, Värde Partners, Inc. and its applicable affiliated funds beneficially own over 5% of our common stock as a result of their respective conversion rights under the Second Lien Credit Agreement and the Series C Preferred Stock.

Compensation of Directors

On August 1, 2019, Steinsberger Tight Gas Consulting LLC and the Company entered into an engagement letter effective as of June 1, 2019, under which the Steinsberger Tight Gas Consulting LLC provides consulting services involving all areas of operations to the Company for $60,000 per quarter. Mr. Steinsberger, who is a Director on our Board, is Managing Partner of Steinsberger Tight Gas Consulting LLC.

For more information on this and other Director compensation, see “Item 12. Executive Compensation - Compensation of Nonemployee Directors” above.

Employee Relationship

The Company employs Austin Brooks, who is the son-in law of Ronald Ormand, who was a Director on our Board until his resignation on April 15, 2020. In 2019, his total compensation, including salary, bonus and other benefits, totaled approximately $379,204. Our employment relationship with Mr. Brooks was entered into in 2018 in the ordinary course of business and has been conducted on an arm’s-length basis, and the compensation paid to Mr. Brooks is commensurate with that of his peers.

Conflict of Interest Disclosure

We have a corporate code of business conduct that requires disclosure of any conflicts of interests at least annually and upon awareness of any potential conflict of interest, such conflict will either be prohibited or the Company will adopt a mitigation plan to protect the Company’s interest.

Director Independence

Our Board follows the standards of independence established under the rules of the NYSE American, as well as our Corporate Governance Guidelines on Director Independence, in determining if directors are independent. The Board has determined that four of our current directors, Mr. Brandolini, Mr. Johanning, Mr. Specks, and Mr. Long, are “independent directors” under the NYSE American rules referenced above.

No independent director receives, or has received, any fees or compensation directly as an individual from us other than compensation received in his capacity as a director or indirectly through their respective companies, except as described above. There were no transactions, relationships or arrangements not otherwise disclosed that were considered by the Board in determining whether any of the directors were independent.

Item 14. Principal Accounting Fees and Services

The following table sets forth fees billed by our principal accounting firm BDO USA, LLP for the years ended December 31, 2019 and 2018:



(In thousands)	Year Ended December 31,
	2019		2018
Audit Fees	$	738	$	1,032
Audit Related Fees	$	—	$	—
Tax Fees	$	—	$	—
All Other Fees	$	—	$	—

Audit Fees consist of the aggregate fees for professional services rendered for the audit of our annual financial statements and the reviews of the financial statements included in our Quarterly Reports on Forms 10-Q and for any other services that were normally provided by our auditors in connection with our statutory and regulatory filings or engagements.

Audit-Related Fees consist of the aggregate fees billed or reasonably expected to be billed for professional services rendered for assurance and related services that were reasonably related to the performance of the audit or review of our financial statements and were not otherwise included in Audit Fees.

Tax Fees consist of the aggregate fees billed for professional services rendered for tax consulting. Included in such Tax Fees were fees for consultancy, review, and advice related to our income tax provision and the appropriate presentation on our financial statements of the income tax related accounts.

All Other Fees consist of the aggregate fees billed for products and services provided by our auditors and not otherwise included in Audit Fees, Audit-Related Fees or Tax Fees.

Audit Committee Pre-Approval Policy

Consistent with SEC rules regarding auditor independence, our Audit Committee has the responsibility for appointing, approving the compensation of, and overseeing the work of our independent public accounting firm. Our independent registered public accounting firm may not be engaged to provide non-audit services that are prohibited by law or regulation to be provided by it, nor may our independent registered public accounting firm be engaged to provide any other non-audit service unless it is determined that the engagement of the principal accountant provides a business benefit resulting from its inherent knowledge of our Company while not impairing its independence. Our Audit Committee must pre-approve permissible non-audit services. During the year ended December 31, 2019, we had no non-audit services provided by our independent registered public accounting firm.

PART IV

Item 15. Exhibits, Financial Statement Schedules


a.	The following documents are filed as part of this Annual Report on Form 10-K or incorporated by reference:


(i)	The consolidated financial statements of Lilis Energy, Inc. are listed on the Index to this Form 10-K, page 79.


b.	The following exhibits are filed or furnished with this Annual Report on Form 10-K or incorporated by reference:

b) Exhibits



2.1	Agreement and Plan of Merger, dated as of December 29, 2015, among Lilis Energy, Inc., Lilis Merger Sub, Inc. and Brushy Resources, Inc. (incorporated herein by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on January 5, 2016).
2.2	First Amendment to Agreement and Plan of Merger, dated as of January 20, 2016, among Lilis Energy, Inc., Lilis Merger Sub, Inc. and Brushy Resources, Inc. (incorporated herein by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on January 20, 2016).
2.3	Second Amendment to Agreement and Plan of Merger, dated as of March 24, 2016, among Lilis Energy, Inc., Lilis Merger Sub, Inc. and Brushy Resources, Inc. (incorporated herein by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on March 24, 2016).
2.4	Third Amendment to Agreement and Plan of Merger, dated as of June 22, 2016, among Lilis Energy, Inc., Lilis Merger Sub, Inc. and Brushy Resources, Inc. (incorporated herein by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on June 28, 2016).
3.1	Amended and Restated Articles of Incorporation of Recovery Energy, Inc., dated as of October 10, 2011 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on October 20, 2011).
3.2	Certificate of Amendment to the Amended and Restated Articles of Incorporation of Recovery Energy, Inc., dated as of November 18, 2013 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on November 19, 2013).
3.3	Certificate of 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 to 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 to 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 to the Company's Annual Report on 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 to the Company’s Annual Report on 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 to the Company’s Annual Report on 10-K filed on March 7, 2019).
3.12	Amended and Restated Certificate of Designation of Preferences, Rights and Limitations of Series D 8.25% Participating Preferred Stock, dated March 5, 2019 (incorporated herein by reference to Exhibit 3.12 to of the Company’s Annual Report on 10-K filed on March 7, 2019).



4.1	Form of Warrant (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on January 28, 2014).
4.2	Form of Warrant (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on February 6, 2014).
4.3	Form of Warrant dated May 30, 2014 (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on June 4, 2014).
4.4	Form of Warrant (incorporated herein by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on January 5, 2016).
4.5	Form of Common Stock Purchase Warrant (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on June 16, 2016).
4.6	Form of Common Stock Certificate (incorporated herein by reference to Exhibit 4.1 to the Company’s Registration Statement on Form S-1 filed on September 16, 2016).
4.7	Form of Warrant (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on March 2, 2017).
4.8†	Lilis Energy, Inc. 2016 Omnibus Incentive Plan and forms of agreement thereunder (incorporated herein by reference to Exhibit 4.1 to the Company’s Registration Statement on Form S-8 filed on June 28, 2016).
4.9†	First Amendment to the Lilis Energy, Inc. 2016 Omnibus Incentive Plan, approved on November 3, 2016 (incorporated herein by reference to Annex C to the Company’s Definitive Proxy filed on September 30, 2016).
4.10†	Second Amendment to the Company’s 2016 Omnibus Incentive Plan, dated July 13, 2017 (incorporated herein by reference to Annex A of the Company’s Definitive Proxy Statement on Schedule 14A, filed on June 19, 2017).
4.11†	Third Amendment to Lilis Energy, Inc. 2016 Omnibus Incentive Plan, approved on June 28, 2018 (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on July 5, 2018).
4.15*	Description of Registrant’s Securities.
10.1	Recovery Energy, Inc. 2012 Equity Incentive Plan dated August 31, 2012, as amended (incorporated herein by reference to Appendix B to the Company’s definitive proxy filed on December 15, 2015).
10.2	Form of Convertible Note Purchase Agreement (incorporated herein by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K filed on January 5, 2016).
10.3	Form of Note Exchange Agreement (incorporated herein by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K filed on January 5, 2016).
10.4	Form of Securities Purchase Agreement (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on June 16, 2016).
10.5	Form of Registration Rights Agreement (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on June 16, 2016).
10.6†	Employment Agreement with Ronald Ormand, dated as of July 5, 2016 (incorporated herein by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K filed on July 8, 2016).
10.7	Texican Crude & Hydrocarbon LLC Purchase Contract, dated as of February 3, 2016, between Texican Crude & Hydrocarbon, LLC and Impetro Operating LLC (incorporated herein by reference to Exhibit 10.65 to Brushy Resources, Inc.’s Registration Statement on Form S-1 filed on September 16, 2016).
10.8	DCP Midstream, LP Gas Purchase Agreement (incorporated herein by reference to Exhibit 10.8 to Brushy Resources, Inc.’s Form 10/A filed on July 26, 2013, which became effective August 6, 2013).
10.9	Credit and Guarantee Agreement, dated as of September 29, 2016 by and among Lilis Energy, Inc., Brushy Resources, Inc., ImPetro Operating, LLC, ImPetro Resources, LLC, the Lenders party thereto and T.R. Winston & Company, LLC acting as collateral agent (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K/A filed on October 26, 2016).
10.10	Securities Subscription Agreement, dated February 28, 2017, by and among the Company and the Purchasers thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on March 2, 2017).
10.11	Registration Rights Agreement, dated February 28, 2017, by and among the Company and the Purchasers thereto (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on March 2, 2017).
10.12†	First Amendment to Employment Agreement with Ronald D. Ormand, dated as of March 9, 2017 (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on March 10, 2017).
10.13	Credit Agreement, dated April 26, 2017 by and among Lilis Energy, Inc., the Guarantors party thereto, the Lenders party thereto and Wilmington Trust, National Association acting as administrative agent (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed April 27, 2017).
10.14	Registration Rights Agreement, dated April 26, 2017 by and among the Lender party thereto (incorporated herein by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed April 27, 2017).



10.15	Series B 6.0% Convertible Preferred Stock Conversion Agreement, dated April 25, 2017, by and among the Holders party thereto (incorporated herein by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K filed April 27, 2017).
10.16	Letter Agreement dated August 12, 2017 between the Company and Värde Partners, Inc. (incorporated herein by reference to Exhibit 10.14 on the Company’s Quarterly Report on Form 10-Q filed on August 14, 2017).
10.17	Gas Gathering, Processing and Purchase Agreement, dated August 10, 2017 by and among the Company and Lucid Energy Delaware (incorporated herein by reference to Exhibit 10.5 to the Company’s quarterly report on Form 10-Q filed on November 14, 2017). Specific items in this exhibit have been redacted, as marked by two asterisks (**), because confidential treatment for those items has granted. The redacted material has been separately filed with the SEC.
10.18	Amendment No. 1 to the Gas Gathering, Processing and Purchase Agreement, dated October 1, 2017 by and among the Company and Lucid Energy Delaware (incorporated herein by reference to Exhibit 10.26 to the Company’s Annual Report on Form 10-K filed on March 7, 2019).
10.19	Amendment No. 1 to Second Lien Credit Agreement, dated October 3, 2017 by and among Lilis Energy, Inc., the Guarantors party thereto, the Lenders party thereto and Wilmington Trust, National Association, as administrative agent (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 10, 2017).
10.20	Amendment No. 2 to Second Lien Credit Agreement, dated October 19, 2017 by and among Lilis Energy, Inc., the Guarantors party thereto, the Lenders party thereto and Wilmington Trust, National Association, as administrative agent (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on October 24, 2017).
10.21	Amendment No. 3 to Second Lien Credit Agreement, dated November 10, 2017 by and among Lilis Energy, Inc., the Guarantors party thereto, the Lenders party thereto and Wilmington Trust, National Association, as administrative agent (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on November 14, 2017).
10.22	Purchase and Sale Agreement, dated as of January 30, 2018, by and between Lilis Energy, Inc. and OneEnergy Partners Operating, LLC (incorporated herein by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on February 1, 2018).
10.23	Securities Purchase Agreement, dated as of January 30, 2018, by and among Lilis Energy, Inc. and the Purchasers party thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 1, 2018).
10.24	Registration Rights Agreement, dated as of January 31, 2018, by and among Lilis Energy, Inc. and the Purchasers party thereto (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on February 1, 2018).
10.25	Amended and Restated Senior Secured Term Loan Credit Agreement, dated as of January 30, 2018, by and among Lilis Energy, Inc., the subsidiaries of the Company party thereto as guarantors, Riverstone Credit Management LLC, as administrative agent and collateral agent, and the lenders party thereto (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on February 1, 2018).
10.26	Amendment No. 4 to Second Lien Credit Agreement, dated as of January 31, 2018, by and among Lilis Energy, Inc., the guarantors party thereto, the lenders party thereto and Wilmington Trust, National Association, as administrative agent (incorporated herein by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on February 1, 2018).
10.27	Amendment No. 5 to Second Lien Credit Agreement, dated as of February 20, 2018, by and among Lilis Energy, Inc., the guarantors party thereto, the lenders party thereto and Wilmington Trust, National Association, as administrative agent (incorporated herein by reference to Exhibit 10.35 to the Company’s Annual Report on Form 10-K filed on March 7, 2019).
10.28	Amendment No. 1 to the Amended and Restated Senior Secured Term Loan Credit Agreement, dated as of February 20, 2018, by and among Lilis Energy, Inc., the subsidiaries of the Company party thereto as guarantors, Riverstone Credit Management LLC, as administrative agent and collateral agent, and the lenders party thereto (incorporated herein by reference to Exhibit 10.36 to the Company’s Annual Report on Form 10-K filed on March 7, 2019).
10.29*	Crude Oil Gathering Agreement, dated May 21, 2018 by and among the Company and Salt Creek Midstream, LLC.
10.30*	Option Agreement, dated May 21, 2018, by and among the Company and Salt Creek Midstream, LLC.
10.31	Second Amended and Restated Senior Secured Revolving Credit Agreement dated as of October 10, 2018, among Lilis Energy, Inc., the subsidiaries of Lilis Energy, Inc. party thereto as guarantors, BMO Harris Bank, N.A., as administrative agent, and the lenders party thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 16, 2018).



10.32	Amendment No. 6 to Credit Agreement and Amendment No. 1 to Pledge and Security Agreement dated as of October 10, 2018, among Lilis Energy, Inc., the subsidiaries of Lilis Energy, Inc., party thereto as guarantors, Wilmington Trust, National Association, as administrative agent, Varde Partners, Inc., as lead lender, and the other lenders party thereto (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on October 16, 2018).
10.33	Transaction Agreement, dated as of October 10, 2018, by and among Lilis Energy, Inc. and the Varde Parties party thereto (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on October 16, 2018).
10.34	Registration Rights Agreement, dated as of October 10, 2018, by and among Lilis Energy, Inc. and the Varde Parties party thereto (incorporated herein by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on October 16, 2018).
10.35	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, Wilmington Trust, National Association, as administrative agent, Värde Partners, Inc., as lead lender, and the other lenders party thereto (incorporated herein by reference to Exhibit 10.41 to the Company’s Annual Report on Form 10-K filed on March 7, 2019).
10.36	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 to the Company’s Annual Report on Form 10-K filed on March 7, 2019).
10.37	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 to the Company’s Annual Report on Form 10-K filed on March 7, 2019).
10.38	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 to the Quarterly Report on Form 10-Q filed on May 9, 2019).
10.39	Separation and Release Agreement for Ronald D. Ormand (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on June 6, 2019).
10.40	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 (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on August 1, 2019).
10.41	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).
10.42	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).
10.43	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 (incorporated herein by reference to Exhibit 10.9 to the Company’s Quarterly Report on Form 10-Q filed on November 7, 2019).
10.44	Fifth Amendment and Waiver to Second Amended and Restated Credit Agreement dated as of November 27, 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 10.1 to the Company’s Current Report on Form 8-K filed on November 27, 2019).
10.45	Sixth Amendment and Waiver to Second Amended and Restated Credit Agreement dated as of December 16, 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 10.1 to the Company’s Current Report on Form 8-K filed on December 17, 2019).
10.46†	Employment Agreement dated December 17, 2019, between Joseph Daches and Lilis Energy, Inc (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on December 20, 2019).
10.47	Seventh Amendment and Waiver to Second Amended and Restated Credit Agreement dated as of January 17,2020, 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 10.1 to the Company’s Current Report on Form 8-K filed on January 21, 2020).



10.48	Eighth Amendment and Waiver to Second Amended and Restated Credit Agreement dated as of January 23,2020, 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 10.1 to the Company’s Current Report on Form 8-K filed on January 24, 2020).
10.49	Ninth Amendment and Waiver to Second Amended and Restated Credit Agreement dated as of February 6, 2020, 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 10.1 to the Company’s Current Report on Form 8-K filed on February 6, 2020).
10.50	Tenth Amendment and Waiver to Second Amended and Restated Credit Agreement dated as of February 14, 2020, 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 10.1 to the Company’s Current Report on Form 8-K filed on February 14, 2020).
10.51	Eleventh Amendment and Waiver to Second Amended and Restated Credit Agreement dated as of March 13, 2020, 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 10.1 to the Company’s Current Report on Form 8-K filed on March 16, 2020).
10.52	Twelfth Amendment and Waiver to Second Amended and Restated Credit Agreement dated as of March 30,2020, 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 10.1 to the Company’s Current Report on Form 8-K filed on March 30, 2020).
10.53	Thirteenth Amendment and Waiver to Second Amended and Restated Credit Agreement dated as of April 14,2020, 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 10.1 to the Company’s Current Report on Form 8-K filed on April 14, 2020).
10.54	Resignation Letter of Mark Christensen dated April 14, 2020 (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 15, 2020).
10.55	Resignation Letter of Robert Glenn Dawson dated April 14, 2020 (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on April 15, 2020).
10.56	Resignation Letter of Ronald D. Ormand dated April 14, 2020 (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on April 15, 2020).
10.57	Fourteenth Amendment and Waiver to Second Amended and Restated Credit Agreement dated as of April 21,2020, 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 10.1 to the Company’s Current Report on Form 8-K filed on April 21, 2020).
21.1*	List of Subsidiaries of the Company.
23.1*	Consent of BDO USA, LLP for the Company.
23.2*	Consent of LaRoche Petroleum Consultants, Ltd., independent petroleum engineers for the Company.
23.3*	Consent of Cawley. Gillespie & Associates, Inc., independent petroleum engineers for the Company.
31.1*	Certifications Pursuant to Section 302 of Sarbanes Oxley Act of 2002.
32.1*	Certifications Pursuant to Section 906 of Sarbanes Oxley Act of 2002.
99.1*	Report of LaRoche Petroleum Consultants, Ltd., dated March 12, 2020, for the Company.
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.

c) Financial Statement Schedules

Not applicable.

Item 16. Form 10-K Summary

None.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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: April 30, 2020	By:	/s/ Joseph C. Daches
		Joseph C. Daches
		Chief Executive Officer, President, and Chief Financial Officer

Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated.



Signature	Title	Date

/s/ Joseph C. Daches	Chief Executive Officer, President, and Chief Financial Officer	April 30, 2020
Joseph C. Daches	(Principal Executive Officer and Principal Financial and Accounting Officer)

/s/ Nuno Brandolini	Director	April 30, 2020
Nuno Brandolini

/s/ John Johanning	Director	April 30, 2020
John Johanning

/s/ Markus Specks	Director	April 30, 2020
Markus Specks

/s/ Michael G. Long	Director	April 30, 2020
Michael G. Long

/s/ Nicholas Steinsberger	Director	April 30, 2020
Nicholas Steinsberger

Index to Financial Statements



Reports of Independent Registered Public Accounting Firm	85
Consolidated Balance Sheets as of December 31, 2019 and 2018	86
Consolidated Statements of Operations for the Years Ended December 31, 2019 and 2018	88
Consolidated Statements of Changes in Stockholders’ Equity (Deficit) for the Years Ended December 31, 2019 and 2018	89
Consolidated Statements of Cash Flows for the Years Ended December 31, 2019 and 2018	90
Notes to Consolidated Financial Statements	92
Supplementary Information on Oil and Natural Gas Exploration, Development and Production Activities (unaudited)	133

Report of Independent Registered Public Accounting Firm

Shareholders and Board of Directors

Lilis Energy, Inc.

Fort Worth, Texas

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Lilis Energy, Inc. (the “Company”) as of December 31, 2019 and 2018, the related consolidated statements of operations, changes in stockholders’ equity (deficit), and cash flows for each of the two years in the period ended December 31, 2019, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

Going Concern Uncertainty

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the consolidated financial statements, the Company has incurred significant losses, negative cash flows from operations, and working capital deficiencies. Additionally, the Company has significant borrowing base deficiency payments due under its revolving credit agreement and does not anticipate maintaining compliance with the debt covenants contained in its revolving credit agreement during 2020, which may accelerate the Company’s debt obligations. These matters raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ BDO USA, LLP

We have served as the Company’s auditor since 2017.

Dallas, Texas

April 30, 2020

Lilis Energy, Inc. and Subsidiaries

Consolidated Balance Sheets

(In thousands, except share and per share data)



	December 31,
	2019		2018
ASSETS
Current assets:
Cash and cash equivalents	$	3,753	$	21,137
Accounts receivable, net of allowance of $448 and $25, respectively	18,146		20,546
Derivative instruments	427		2,551
Prepaid expenses and other current assets	4,438		1,851
Total current assets	26,764		46,085
Property and equipment:
Oil and natural gas properties, full cost method of accounting, net	228,855		430,379
Other property and equipment, net	421		524
Total property and equipment, net	229,276		430,903
Right-of-use assets	1,722		—
Other assets	837		3,785
Total assets	$	258,599	$	480,773
LIABILITIES, MEZZANINE EQUITY AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities:
Current portion of long-term debt	$	115,000	$	—
Accounts payable	24,834		47,112
Accrued liabilities and other	13,972		14,794
Revenue payable	11,442		14,546
Derivative instruments	5,044		515
Total current liabilities	170,292		76,967
Asset retirement obligations	3,423		2,433
Long-term debt	—		157,804
Long-term derivative instruments and other non-current liabilities	3,762		4,699
Long-term deferred revenue and other long-term liabilities	73,749		52,513
Total liabilities	251,226		294,416
Commitments and Contingencies - Note 21
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 $1,203 and $1,093, per share, as of December 31, 2019 and 2018, respectively	80,446		106,774
Series C-2 9.75% Participating Preferred Stock, 25,000 shares issued and outstanding with a stated value of $1,128 and $1,024, per share, as of December 31, 2019 and 2018, respectively	18,857		25,522
Series D 8.25% Participating Preferred Stock, 39,254 shares issued and outstanding with a stated value of $1,107 and $1,021, per share, as of December 31, 2019 and 2018, respectively	29,082		40,729
Series E 8.25% Convertible Participating Preferred Stock, 60,000 shares issued and outstanding with a stated value of $1,069, per share, as of December 31, 2019	66,285		—
Series F 9.00% Participating Preferred Stock, 55,000 shares issued and outstanding with a stated value of $1,076, per share, as of December 31, 2019	50,861		—



Stockholders’ equity (deficit):
Common stock, $0.0001 par value per share, 150,000,000 shares authorized 91,584,460 and 71,182,016 issued and outstanding as of December 31, 2019 and December 31, 2018, respectively	9			7
Additional paid-in capital	342,382			321,753
Treasury stock, 253,598 shares at cost	(997		)	(997		)
Accumulated deficit	(579,552		)	(307,431		)
Total stockholders’ equity (deficit)	(238,158		)	13,332
Total liabilities, mezzanine equity and stockholders’ equity (deficit)	$	258,599		$	480,773

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

Lilis Energy, Inc. and Subsidiaries

Consolidated Statements of Operations

(In thousands, except share and per share data)



	Year Ended December 31,
	2019			2018
Revenues:
Oil sales	$	59,015		$	58,042
Natural gas sales	3,180			5,246
Natural gas liquid sales	3,868			6,928
Total revenues	66,063			70,216
Operating expenses:
Production costs	16,127			13,843
Gathering, processing and transportation	3,960			3,392
Production taxes	3,302			3,709
General and administrative	28,371			33,251
Depreciation, depletion, amortization and accretion	33,252			25,367
Impairment of oil and natural gas properties	228,324			—
Total operating expenses	313,336			79,562
Operating loss	(247,273		)	(9,346		)
Other income (expense):
Loss on early extinguishment of debt	(1,299		)	(20,370		)
Gain (loss) from commodity derivatives	(8,985		)	55
Change in fair value of financial instruments	(3,573		)	58,343
Interest expense	(11,426		)	(32,827		)
Other income	435			2
Total other income (expense)	(24,848		)	5,203
Net loss before income taxes	(272,121		)	(4,143		)
Income tax expense	—			—
Net loss	(272,121		)	(4,143		)
Paid-in-kind dividends on preferred stock	(25,397		)	(10,687		)
Net loss attributable to common stockholders	$	(297,518	)	$	(14,830	)

Net loss per common share-basic and diluted: (Note 18)
Basic	$	(3.38	)	$	(0.24	)
Diluted	$	(3.38	)	$	(0.47	)

Weighted average common shares outstanding:
Basic	87,912,362			62,854,214
Diluted	87,912,362			78,451,341

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

Lilis Energy, Inc. and Subsidiaries

Consolidated Statements of Changes in Stockholders’ Equity (Deficit)

(In thousands, except share data)



	Common Shares				Additional Paid-In Capital			Treasury Shares					Accumulated Deficit			Total
	Shares		Amount		Additional Paid-In Capital			Shares		Amount			Accumulated Deficit			Total
Balance, January 1, 2018	53,368,331		$	5	$	272,335		—		$	—		$	(303,288	)	$	(30,948	)
Stock-based compensation	—		—		9,000			—		—			—			9,000
Common stock for restricted stock	404,093		—		—			—		—			—			—
Common stock withheld for taxes on stock-based compensation	(484,727	)	—		(2,230		)	—		—			—			(2,230		)
Common stock for acquisition of oil and natural gas properties	6,940,722		1		24,777			—		—			—			24,778
Exercise of warrants and stock options	5,000,834		—		3,751			—		—			—			3,751
Common stock issued for extinguishment of debt	5,952,763		1		24,584			—		—			—			24,585
Reclassification of warrant derivative liabilities	—		—		223			—		—			—			223
Purchase of treasury stock	—		—		—			(253,598	)	(997		)	—			(997		)
Dividends on preferred stock	—		—		(10,687		)	—		—			—			(10,687		)
Net loss	—		—		—			—		—			(4,143		)	(4,143		)
Balance, December 31, 2018	71,182,016		$	7	$	321,753		(253,598	)	$	(997	)	$	(307,431	)	$	13,332
Stock-based compensation	—		—		6,506			—		—			—			6,506
Common stock for restricted stock	3,178,448		—		—			—		—			—			—
Common stock withheld for taxes on stock-based compensation	(417,642	)	—		(546		)	—		—			—			(546		)
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	—		—		(25,397		)	—		—			—			(25,397		)
Net loss	—		—		—			—		—			(272,121		)	(272,121		)
Balance, December 31, 2019	91,584,460		$	9	$	342,382		(253,598	)	$	(997	)	$	(579,552	)	$	(238,158	)

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

Lilis Energy, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(In thousands)



	Year Ended December 31,
	2019			2018
Cash flows from operating activities:
Net loss	$	(272,121	)	$	(4,143	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Stock-based compensation	6,506			9,000
Bad debt recovery	422			106
Amortization of debt issuance cost and accretion of debt discount	2,460			15,656
Payable in-kind interest	1,590			12,213
Loss on early extinguishment of debt	1,299			20,370
Loss (gain) from commodity derivatives, net	8,985			(55		)
Net settlements paid on commodity derivatives	(3,214		)	(2,742		)
Change in fair value of financial instruments	3,573			(58,343		)
Deferred revenue realized	(232		)	—
Impairment of oil and natural gas properties	228,324			—
Depreciation, depletion, amortization and accretion	33,252			25,367
Operating lease ROU amortization	(453		)	—
Changes in operating assets and liabilities:
Accounts receivable	(6,378		)	(13,226		)
Prepaid expenses and other assets	(944		)	(473		)
Accounts payable and accrued liabilities	(31,393		)	53,402
Proceeds from options associated with future midstream services	2,500			35,000
Net cash (used in) provided by operating activities	(25,824		)	92,132
Cash flows from investing activities:
Acquisition of oil and natural gas properties	—			(92,410		)
Proceeds from the sale of assets	16,851			17,500
Capital expenditures	(82,378		)	(168,025		)
Net cash used in investing activities	(65,527		)	(242,935		)
Cash flows from financing activities:
Proceeds from term loans, net of financing costs	—			47,806
Proceeds from revolving credit agreement, net of financing costs	56,883			72,566
Repayment of term loans and notes payable	—			(88,836		)
Repayment of revolving credit agreement	(18,000		)	—
Proceeds from the issuance of Series C Preferred Stock	—			122,418
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	—			3,751
Payment for tax withholding on stock-based compensation	(546		)	(2,230		)
Net cash provided by financing activities	73,967			154,478
Net increase (decrease) in cash and cash equivalents	(17,384		)	3,675
Cash and cash equivalents at beginning of period	21,137			17,462
Cash and cash equivalents at end of period	$	3,753		$	21,137
Supplemental disclosure:
Cash paid for interest	$	6,488		$	4,958

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

Lilis Energy, Inc. and Subsidiaries

Notes to 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 - LIQUIDITY AND GOING CONCERN

These consolidated financial statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business for the twelve-month period following the date of issuance of these consolidated financial statements. As such, the accompanying consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets and their carrying amount, or the amount and classification of liabilities that may result should the Company be unable to continue as a going concern.

As of December 31, 2019, we were fully drawn against the borrowing base under our Revolving Credit Agreement (as defined in Note 11 - Long-Term Debt), with $115.0 million of indebtedness outstanding under our Revolving Credit Agreement. As provided for in the Seventh Amendment to our Revolving Credit Agreement and as a result of a decrease in commodity prices, on January 17, 2020, the borrowing base was decreased to $90.0 million.

As a result of the January 17, 2020 redetermination of the borrowing base, a borrowing base deficiency in the amount of $25.0 million (the “Borrowing Base Deficiency”) was created under the Revolving Credit Agreement. The Borrowing Base Deficiency constitutes the difference between the principal amount of borrowings currently outstanding under the Revolving Credit Agreement ($115.0 million) and the borrowing base as so redetermined ($90.0 million). On February 28, 2020, we paid $17.3 million towards the Borrowing Base Deficiency. Pursuant to the Fourteenth Amendment to the Revolving Credit Agreement, the remaining payment of $7.8 million is due June 5, 2020.

The Company is seeking additional funding and considering certain strategic transactions to enable it to pay the remaining Borrowing Base Deficiency amount of $7.8 million. Unless funding or additional transactions are completed, the Company will not be able to pay the remaining Borrowing Base Deficiency. There is no assurance that such transactions will occur or that the bank group will agree to further deficiency payment extensions. If the Company is unable to repay the remaining borrowing base deficiency as and when required under the Revolving Credit Agreement, an event of default would occur under the Revolving Credit Agreement.

Our next borrowing base redetermination is scheduled to occur on or about June 5, 2020. If the borrowing base is further reduced by the lenders in connection with this redetermination, we will be required to repay borrowings in excess of the borrowing base or eliminate the borrowing base deficiency by pledging additional oil and natural gas properties to secure our obligations under the Revolving Credit Agreement. Under the Revolving Credit Agreement, we have the option to affect such repayment either in full within 30 days after the redetermination or in monthly installments over a six-month period after the redetermination.

We have experienced losses and negative cash flows from operations and working capital deficiencies. Additionally, our liquidity and operating forecasts have been negatively impacted by the recent decrease in commodity prices, which impacts our ability to comply with debt covenants under our Revolving Credit Agreement. The commodity prices have fallen significantly since the beginning of 2020, due in part to failed OPEC negotiations as well as concerns about the COVID-19 pandemic, which has significantly decreased worldwide demand for oil and natural gas. Our Revolving Credit Agreement contains financial covenants that require the Company to maintain a ratio of Total Debt to EBITDAX (each as defined in the Revolving Credit Agreement) (the “Leverage Ratio”) of not more than 4.00 to 1.00 and a ratio of Current Assets to Current Liabilities (each as defined in the Revolving Credit Agreement) (the “Current Ratio”) of not less than 1.00 to 1.00 as of the last day of each fiscal quarter thereafter. See Note 11-Long-term Debt for additional information regarding the financial covenants under our Revolving Credit Agreement. As of December 31, 2019, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants under the Revolving Credit Agreement. Pursuant to the Twelfth Amendment (as defined in Note 11 - Long-Term Debt), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants, among other waivers of default, as of December 31, 2019.

obligations of the Company under the Revolving Credit Agreement may be accelerated, which would have a material adverse effect on our business. The Company does not expect to be in compliance with debt covenants in future periods without additional sources of liquidity or future amendments to the Revolving Credit Agreement.

Fluctuations in oil and natural gas prices have a material impact on our financial position, results of operations, cash flows and quantities of oil, natural gas and NGL reserves that may be economically produced. Historically, oil and natural gas prices have been volatile, and may be subject to wide fluctuations in the future. If continued depressed prices persist, the Company will continue to experience operating losses, negative cash flows from operating activities, and negative working capital.

In order to improve our leverage position and current ratio to meet the financial covenants under the Revolving Credit Agreement, we are currently pursuing or considering a number of actions, which in certain cases may require the consent of current lenders and stockholders. In November 2019, our board of directors formed a committee of independent directors (the “Special Committee”) tasked with reviewing and evaluating strategic alternatives that may enhance the value of the Company, including alternatives that may be available to identify and access further sources of liquidity through financing alternatives or deleveraging transactions. The Special Committee hired financial and legal advisors to advise the Special Committee on these matters.

The Special Committee continues to explore financing alternatives and deleveraging transactions. We are also addressing operational matters such as adjusting our capital budget and improving cash flows from operations by continuing to reduce costs and intend to continue to pursue and consider other strategic alternatives.

There can be no assurance that we will be able to implement any of these plans successfully, or that such plans, if executed, will result in the ability to pay borrowing base deficiencies, generate sufficient liquidity to continue as a going concern or comply with our Revolving Credit Agreement covenants. The factors discussed above raise substantial doubt about our ability to continue as a going concern within twelve-month period following the date of issuance of these consolidated financial statements.

NOTE 3 - BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation and Presentation

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

Use of Estimates

Reclassifications

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

Cash and Cash Equivalents

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

Accounts Receivable

The Company has accounts receivable from joint interest owners of properties operated by the Company. The Company typically has the right to withhold future revenue disbursements to recover any non-payment of related joint interest billings. Management routinely assesses accounts receivable amounts to determine their collectability and accrues an allowance for uncollectible receivables when, based on the judgment of management, it is probable that a receivable will not be collected. The Company records actual and estimated oil and natural gas revenue receivable from third parties at its net revenue interest. In addition, the Company has receivables derived from sales of certain oil and natural gas production which are collateral under the Company’s credit agreements. The Company had an allowance for doubtful accounts of $0.4 million as of December 31, 2019. There was no allowance for doubtful accounts as of December 31, 2018.

Fair Value of Financial Instruments

As of December 31, 2019, and 2018, the carrying value of cash and cash equivalents, accounts receivable, accounts payable, accrued liabilities, revenue payable and advances from joint interest partners approximates fair value due to the short-term nature of such items. The carrying value of the Company’s secured debt is carried at cost which approximates the fair value of the debt as the related interest rates approximates interest rates currently available to the Company.

Oil and Natural Gas Properties

The Company uses the full cost method of accounting for oil and natural gas operations. Under this method, costs related to the exploration, non-production related development and acquisition of oil and natural gas reserves are capitalized. Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling, developing and completing productive wells, and any other costs directly related to acquisition and exploration activities. Proceeds from property sales are generally applied as a credit against capitalized exploration and development costs, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of proved reserves.

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

Under the full cost method of accounting, capitalized oil and natural gas property costs less accumulated depletion (net of deferred income taxes) may not exceed an amount equal to the sum of the present value, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves and the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are not subject to amortization. Should capitalized costs exceed this ceiling, an impairment expense is recognized. The present value of estimated future net cash flows was computed by applying a flat oil price to forecast revenues from estimated future production of proved oil and natural gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves (assuming the continuation of existing economic conditions), less any applicable future taxes. For the year ended December 31, 2019, the ceiling value of the Company’s reserves was calculated based upon SEC pricing of $55.69 per barrel for oil and $2.58 per MMBtu for natural gas. For the year ended December 31, 2018, the ceiling value of the Company’s reserves was calculated based upon SEC pricing of $65.56 per barrel for oil and $3.10 per MMBtu for natural gas. Full-cost ceiling impairments totaling $228.3 million were recorded for the year ended December 31, 2019 and resulted primarily from decreased commodity prices and reduction in expected PUDs used in preparation of estimated future net revenues from proved oil and natural gas reserves as compared to the commodity prices used for the year ended December 31, 2018, when no such impairments were recognized.

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

Wells in Progress

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

Capitalized Interest

For significant oil and natural gas investments in unproved properties, and significant exploration and development projects that have not commenced production, interest is capitalized as part of the historical cost of developing and constructing assets. Capitalized interest is determined by multiplying the Company’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depreciation or impairment. As of December 31, 2019, there were no significant exploratory projects on unproved properties and none of the development projects exceeded the interest capitalization qualifying asset limit. As a result, no interest was capitalized as of December 31, 2019 and 2018.

Other Property and Equipment

Property and equipment include vehicles, office equipment and furniture which are stated at cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets. The estimated useful lives of property and equipment range from 4 to 20 years. The Company recorded approximately $0.2 million and $0.1 million of depreciation for the years ended December 31, 2019 and 2018, respectively.

Asset Retirement Obligations

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

Revenue Recognition

Stock based Compensation

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

stock based compensation expense. The fair value of restricted stock awards is identified as the closing stock price on the day the award was granted. The Company recognizes forfeitures as and when the stock awards are forfeited.

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

Income Taxes

Concentration of Credit Risk

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

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

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

Derivative Instruments

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

recognized in current earnings since the Company has elected not to designate its current derivative contracts as cash flow hedges for accounting purposes.

The Company has recognized certain conversion features within its Second Lien Term Loan as embedded derivatives that have been bifurcated from the Second Lien Term Loan, as defined in Note 9 - Derivatives, and accounted for separately from the debt.

The Company has recognized that our crude oil sales agreement with ARM no longer meets the criteria for the “normal purchase normal sales” exception under ASC 815, “Derivatives and Hedging,” due to the Company not meeting the minimum quantities deliverable under the contract and the net settlement criteria being met. As a result, an embedded derivative exists as it is no longer probable the contract will only result in physical deliveries of crude oil and may net settle. See Note 9 - Derivatives for additional information.

Recently Adopted Accounting Standards

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

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

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

Accounting Standards Not Yet Adopted

In June 2016, the FASB issued ASU 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which replaces the currently required incurred loss methodology with an expected loss methodology. This new methodology requires that a financial asset measured at amortized cost be presented at the net amount expected to be collected. The update is intended to provide financial statement users with more useful information about expected credit losses on financial instruments. The amended standard is effective for the Company on January 1, 2023, with early adoption permitted, and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Company is evaluating the impact the adoption of ASU 2016-13 will have on its consolidated financial statements.

In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement, which modifies the fair value disclosure requirements based on application of the disclosure framework. The provisions removed or amended certain disclosures and in some cases, the ASU requires additional disclosures. The standard is effective for the Company for fiscal years, and interim periods within those years, beginning after December 15, 2019. The Company is evaluating the impact the adoption of ASU 2018-13 will have on its consolidated financial statements.

Accrued Liabilities and Other

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



	2019		2018
	(In thousands)
Accrued personnel costs	$	—	$	2,300
Accrued drilling and completion costs	5,021		2,849
Drilling advances	1,328		5,001
Accrued production expenses	3,326		2,926
Other accrued liabilities	3,885		1,718
Short-term operating lease liabilities	412		—
	$	13,972	$	14,794

NOTE 4 - OIL AND NATURAL GAS PROPERTIES

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



	December 31,
	2019			2018
	(In thousands)
Oil and natural gas properties:
Proved	$	478,569		$	358,858
Unproved	109,590			169,863
Total oil and natural gas properties	588,159			528,721
Accumulated depletion, depreciation, amortization and impairment	(359,304		)	(98,342		)
Oil and natural gas properties, net	$	228,855		$	430,379

The following table sets forth a summary of costs withheld from amortization as of December 31, 2019:



	Year of Acquisition
	Total		2019		2018		2017
	(In thousands)
Unamortized costs:
Unproved leasehold costs	$	109,590	$	1,643	$	85,598	$	22,349
Total	$	109,590	$	1,643	$	85,598	$	22,349

For the years ended December 31, 2019 and 2018, $56.2 million and $11.1 million, respectively, of unproved property costs were recorded as impairments of unproved property costs and transferred to proved properties. Impairments for 2019 were the result of title defects, lease expirations, changes to management’s development plans and uncertainty that the Company will have access to necessary funding to either extend the leases expiring in 2020 or begin drilling before their expiration dates. The 2018 impairment of $11.1 million was the result of defective titles for certain leases.

Depreciation, depletion and amortization expense related to proved properties was approximately $32.6 million and $25.2 million, respectively for the years ended December 31, 2019 and 2018. Full-cost ceiling impairments totaling $228.3 million were recorded for the year ended December 31, 2019. For the year ended December 31, 2018, no such impairments were recognized.

The 2019 impairment charges were the result of a decrease in crude oil and natural gas prices used in preparation of the proved reserves estimates. Additionally, proved undeveloped reserves previously included in the Company’s proved reserves report were reclassified as unproved because of the uncertainty regarding the availability of capital for development those reserves as of December 31, 2019. The reclassification of proved undeveloped reserves to unproved are recognized in the Company’s proved reserves report as of December 31, 2019. These changes have contributed, in part, to higher depletion rates for 2019 as compared to 2018.

NOTE 5 - ACQUISITIONS AND DIVESTITURES

Divestitures During 2019

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

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

The Company entered into a Purchase and Sale Agreement with WLWI (the “WI Agreement”), pursuant to which the Company sold an undivided 49% of its right, title and interest in certain undeveloped assets located in Winkler and Loving Counties, Texas, consisting of approximately 749 net acres. The WI Agreement provides that the Company must drill, complete and equip five commitment wells after closing (the “Development Plan”). Contemporaneously with the purchase, WLWI paid a drilling advance which funded its proportionate share of the development costs to drill, complete and equip such commitment wells. Any drilling cost overruns or costs incurred below estimated costs are the responsibility of the Company. As of December 31, 2019, three of the five commitment wells are producing, the fourth well is drilled and awaiting completion and the fifth well has not yet been drilled. Under the WI Agreement, the fourth and fifth wells are required to begin production mid-year 2020, subject to reasonable delays on account of Force Majeure or modifications or revisions to the Development Plan as approved by both parties. Should the Company otherwise breach the scheduled Development Plan, WLWI shall be entitled to liquidated damages of an amount equal to $150,000 plus $1,500 for each day beyond a 60-day period after Development Plan commitment date until the actual date of first production.

The WI Agreement provides the Company with a right to repurchase all, but not less than all, of the interest for a period of three years and an obligation, at WLWI’s election only upon a change of control, to repurchase all, but not less than all, of the interest, and also includes certain limitations on WLWI’s right to transfer the interest during such three year period without the consent of the Company. The repurchase price is 1.5 times the consideration paid by WLWI plus additional capital expenditures of WLWI. The repurchase period expires after three years.

As a result of the repurchase rights, the agreements with WLR and WLWI do not meet the criteria for a conveyance or sale of assets under ASC 932, “Extractive Activities - Oil & Gas”, and are accounted for as a financing arrangement. The net proceeds of the transaction of $39.0 million are included in long-term deferred revenue and other long-term liabilities on the Company’s consolidated balance sheet as of December 31, 2019. WLR’s proportionate share of revenue of $0.4 million and WLWI’s proportionate share of net revenues, (revenues less production costs), of $0.5 million for the year ended December 31, 2019 is included in interest expense on the Company’s consolidated statements of operations.

On August 16, 2019, we sold approximately 513 noncontiguous net acres in New Mexico for net cash proceeds of $16.7 million, which was recorded as a reduction to the full cost pool. The Company repurchased certain overriding royalty interests in the acreage previously sold to WLR under the ORRI Agreement for $2.6 million, resulting in a $1.3 million loss on extinguishment of a portion of the financing arrangement and is included in loss on early extinguishment of debt on the Company’s consolidated statements of operations.

On February 28, 2020, the Company closed on the sale of approximately 1,185 undeveloped net acres in Lea County, New Mexico, for net cash proceeds of approximately $24.1 million, subject to customary purchase price adjustments (the “Marlin Disposition”). The proceeds were used to fund a substantial portion of the Borrowing Base Deficiency with the balance to be used for general corporate purposes.

Acquisitions During 2018

During the year ended December 31, 2018, the Company acquired the following oil and natural gas properties:

•

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


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


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


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


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

•

Proved property and certain leasehold interests located in Winkler County, Texas from Southwest Royalties, LLC for total consideration of approximately $17.0 million. The acquisition was accounted for as a business combination. Therefore the purchase price was allocated to the assets acquired and liabilities assumed based on their estimated acquisition date fair values available at closing. Transaction costs associated for this acquisition were immaterial and were expensed in the Consolidated Statements for Operations during the year ended December 31, 2018. Revenues and operating expenses associated with the proved properties were insignificant to the December 31, 2018 Consolidated Statements of Operations. The following table presents the final allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date:



	As of October 16, 2018
	(In thousands)
Fair value of net assets:
Proved oil and natural gas properties	$	12,562
Unproved oil and natural gas properties	4,542
Total assets acquired	17,104
Asset retirement obligations assumed	(65		)
Fair value of net assets acquired	$	17,039

NOTE 6 - ASSET RETIREMENT OBLIGATIONS

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

100

The following table summarizes the changes in the Company’s ARO for the years ended December 31, 2019 and 2018:



	For the Year Ended December 31,
	2019			2018
	(In thousands)
ARO, beginning of period	$	2,444		$	952
Additional liabilities incurred	186			374
Accretion expense	433			85
Liabilities settled	(78		)	(87		)
Revision in estimates	438			1,120
ARO, end of period	3,423			2,444
Less: current portion of ARO ⁽¹⁾	—			(11		)
ARO, non-current	$	3,423		$	2,433

⁽¹⁾ The current portion of ARO is included in accrued liabilities in the consolidated balance sheets.

NOTE 7 - REVENUE

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

Crude Oil Revenues

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

Effective March 1, 2019, the Company’s crude oil is sold under a single long-term contract with a term that extends to at least December 31, 2024. The purchaser’s commitment has a quantity-based minimum set forth in the contract, measured in barrels per day, with the minimum quantity commitment increasing at periodic intervals over the life of the contract to coincide with the Company’s expected growth in production.

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

101

Natural Gas and NGL Revenues

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

Gathering, Processing and Transportation

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

Imbalances

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

Contract balances and prior period performance obligations

The Company is entitled to payment from purchasers once its performance obligations have been satisfied upon delivery of the product, at which point payment is unconditional, and the Company records these invoiced amounts as accounts receivable

in its condensed consolidated balance sheets. To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and also recorded as accounts receivable in the accompanying consolidated balance sheets. In this scenario, payment is unconditional, as the Company has satisfied its performance obligations through delivery of the relevant product. As a result, the Company has concluded that its product sales do not give rise to contract assets or liabilities.

The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and NGL sales may not be received for 30 to 60 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production that was delivered to the customer and the price that will be received for the sale of the product. Additionally, to the extent actual volumes and prices of oil, natural gas and NGLs are unavailable for a given reporting period because of timing or information not received from third-party purchasers, the expected sales volumes and prices for those barrels of oil, cubic feet of gas and gallons of NGL are also estimated. The Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls in place for its estimation process, and any identified differences between its revenue estimates and actual revenue received historically have not been significant.

Significant judgments

The Company engages in various types of transactions in which midstream entities process its gas and subsequently market resulting NGLs and residue gas to third-party customers on the Company’s behalf per gas purchase contracts. These types of transactions require judgment to determine whether the Company is the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net. The Company maintains control of the natural gas and NGLs during processing and considers itself the principal in these arrangements.

102

Practical expedients

A significant number of the Company’s product sales are short-term in nature with contract term of one year or less. For those contracts, the Company utilizes the practical expedient that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For the Company’s product sales that have contract terms less than one year, the Company utilizes the practical expedient in the new revenue standard that states that it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

The following table disaggregates the Company’s revenue by contract type (in thousands) for the year ended December 31, 2019:



Year Ended December 31, 2019	Short-term contracts		Long-term contracts		Total
Crude oil	$	9,711	$	49,304	$	59,015
Natural gas	220		2,960		3,180
NGLs	188		3,680		3,868

Customer Credit Risk

Our principal exposure to credit risk is through receivables from the sale of our oil and natural gas production of approximately $9.1 million and $8.2 million at December 31, 2019 and 2018, respectively, and through actual and accrued receivables from our joint interest partners of approximately $9.5 million and $11.4 million at December 31, 2019 and 2018, respectively. We are subject to credit risk due to the concentration of our oil and natural gas receivables with our most significant customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

Major Customers

During the year ended December 31, 2019, the Company’s major customers as a percentage of total revenue consisted of the following:



	Year ended December 31,
	2019		2018
ARM Energy Management, LLC	68	%	—	%
Texican Crude & Hydrocarbon, LLC	19	%	87	%
Lucid Energy Delaware, LLC	12	%	10	%
Other below 10%	1	%	3	%
	100	%	100	%

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.

103

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

Recurring Fair Value Measurements



	Fair Value Measurement Classification
	Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total
	(In thousands)
As of December 31, 2019
Oil and natural gas derivative instruments:
Oil and natural gas derivative swap contracts	$	—	$	(3,932	)	$	—		$	(3,932	)
Oil and natural gas derivative collar contracts	—		301			—			301
Embedded derivative instruments:
Net settlement provisions under ARM sales agreement	—		—			(3,238		)	(3,238		)
Total	$	—	$	(3,631	)	$	(3,238	)	$	(6,869	)
As of December 31, 2018
Oil and natural gas derivative instruments:
Oil and natural gas derivative swap contracts	$	—	$	(2,923	)	$	—		$	(2,923	)
Oil and natural gas derivative collar contracts	—		4,047			—			4,047
Embedded derivative instruments:
Second Lien Term Loan conversion features	—		—			(1,965		)	(1,965		)
Total	$	—	$	1,124		$	(1,965	)	$	(841	)

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

In addition, derivative liabilities as of December 31, 2019 include an embedded derivative associated with the ARM sales agreement (see Note 21 - Commitments and Contingencies). The Company recognized a derivative liability and an unrealized loss of $3.2 million as of December 31, 2019. This embedded derivative has fewer observable inputs from objective sources and are therefore measured using Level 3 inputs. The fair value of the net settlement provisions under the agreement was determined based on certain assumptions including (1) forward pricing for crude oil basis differentials, (ii) future LIBOR rates and (iii) the Company’s implied credit rating.

The Company’s derivative liabilities as of December 31, 2018 also include embedded derivatives associated with the Second Lien Term Loan (as defined in Note 11 - Long-Term Debt). These instruments have fewer observable inputs from objective sources and are therefore measured using Level 3 inputs. The Company recorded an unrealized loss of $0.3 million and $58.3 million on the change in fair value of derivative liabilities associated with the Second Lien Term Loan conversion features for the years ended December 31, 2019 and 2018, respectively.

The fair value of the holder conversion features was determined using a binomial lattice model based on certain assumptions including (i) the Company’s stock price, (ii) risk-free rate, (iii) expected volatility, (iv) the Company’s implied credit rating, and (v) the implied credit yield of the Loan.

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The following table sets forth a reconciliation of changes in the fair value of the Company’s financial assets and liabilities classified as Level 3 in the fair value hierarchy, except for the commodity derivatives classified as Level 2, as disclosed in Note 9, as of December 31, 2019 and 2018:



	Firm Takeaway and Pricing Agreement Net Settlement Provisions			Second Lien Term Loan Conversion Features			Total
	(in thousands)
Balance at January 1, 2019	$	—		$	(1,965	)	$	(1,965	)
Fair value of the converted portion of the embedded derivatives associated with the Second Lien Term Loan	—			2,300			2,300
Fair value of the embedded derivatives in ARM Sales Agreement	(3,238		)	(335		)	(3,573		)
Balance at December 31, 2019	$	(3,238	)	$	—		$	(3,238	)



	Second Lien Term Loan Conversion Features			Warrant Liabilities			Total
	(in thousands)
Balance at January 1, 2018	$	(72,714	)	$	(223	)	$	(72,937	)
Transferred to equity	—			223			223
Fair value of the converted portion of the embedded derivatives associated with the Second Lien Term Loan	12,406			—			12,406
Change in fair value of derivative liabilities	58,343			—			58,343
Balance at December 31, 2018	$	(1,965	)	$	—		$	(1,965	)

NOTE 9 - DERIVATIVES

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



	December 31,
	2019			2018
	(In thousands)
Derivative assets (liabilities):
Derivative assets - current	$	427		$	2,551
Derivative assets - non-current⁽¹⁾	187			1,822
Derivative liabilities - current⁽³⁾	(5,044		)	(515		)
Derivative liabilities - non-current^{(2) (3) (4)}	(2,439		)	(4,699		)
Total derivative liabilities, net	$	(6,869	)	$	(841	)

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

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

⁽³⁾The ARM sales agreement includes an embedded derivative. As of December 31, 2019, the embedded derivative is included as current liabilities and non-current liabilities of $0.8 million and $2.4 million, respectively.

⁽⁴⁾Includes $2.0 million embedded derivative associated with Second Lien Term Loan and $2.7 million in commodity derivatives as of December 31, 2018.

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Embedded Derivatives

As discussed in Note 21 - Commitments and Contingencies, the ARM sales agreement contains minimum quantity commitments. Should the Company be unable to meet those minimum commitments, the agreement contains a two way make whole provision that allows for net settlement. As of December 31, 2019, the Company concluded it is no longer probable they will be able to make delivery of the minimum quantities specified in the agreement. The Company has, therefore recorded the fair value of the embedded derivative as of December 31, 2019. The net settlement feature for remaining future minimum commitment volumes are considered embedded derivatives that are recorded, with changes in fair value included in the Company’s consolidated statement of operations.

As of December 31, 2019, the derivative liability associated with the ARM sales agreement was approximately $3.2 million with $0.8 million recorded in current derivative instruments and $2.4 million recorded in long-term derivative instruments on the Company’s consolidated balance sheets.

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

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

Commodity Derivatives

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

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

All of our derivatives are accounted for as mark-to-market activities. Under Accounting Standard Codification (“ASC”) Topic 815, “Derivatives and Hedging,” these instruments are recorded on the Company’s consolidated balance sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. The Company nets derivative assets and liabilities by commodity for counterparties where a legal right to such offset exists. Because the Company has elected not to designate its current derivative contracts as cash flow hedges for accounting purposes, changes in the fair values of the derivatives are recognized in current earnings.

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The following table presents the Company’s derivative position for the production periods indicated as of December 31, 2019:



Description		Notional Volume (Bbls/d)	Production Period	Weighted Average Price ($/Bbl)
Oil Positions

Oil Swaps		1,028	January 2020 - December 2020	$	56.28
Oil Swaps		370	January 2021 - December 2021	$	53.07

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

3 Way Collar	Floor sold price (put)	228	January 2020 - December 2020	$	40.00
3 Way Collar	Floor purchase price (put)	228	January 2020 - December 2020	$	50.00
3 Way Collar	Ceiling sold price (call)	228	January 2020 - December 2020	$	59.60
3 Way Collar	Floor sold price (put)	80	January 2021 - December 2021	$	37.50
3 Way Collar	Floor purchase price (put)	80	January 2021 - December 2021	$	47.50
3 Way Collar	Ceiling sold price (call)	80	January 2021 - December 2021	$	59.30

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

Description		Notional Volume (MMBtus/d)	Production Period	Weighted Average Price ($/MMBtu)
Natural Gas Positions

Gas Swaps		4,557	January 2020 - December 2020	$	2.57
Gas Swaps		4,184	January 2021 - March 2021	$	2.77

3 Way Collar	Floor sold price (put)	563	January 2020 - December 2020	$	1.60
3 Way Collar	Floor purchase price (put)	563	January 2020 - December 2020	$	2.10
3 Way Collar	Ceiling sold price (call)	563	January 2020 - December 2020	$	3.00
3 Way Collar	Floor sold price (put)	133	January 2021 - December 2021	$	1.65
3 Way Collar	Floor purchase price (put)	133	January 2021 - December 2021	$	2.15
3 Way Collar	Ceiling sold price (call)	133	January 2021 - December 2021	$	3.05
Gas Collar	Floor purchase price (put)	2,748	January 2020 - December 2020	$	2.55
Gas Collar	Ceiling sold price (call)	2,748	January 2020 - December 2020	$	3.07
Gas Collar	Floor purchase price (put)	4,464	January 2021 - December 2021	$	2.20
Gas Collar	Ceiling sold price (call)	4,464	January 2021 - December 2021	$	2.97


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

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The table below summarizes the Company’s net gain (loss) on commodity derivatives for the year ended December 31, 2019 and 2018:



	Year Ended December 31,
	2019			2018
	(in thousands)
Unrealized gain (loss) on unsettled derivatives	$	(5,575	)	$	1,977
Net settlements paid on derivative contracts	(3,214		)	(2,742		)
Net settlements receivable (payable) on derivative contracts	(196		)	820
Net gain (loss) on commodity derivatives	$	(8,985	)	$	55

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



	As of December 31, 2019
	Gross Amount of Recognized Assets and Liabilities			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)
Offsetting Derivative Assets:
Current assets	$	1,009		$	(582	)	$	427
Long-term assets	359			(172		)	187
Total assets	$	1,368		$	(754	)	$	614
Offsetting Derivative Liabilities:
Current liabilities	$	(4,827	)	$	582		$	(4,245	)
Current embedded derivative liabilities	(799		)	—			(799		)
Long-term commodity derivative liabilities	(172		)	172			—
Long-term embedded derivative liabilities	(2,439		)	—			(2,439		)
Total liabilities	$	(8,237	)	$	754		$	(7,483	)



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

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NOTE 10 - LEASES

Lease Recognition

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

The Company determines if an arrangement is or contains a lease at inception of the contract and records the resulting operating lease asset on the consolidated balance sheets as an asset, with offsetting liabilities recorded as a liability. The Company recognizes a lease in the consolidated financial statements when the arrangement either explicitly or implicitly involves property or equipment, the contract terms are dependent on the use of the property or equipment, and the Company has the ability or right to operate the property or equipment or to direct others to operate the property or equipment and receives greater than 10% of the economic benefits of the assets. As of December 31, 2019, the Company does not have any financing leases.

The Company has adopted the modified retrospective method for the new lease recognition rule. Therefore, prior periods are not presented as prior period amounts have not been adjusted under the modified retrospective. Refer to Note 3 - Basis of Presentation and Summary of Significant Accounting Policies for additional information.

The Company’s ROU assets and operating lease liabilities were included in the consolidated balance sheets as follows (in thousands):



	December 31, 2019
Right of use assets:
Right of use assets - long-term⁽¹⁾	$	1,722

Lease liabilities:
Lease liabilities - current ⁽²⁾	$	412
Lease liabilities - long-term ⁽³⁾	1,323
Total lease liabilities	$	1,735

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

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

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

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

During the third quarter of 2019, the Company entered into a new long-term drilling rig lease which resulting in a lease liability and ROU asset of $10.8 million. During the 4th quarter of 2019, the Company canceled the long-term drilling rig lease, within the terms of the agreement, which resulted in the write-off of the related lease liability and ROU asset of $10.4 million.

109

Lease costs represent the straight line lease expense of ROU assets, short-term leases, and variable lease costs. The components of lease cost were classified as follows (in thousands):



	Year Ended December 31, 2019
Fixed lease costs	$	5,084
Short-term lease costs	1,096
Variable lease costs	575
Total lease costs	$	6,755



Lease Cost included in the Consolidated Financial Statements	Year Ended December 31, 2019
Oil and natural gas properties, full cost method of accounting, net⁽¹⁾
Total lease costs capitalized	$	5,688

Production costs	593
General and administrative	474
Total lease costs expensed	1,067
Total lease costs	$	6,755

⁽¹⁾Represents short-term lease capital expenditures related to drilling rigs for the year ended December 31, 2019.

During the year ended December 31, 2019, the following cash activities were associated with the Company’s leases as follows (in thousands):



Cash paid for amounts included in the measurement of operating lease liabilities:
Operating cash flows from operating leases	$	222
Investing cash flows from operating leases	$	4,768

As of December 31, 2019, the weighted average lease term and discount rate related to the Company’s remaining leases were as follows:



Lease term and discount rate
Weighted-average remaining lease term (years)	4.45
Weighted-average discount rate	5.3	%

As of December 31, 2019, minimum future payments, including imputed interest, for long-term operating leases under the scope of ASC Topic 842, “Leases”, were as follows (in thousands):



Year	Amount
2020	$	477
2021	425
2022	353
2023	379
2024	315
After 2024	—
Less: the effects of discounting	(214		)
Present value of lease liabilities	$	1,735

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



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

NOTE 11 - LONG-TERM DEBT



	December 31,
	2019			2018
	(In thousands)
8.25% Second Lien Term Loan, due 2021, net of debt issuance costs and debt discount	$	—		$	82,804
Revolving Credit Agreement, due October 2023	115,000			75,000
Total long-term debt	$	115,000		$	157,804
Less: current portion	(115,000		)	—
Total long-term debt, net of current portion	$	—		$	157,804

Revolving Credit Agreement

On October 10, 2018, the Company entered into a five-year, $500.0 million senior secured revolving credit agreement by and among the Company, as borrower, certain subsidiaries of the Company, as guarantors (the “Guarantors”), BMO Harris Bank, N.A., as administrative agent, and the lenders party thereto (the “Revolving Credit Agreement”). The Revolving Credit Agreement provides for a senior secured reserves based revolving credit facility with an initial borrowing base of $95.0 million. The borrowing base is subject to semiannual re-determinations in May and November of each year. In December 2018, the borrowing base was increased to $108.0 million in connection with our scheduled borrowing base re-determination. On March 5, 2019, the Company’s borrowing base under the Revolving Credit Agreement was increased from $108.0 million to $125.0 million, as the result of an acceleration of the scheduled May 2019 borrowing base redetermination pursuant to the First Amendment (as defined below). As provided in the Third Amendment (as defined below) and as a result of the Asset Sales (as defined in Note 5 - Acquisitions and Divestitures), in July 2019, the borrowing base was decreased to $115.0 million. As provided for in the Seventh Amendment and as a result of a decrease in commodity prices, on January 17, 2020, the borrowing base was decreased to $90.0 million. The reduction in the borrowing base resulted in a borrowing base deficiency as of January 17, 2020, of $25.0 million. We have made scheduled repayments of $17.3 million and the remaining $7.8 million is due on June 5, 2020.

As of December 31, 2019, outstanding borrowings under the Revolving Credit Agreement were $115.0 million. The Revolving Credit Agreement also provides for issuance of letters of credit in an aggregate amount of up to $5.0 million. As of December 31, 2019, we were fully drawn against the borrowing base under our Revolving Credit Agreement, with $115.0 million of indebtedness outstanding under our Revolving Credit Agreement, classified as current liability due to uncertainty of the Company’s ability to meet debt covenants over the next twelve months.

The Company capitalizes certain direct costs associated with the debt issuance under the Revolving Credit Agreement and amortizes such costs over the term of the debt instrument. The deferred financing costs related to the Revolving Credit Agreement are classified in assets. For the year ended December 31, 2019 and 2018, the Company amortized debt issuance costs associated with the Revolving Credit Agreement of $0.8 million and $2.2 million, respectively. As of December 31, 2019, the

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Company had $2.6 million of unamortized deferred financing costs in other current assets. As of December 31, 2018, the Company had $0.5 million and $1.7 million of unamortized deferred financing costs in other current assets and non-current assets, respectively.

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

Pursuant to the Fourteenth Amendment to the Revolving Credit Agreement, our next borrowing base redetermination is scheduled to occur on or about June 5, 2020. If the borrowing base is further reduced by the lenders in connection with this redetermination, we will be required to repay borrowings in excess of the borrowing base or eliminate the borrowing base deficiency by pledging additional oil and natural gas properties to secure our obligations under the Revolving Credit Agreement. Under the Revolving Credit Agreement, we have the option to affect such repayment either in full within 30 days after the redetermination or in monthly installments over a six-month period after the redetermination.

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

Compliance with the Current Ratio and Leverage Ratio covenants in future periods depends on our ability to keep wells online and consistently flowing to sales, commodity prices, our ability to control costs, and if necessary, our ability to complete sales of non-core assets or access other sources of capital to reduce indebtedness. However, our future cash flows, and consequently our EBITDAX, are subject to a number of variables, including uncertainty in forecasted production volumes and commodity prices, and we may not be able to complete sales of non-core assets or access other sources of capital on acceptable terms or at all. As of December 31, 2019, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants. Pursuant to the Twelfth Amendment, the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants as of December 31, 2019.

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

The Revolving Credit Agreement also provides for the Company to have and maintain Swap Agreements (as defined in the Revolving Credit Agreement) in respect of crude oil and natural gas, on not less than 75% of the projected production from proved reserves classified as “Developed Producing Reserves” attributable to the oil and natural gas properties of the Company, as reflected in the most recently delivered reserves report, for a period through at least 24 months after the end of each applicable quarter. For further information on our hedges, see Note 9 - Derivatives. Pursuant to the Twelfth Amendment, the Company obtained a waiver from the requisite lenders of the requirement to comply with certain hedging obligations set forth in the Credit Agreement until the quarter ending June 30, 2020.

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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.

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Fifth Amendment and Waiver to Revolving Credit Agreement

On November 27, 2019, the Company entered into a Fifth Amendment (the “Fifth Amendment”) to the Revolving Credit Agreement dated as of October 10, 2018 which provides that the semi-annual redetermination of the borrowing base under the Revolving Credit Agreement previously scheduled to occur on or about November 1, 2019 (the “Fall 2019 Scheduled Redetermination”) will instead occur on December 16, 2019. Additionally, among other matters, the Fifth Amendment shortened the period over which the Company may repay in installments any borrowing base deficiency that may exist as a result of the Fall 2019 Scheduled Redetermination, as described below.

Under the Revolving Credit Agreement, a borrowing base deficiency will occur if the amounts outstanding under the Revolving Credit Agreement exceed the borrowing base then in effect. If a borrowing base deficiency occurs, the Company is required to repay borrowings in excess of the borrowing base or eliminate the borrowing base deficiency by pledging additional oil and natural gas properties to secure its obligations under the Revolving Credit Agreement. The Company has the option to effect such repayment either (1) in full within 30 days after the redetermination or (2) in monthly installments over a period of, except as amended by the Fifth Amendment, six months, commencing 30 days after the redetermination. The Fifth Amendment provides that, for a borrowing base deficiency that exists as a result of the Fall 2019 Scheduled Redetermination only, the period over which the Company may repay the amount of the deficiency in installments will be four months, rather than six months, commencing 30 days after the redetermination.

Sixth Amendment and Waiver to Revolving Credit Agreement

On December 16, 2019, the Company entered into a Sixth Amendment (the “Sixth Amendment”) to the Revolving Credit Agreement which provides that the semi-annual redetermination of the borrowing base under the Revolving Credit Agreement previously scheduled to occur on or about December 16, 2019 (the “Fall 2019 Scheduled Redetermination”) will instead occur on or about January 14, 2020. Additionally, among other matters, the Sixth Amendment provides that, if any borrowing base deficiency exists as a result of the Fall 2019 Scheduled Redetermination, the date on which the initial payment is due to cure such deficiency is the first business day after such deficiency, rather than 30 days after such deficiency.

Seventh Amendment to Revolving Credit Agreement

On January 17, 2020, the Company entered into a Seventh Amendment (the “Seventh Amendment”) to the Revolving Credit Agreement. The Seventh Amendment provided for the January 14, 2020 redetermination of the borrowing base under the Revolving Credit Agreement (the “Scheduled Redetermination”). As so redetermined, the borrowing base has been set at $90 million. As a result of the Scheduled Redetermination, a borrowing base deficiency in the amount of $25 million existed under the Revolving Credit Agreement (the “Borrowing Base Deficiency”). The Seventh Amendment required repayment of the Borrowing Base Deficiency in four equal monthly installments, with the first payment of $6.25 million scheduled to occur on January 24, 2020.

Eighth Amendment to Revolving Credit Agreement

On January 23, 2020, the Company entered into an Eighth Amendment (the “Eighth Amendment”) to the Revolving Credit Agreement. The Eighth Amendment, among other things, amended the Revolving Credit Agreement to provide that the due date for the first Installment Payment was extended from January 24, 2020 to February 7, 2020 and that the due dates for the subsequent Installment Payments are February 14, 2020, March 16, 2020 and April 14, 2020.

Ninth Amendment to Revolving Credit Agreement

On February 6, 2020, the Company entered into an Ninth Amendment (the “Ninth Amendment”) to the Revolving Credit Agreement. The Ninth Amendment amended the Revolving Credit Agreement to provide that the due date for the first Installment Payment is extended from February 7, 2020 to February 18, 2020 and the due date for the second Installment Payment is extended from February 14, 2020 to February 18, 2020. The due dates for the two subsequent Installment Payments remain March 16, 2020 and April 14, 2020.

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Tenth Amendment to Revolving Credit Agreement

On February 14, 2020, the Company entered into an Tenth Amendment (the “Tenth Amendment”) to the Revolving Credit Agreement. The Tenth Amendment amended the Revolving Credit Agreement to provide that the due date for the first two Installment Payments is extended from February 18, 2020 to February 28, 2020 and the due dates for the two subsequent Installment Payments remain March 16, 2020 and April 14, 2020.

Eleventh Amendment to Revolving Credit Agreement

Twelfth Amendment to Revolving Credit Agreement

On March 30, 2020, the Company entered into a Twelfth Amendment (the “Twelfth Amendment”) to the Revolving Credit Agreement. The Twelfth Amendment amended the Revolving Credit Agreement to, among other things extend the due date for the $1.50 million installment of the Borrowing Base Deficiency from March 30, 2020 to April 14, 2020. The due date for the final installment of the Borrowing Base Deficiency remains April 14, 2020. The lenders under the Revolving Credit Agreement also waived the requirement under the Revolving Credit Agreement that the Company comply with a leverage ratio and a current ratio, in each case, as of December 31, 2019, and granted certain other waivers, including the requirement to comply with certain hedging obligations set forth in the Revolving Credit Agreement until June 30, 2020. Additionally, the lenders consented to an extension of an additional 45 days for the Company to provide its audited annual financial statements for the fiscal year ended December 31, 2019, and waived the requirement that such financial statements be delivered without a “going concern” or like qualification or exception.

Thirteenth Amendment to Revolving Credit Agreement

Fourteenth Amendment to Revolving Credit Agreement

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.

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

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

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


•	an aggregate of 55,000 shares of a newly created series of preferred stock of the Company, designated as “Series F 9.00% Participating Preferred Stock” (the “Series F Preferred Stock”), corresponding to $55 million of the Second Lien Exchange Amount based on the aggregate initial Stated Value (as defined in Note 15 - Preferred Stock) of the shares of Series F Preferred Stock;

•

an aggregate of 60,000 shares of a newly created series of preferred stock of the Company, designated as “Series E 8.25% Convertible Participating Preferred Stock” (the “Series E Preferred Stock”), corresponding to $60 million of the Second Lien Exchange Amount based on the aggregate initial Stated Value (as defined in Note 15 - Preferred Stock) of the shares of Series E Preferred Stock; and


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

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

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

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Interest Expense

The components of interest expense are as follows (in thousands) for the year ended December 31, 2019 and 2018:



	Year Ended December 31,
	2019		2018
Interest on debt	$	6,488	$	2,975
Net revenue payments on financing arrangement	888		—
Paid-in-kind interest on term loans	1,590		12,213
Amortization of debt financing costs	803		3,241
Amortization of discount on term loans	1,657		14,398
Total	$	11,426	$	32,827

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



	December 31,
	2019		2018
	(in thousands)
Long-term deferred revenue liabilities	$	36,920	$	52,500
Long-term deferred proceeds, WLR agreement	13,061		—
Long-term deferred proceeds, WLWI agreement	23,768		—
Other	—		13
Total long-term deferred revenue liabilities and other long-term liabilities	$	73,749	$	52,513

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

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

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

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

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

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On March 11, 2019, the Company, SCM Water, and ARM Energy Management, LLC (“ARM”), a related company to SCM Water, agreed to amend the terms of the previously negotiated water gathering and disposal agreement and entered into a new crude oil sales contract (See Note 7 - Revenue and Note 21 - Commitments and Contingencies). Under the terms of such agreements, the Company agreed to an increase in salt water disposal rates in exchange for more favorable pricing differentials on the crude oil sales contract, modification on the minimum quantities of crude oil required under the crude oil sales contract, an upfront payment of $2.5 million and the elimination of the potential bonus for hitting a target of 40,000 barrels of produced water per day. The Company determined that the upfront $2.5 million payment was primarily attributable to the crude oil sales contract, and the Company recorded the $2.5 million payment as deferred revenues and will recognize it in income ratably as the crude oil is sold.

Crude Oil Gathering Agreement and Option Agreement

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

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

Asset Disposition Accounted for as a Financing Arrangement

As a result of certain repurchase rights, as discussed more fully in Note 5 - Acquisitions and Divestitures, the agreements with WLR and WLWI do not meet the criteria for a sale and are accounted for as a financing arrangement under ASC 470. The net proceeds of the transaction of $39.0 million are included in long-term deferred revenue and other long-term liabilities on the Company’s consolidated balance sheet as of December 31, 2019. As a result of the transaction, the net revenue payments of $0.9 million for the year ended December 31, 2019 are included in interest expense on the Company’s consolidated statements of operations (see Note 5 - Acquisitions and Divestitures).

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NOTE 13 - RELATED PARTY TRANSACTIONS

During the year ended December 31, 2019 and 2018, the Company was engaged in the following transactions with certain related parties:



		As of December 31,
Related Party	Transactions	2019			2018
		(In thousands)
Directors and Officers:
Värde Partners, Inc. (1)	The Company acquired oil and natural gas interests from VPD, an affiliate of Värde	$	—		$	10,705
	Receivable balance outstanding for operating costs associated with VPD's producing wells	—			1,843
	ImPetro Operating, LLC, a wholly-owned subsidiary of the Company is the operator for two of VPD's producing wells and VPD reimbursed the Company for operating charges	—			44
	Revenue payable balance due as of December 31, 2019 for revenue associated with VPD's producing wells	(157		)	—
	Payable to WLR for net proportionate share of production	(161		)	—
	Payable to WLWI for net proportionate share of production	(526		)
	Asset disposition accounted for as a financing arrangement	(36,833		)	—
	Total:	$	(37,677	)	$	12,592

⁽¹⁾Värde was the lead lender in the Company’s Second Lien Term Loan (see Note 11 - Long-Term Debt), is a major stockholder of the Company, and also participated in various transactions in 2018 and 2019 (which such transactions included the issuance of preferred stock to Värde Parties) (see Note 15 - Preferred Stock).

Additionally, on March 5, 2019, pursuant to the 2019 Transaction Agreement and the related payoff letter, the Company agreed to issue to the Värde Parties shares of two new series of its preferred stock and shares of its common stock, as consideration for the termination of the Second Lien Credit Agreement with the Värde Parties and the satisfaction in full, in lieu of repayment in cash, of the Second Lien Term Loan under the Second Lien Credit Agreement. See Note 11 - Long-Term Debt and Note 15 - Preferred Stock for additional information.

On July 31, 2019, the Company entered into two agreements with affiliates of Värde for the sale of an overriding royalty interest and a non-operated working interest in undeveloped assets. WLR’s proportionate share of production of $0.4 million and WLWI’s proportionate share of production, net of production costs, of $0.5 million for the year ended December 31, 2019 is included in interest expense on the Company’s consolidated statements of operations. None of the properties included in the WI Agreement were producing as of December 31, 2019. See Note 5 - Acquisitions and Divestitures for additional information.

On August 16, 2019, the company entered into an agreement with an affiliate of Värde to repurchase the overriding royalty interest for the New Mexico acreage sold. See Note 5 - Acquisitions and Divestitures for additional information.

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NOTE 14 - INCOME TAXES

The income tax provision (benefit) for the years ended December 31, 2019 and 2018 consisted of the following:



	December 31,
	2019			2018
	(in thousands)
U.S. Federal:
Current	$	—		$	—
Deferred	(55,366		)	(7,496		)
State and local:
Current	—			—
Deferred	(4,220		)	509
	(59,586		)	(6,987		)
Change in valuation allowance	59,586			6,987
Income tax provision	$	—		$	—

The tax effects of temporary differences that give rise to the Company’s deferred tax asset as of December 31, 2019 and 2018 consisted of the following:



	December 31,
	2019			2018
	(In thousands)
Deferred tax assets:
Net operating loss carry-forward	$	31,992		$	27,568
Share based compensation	531			808
Abandonment obligation	761			541
Derivative instruments	1,526			—
Deferred revenue	15,863			11,630
Interest expense	4,540			3,804
Lease Liability	386			—
Property Basis	27,837			—
Accrued liabilities and other	144			85
Total deferred tax asset	83,580			44,436
Valuation allowance	(83,197		)	(23,611		)
Deferred tax asset, net of valuation allowance	383			20,825

Deferred tax liabilities:
Derivative instruments	—			249
Oil and natural gas properties and equipment	—			20,576
Right of use asset	383			—
Total deferred tax liability	383			20,825
Net deferred tax asset (liability)	$	—		$	—

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Reconciliation of the Company’s effective tax rate to the expected U.S. federal tax rate is:



	Year Ended December 31,
	2019		2018
Effective federal tax rate	21	%	21	%
State tax rate, net of federal benefit	1	%	2	%
Change in fair value derivative liability	—	%	296	%
Debt discount amortization	—	%	(73	)%
Change in rate	—	%	(6	)%
Other permanent differences	—	%	(6	)%
NOL true-up - §382 limitation	—	%	(6	)%
Loss from early debt extinguishment	—	%	(59	)%
Other	—	%	(1	)%
Valuation allowance	(22	)%	(169	)%
Net	—	%	—	%

As of December 31, 2019 and 2018, the Company had net operating loss carry-forwards for federal income tax purposes of approximately $142.2 million and $127.5 million respectively, available to offset future taxable income. To the extent not utilized, federal net operating loss carry-forwards incurred prior to January, 1 2018 of $69.9 million will expire beginning in 2028 through 2037. Federal net operating loss carryforwards incurred after December 31, 2017 of $77.1 million have no expiration and can only be used to offset 80% of taxable income when utilized. A portion of the net operating loss of $142.2 million is subject to Section 382 limitations of utilization due to ownership changes of more than 50% which occurred in the prior tax years.

In assessing the need for a valuation allowance on the Company’s deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon whether future book income is sufficient to reverse existing temporary differences that give rise to deferred tax assets, as well as whether future taxable income is sufficient to utilize net operating loss and credit carryforwards. Assessing the need for, or the sufficiency of, a valuation allowance requires the evaluation of all available evidence, both positive and negative. Negative evidence considered by management includes cumulative book and tax losses in recent years, no taxable income in available carryback years, and no tax planning strategies contemplated to realize the valued deferred tax assets.

As of December 31, 2019, and 2018, management assessed the available positive and negative evidence to estimate if sufficient future taxable income would be generated to use the Company’s deferred tax assets and determined that it is not more-likely-than-not that the deferred tax assets would be realized in the near future. Therefore, the Company recorded a full valuation allowance of approximately $83.2 million and $23.6 million on its deferred tax assets as of December 31, 2019 and 2018, respectively.

NOTE 15 - PREFERRED STOCK

Preferred Stock Issuances

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

Pursuant to the 2018 Transaction Agreement, on October 10, 2018, the Company issued and sold to the Värde Parties 25,000 shares of a newly created series of the Company’s preferred stock designated as “Series C-2 9.75% Convertible Participating Preferred Stock” for a purchase price of $1,000 per share, or an aggregate of $25.0 million. The Series C-2 9.75% Convertible Participating Preferred Stock was subsequently re-designated as “Series C-2 9.75% Participating Preferred Stock” in connection with the transactions contemplated by the 2019 Transaction Agreement (as re-designated, the “Series C-2 Preferred Stock” and, together with the Series C-1 Preferred Stock, the “Series C Preferred Stock”). Also pursuant to the 2018 Transaction Agreement, on October 10, 2018, the Company issued to the Värde Parties 39,254 shares of its Series D 8.25% Convertible Participating Preferred Stock. The Series D 8.25% Convertible Participating Preferred Stock was subsequently re-designated as “Series D

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8.25% Participating Preferred Stock” in connection with the transactions contemplated by the 2019 Transaction Agreement (as re-designated, the “Series D Preferred Stock”).

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

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

As of December 31, 2019, the Company accounted for the Series C, D, E and F Preferred Stock at its initial fair value at closing of the 2019 Transaction Agreement, plus cumulative paid-in-kind dividends accrued subsequent to the closing of the transactions contemplated by the 2019 Transaction Agreement, under mezzanine equity in the consolidated balance sheet. The components of each series of preferred stock are summarized in the table below:



	Series C Preferred Stock				Series D Preferred Stock				Series E Preferred Stock			Series F Preferred Stock
	Number of Shares	Amount			Number of Shares	Amount			Number of Shares	Amount		Number of Shares	Amount
	(In thousands, except shares)
Balance, January 1, 2019	125,000	$	132,296		39,254	$	40,729		—	$	—	—	$	—
Change in carrying value due to modification	—	(46,632		)	—	(15,056		)	—	—		—	—
Issuance of Preferred Stock in extinguishment of debt	—	—			—	—			60,000	62,115		55,000	46,682
Paid-in-kind dividends	—	13,639			—	3,409			—	4,170		—	4,179
Balance, December 31, 2019	125,000	$	99,303		39,254	$	29,082		60,000	$	66,285	55,000	$	50,861

Material Terms of the Series C Preferred Stock and Series D Preferred Stock

Ranking. The Series D Preferred Stock ranks senior to the Series C Preferred Stock, and the Series C Preferred Stock ranks senior to the Common Stock with respect to dividends and rights on the liquidation, dissolution or winding up of the Company.

Stated Value. Each series of the Preferred Stock has a per share stated value of $1,000, subject to increase in connection with the payment of dividends in kind (the “Stated Value”).

Dividends. Holders of shares of Preferred Stock are entitled to receive cumulative preferential dividends, payable and compounded quarterly in arrears on January 1, April 1, July 1 and October 1 of each year, commencing April 1, 2018, at an annual rate of 9.75% of the Stated Value for the Series C Preferred Stock and 8.25% of the Stated Value for the Series D Preferred stock until April 26, 2021, after which the annual dividend rate will increase to 12.00% if paid in full in cash or 15.00% if not paid in full in cash. Dividends are payable, at the Company’s option, (i) in cash, (ii) in kind by increasing the Stated Value by the amount per share of the dividend, or (iii) in a combination thereof. In addition to these preferential dividends, holders of the Preferred Stock will be entitled to participate in any dividends paid on the Common Stock on an as-converted basis.

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Optional Redemption. The Company has the right to redeem the Series C Preferred Stock, in whole or in part, at any time (subject to certain limitations on partial redemptions), at a price per share equal to (i) the Stated Value then in effect multiplied by (a) 120% if redeemed during 2018, (b) 125% if redeemed during 2019 or (c) 130% if redeemed after 2019, plus (ii) accrued and unpaid dividends thereon and any other amounts payable by the Company in respect thereof (the “Series C Optional Redemption Amount”). The Company has the right to redeem the Series D Preferred Stock, in whole or in part at any time (subject to certain limitations on partial redemptions), at a price per share equal to (i) the Stated Value then in effect multiplied by 117.5%, plus (ii) accrued and unpaid dividends thereon and any other amounts payable by the Company in respect thereof (the “Series D optional Redemption Amount”). Each Series of the Preferred Stock is perpetual and is not mandatorily redeemable at the option of the holders, except upon the occurrence of a Change of Control (as defined in the Certificates of Designation) as described below.

Change of Control. Upon the occurrence of a Change of Control (as defined in the Certificates of Designation), each holder of shares of Preferred Stock will have the option to:


•	cause the Company to redeem all of such holder’s shares of Preferred Stock for cash in an amount per share equal to (i) the applicable Optional Redemption Amount plus (ii) 2.5% of the Stated Value, in each case as in effect immediately prior to the Change of Control;


•	convert all of such holder’s shares of Preferred Stock into the number of shares of Common Stock into which such shares are convertible immediately prior to the Change of Control; or


•	continue to hold such holder’s shares of Preferred Stock, subject to any adjustments to the applicable Conversion Price or the number and kind of securities or other property issuable upon conversion resulting from the Change of Control and to the Company’s or its successor’s optional redemption rights described above.

Liquidation Preference. Upon any liquidation, dissolution or winding up of the Company:

•

holders of shares of Series D Preferred Stock will be entitled to receive, prior to any distributions on the Series C Preferred Stock, the Common Stock or other capital stock of the Company ranking junior to the Series D Preferred Stock, an amount per share of Series D Preferred Stock equal to the greater of (i) the Series D Optional Redemption Amount then in effect and (ii) the amount such holder would receive in respect of the number of shares of Common Stock into which such shares of Series D Preferred Stock is then convertible; and

•

holders of shares of Series C Preferred Stock will be entitled to receive, prior to any distributions on the Common Stock or other capital stock of the Company ranking junior to the Series C Preferred Stock, an amount per share of Series C Preferred Stock equal to the greater of (i) the applicable Series C Optional Redemption Amount then in effect and (ii) the amount such holder would receive in respect to the number of shares of common stock into which a share of Series C Preferred Stock is then convertible.

Voting Rights. In addition to the Board designation rights described in the Certificate of Designation, holders of shares of Preferred Stock will be entitled to vote with the holders of shares of Common Stock, as a single class, on all matters submitted for a vote of holders of shares of Common Stock. When voting together with the Common Stock, each share of Preferred Stock will entitle the holder to a number of votes equal to (i) the applicable Stated Value as of the applicable record date or other determination date divided by (ii) (a) in the case of Series C-1 Preferred Stock, $4.42 (the closing price of the Common Stock on the NYSE American on January 30, 2018), and (b) in the case of Series C-2 Preferred Stock and Series D Preferred Stock, $4.41 (the closing price of the Common Stock on the NYSE American on October 9, 2018).

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

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

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

Dividends. Holders of the Series E Preferred Stock and Series F Preferred Stock are entitled to receive cumulative preferential dividends, payable and compounded quarterly in arrears on January 1, April 1, July 1 and October 1 of each year, commencing April 1, 2019, at an annual rate of 8.25% of the Stated Value for the Series E Preferred Stock and at an annual rate of 9.00% of the Stated Value for the Series F Preferred Stock. However, if, on any dividend payment date occurring after April 26, 2021, dividends due on such dividend payment date on the Series E Preferred Stock or the Series F Preferred Stock are not paid in full in cash, the annual dividend rate for the dividends due on such dividend payment date (but not for any future dividend payment date on which dividends are paid in full in cash) will be 9.25% on the Series E Preferred Stock and 10.00% on the Series

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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

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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.

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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 16 - STOCKHOLDERS' EQUITY

Issuance of Common Stock

On March 5, 2019, pursuant to the 2019 Transaction Agreement, as (i) partial consideration for the satisfaction in full of the Second Lien Term Loan as discussed in Note 11 - Long-Term Debt and (ii) consideration for the amendment of the terms of the Series C Preferred Stock and the Series D Preferred Stock as discussed in Note 15 - Preferred Stock, the Company issued an aggregate of 17,641,638 shares of the Company’s common stock, par value 0.0001 per share.

Warrants

The following table provides a summary of warrant activity as of December 31, 2019 and 2018:



	Warrants		Weighted- Average Exercise Price
Outstanding at Outstanding at January 1, 2018	11,882,800		$	3.34
Exercised	(3,975,957	)	2.21
Forfeited or expired	(2,889,514	)	3.35
Outstanding at Outstanding at January 1, 2019	5,017,329		3.83
Forfeited or expired	(2,263,267	)	2.81
Outstanding at December 31, 2019	2,754,062		$	4.67

The outstanding warrants at December 31, 2019 will expire as follows:



Year	Warrants
2020	174,642
2021	—
2022	2,579,420
	2,754,062

Common Stock Repurchase

In March 2018, the Company entered into a share-repurchase agreement (the “SRA”) with an investment brokerage company (“Broker”) to repurchase $1.0 million of the Company’s common stock as part of the Share Repurchase Plan (the “Plan”). Under the terms of the SRA, the Company paid cash directly to the Broker and received delivery of shares of the Company’s common stock. All of the shares acquired by the Company under the SRA are recorded as treasury stock. For the nine months ended December 31, 2018 the Company purchased 253,598 shares of the Company’s common stock for approximately $1.0 million.

NOTE 17 - SHARE BASED AND OTHER COMPENSATION

On April 20, 2016, the Company’s Board and the Compensation Committee of the Board approved the Company’s 2016 Omnibus Incentive Plan (the “2016 Plan”). As of December 31, 2019, 5.4 million shares of the 18 million shares of the Company’s

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common stock authorized for awards under the 2016 Plan remained available for future issuances. The Company generally issues new shares to satisfy awards under employee stock based payment plans. The Company no longer grants any awards under the Lilis 2012 Omnibus Incentive Plan (the “2012 Plan”).

The following table sets forth the stock based compensation expense recognized during the years ended December 31, 2019 and 2018 and the unamortized portion of the stock based compensation expense and weighted average amortization period of the remaining vesting period for the year ended December 31, 2019 and 2018, the Company’s share-based compensation consisted of the following (dollars in thousands):



	Year Ended December 31,
	2019						2018
	Stock Options		Restricted Stock		Total		Stock Options		Restricted Stock		Total
Share based compensation expensed	$	317	$	6,189	$	6,506	$	2,158	$	6,842	$	9,000
Unrecognized share-based compensation costs	$	100	$	1,228	$	1,328	$	487	$	3,501	$	3,988
Weighted average amortization period remaining (in years)	1.55		1.05				0.03		0.50

Restricted Stock

Employees may be granted restricted stock in the form of restricted stock awards or restricted stock units. Restricted stock is subject to forfeiture restrictions and cannot be sold, transferred, or disposed of during the restriction period. The holders of restricted stock awards have the same rights as a stockholder of the Company with respect to such shares, including the right to vote and receive dividends or other distributions paid with respect to the shares. Restricted stock vests over service periods ranging from the date of grant generally up to two or three years. The company expenses the grant date fair value of restricted shares, determined to be share price on the date of grant, ratably over the service period.

A summary of restricted stock grant activity pursuant to the 2012 Plan and the 2016 Plan for the year ended December 31, 2019, is presented below:



	Number of Shares		Weighted Average Grant Date Price
Outstanding at January 1, 2018	2,475,266		$	4.22
Granted	1,194,944		$	4.59
Vested and issued	(1,436,146	)	$	2.38
Forfeited or canceled ⁽¹⁾	(1,280,480	)	$	4.44
Outstanding at December 31, 2018	953,584		$	4.85
Granted	3,684,372		$	1.46
Vested and issued	(2,341,269	)	$	2.39
Forfeited or canceled ⁽¹⁾	(894,512	)	$	2.94
Outstanding at December 31, 2019	1,402,175		$	1.26

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

Stock Options

Employees may be granted incentive stock options to purchase shares of the Company’s common stock with an exercise price equal to, or greater than, the fair market value of the Company’s common stock on the date of grant. These stock options generally vest over two years from the date of grant and terminate at the earlier of the date of exercise or ten years from the date of grant. During the year ended December 31, 2018, the Company received cash proceeds of approximately $2.6 million from the exercise of vested stock options. There were no stock options exercised during the year ended December 31, 2019.

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A summary of stock option activity pursuant to the 2016 Plan for the years ended December 31, 2019 and 2018, is presented below:



	Number of Options		Weighted Average Exercise Price		Number of Options Vested/ Exercisable	Weighted Average Remaining Contractual Life (Years)
Outstanding at January 1, 2018	7,305,000		$	3.74	3,534,484	8.9
Granted	352,500		$	4.07
Exercised	(1,024,877	)	$	2.67
Forfeited or canceled	(1,601,045	)	$	4.20
Outstanding at December 31, 2018	5,031,578		$	3.81	5,035,317	7.9
Granted	135,000		$	2.17
Exercised	—		$	—
Forfeited or canceled ⁽¹⁾	(1,578,228	)	$	3.14
Outstanding at December 31, 2019	3,588,350		$	4.05	4,125,842	7.2

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

During the year ended December 31, 2019, options to purchase 135,000 shares of the Company’s common stock were granted under the 2016 Plan. The weighted average fair value of these options was $1.47 utilizing the weighted average expected term of 10 years, expected volatility of 30%, no expected dividends, and risk-free interest rate of 2.67%.

The Company estimates expected volatility based on an analysis of its historical stock prices since the initial public offering date in 2007. The Company estimates the expected term of its option awards based on the vesting period. The Company uses this method to provide a reasonable basis for estimating its expected term due to the lack of sufficient historical employee exercise data on stock option awards.

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NOTE 18 - INCOME (LOSS) PER COMMON SHARE

The following table shows the computation of basic and diluted net loss per share for the years ended December 31, 2019 and 2018 (in thousands):



	2019			2018
Net loss	$	(272,121	)	$	(4,143	)
Dividends on preferred stock	(25,397		)	(10,687		)
Unallocated net loss	$	(297,518	)	$	(14,830	)

Numerator for basic loss per share:
Net loss attributable to common stockholders	$	(297,518	)	$	(14,830	)

Denominator for basic loss per share:
Basic weighted average common shares outstanding	87,912,362			62,854,214

Net loss per share:
Basic attributable to common stockholders	$	(3.38	)	$	(0.24	)

Numerator for diluted loss per share:
Net loss attributable to common stockholders	$	(297,518	)	$	(14,830	)
Add: interest expense on convertible Second Lien Term Loan	—			13,429
Less: gain on fair value change of embedded derivatives associated with Second Lien Term Loan	—			(35,471		)
Net loss attributable to common stockholders	$	(297,518	)	$	(36,872	)

Denominator for diluted net loss per share:
Basic weighted average common shares outstanding	87,912,362			62,854,214
Dilution effect of if-converted Second Lien Term Loan	—			15,597,127
Diluted weighted average common shares outstanding	87,912,362			78,451,341

Net loss per share - diluted:
Common shares (diluted)	$	(3.38	)	$	(0.47	)

The Company excluded the following shares from the diluted loss per share calculations above because they were anti-dilutive at December 31, 2019 and 2018:



	December 31,
	2019	2018
Stock Options	3,588,350	5,031,578
Series C Preferred Stock	—	26,295,616
Series D Preferred Stock	—	8,543,670
Stock Purchase Warrants	2,754,062	5,017,329
Series E Preferred Stock	25,667,871	—
Conversion of term loans	—	—
	32,010,283	44,888,193

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NOTE 19 - SUPPLEMENTAL NON-CASH TRANSACTIONS

The following table presents the supplemental disclosure of cash flow information for the years ended December 31, 2019 and 2018:



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

NOTE 20 - SEGMENT INFORMATION

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

NOTE 21 - COMMITMENTS AND CONTINGENCIES

ARM Sales Agreement



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

⁽¹⁾ Extending to the later of December 2024 or 5 years from the EPIC Crude Oil pipeline in-service date (February 2025).

Further, ARM has agreed to purchase crude from the Company based upon Magellan East Houston pricing with a fixed “differential basis”. As of December 31, 2019, the agreement no longer meets the criteria for the “normal purchase normal sales” exception under ASC 815, “Derivatives and Hedging”, due to the Company not meeting the minimum quantities deliverable under the contract and the net settlement criteria being met. See Note 9 - Derivatives for information regarding the recognition of the net settlement mechanism as an embedded derivative over the remainder of the contract.

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Environmental and Governmental Regulation

As of December 31, 2019, there were no known environmental or regulatory matters which are reasonably expected to result in a material liability to the Company. Many aspects of the oil and natural gas industry are extensively regulated by federal, state, and local governments and regulatory agencies in all areas in which the Company has operations. Regulations govern such things as drilling permits, environmental protection and air emissions/pollution control, spacing of wells, the unitization and pooling of properties, reports concerning operations, land use, taxation, and various other matters. Oil and natural gas industry legislation and administrative regulations are periodically changed for a variety of political, economic, and other reasons. As of December 31, 2019, the Company had not been fined or cited for any violations of governmental regulations that would have a material adverse effect on the financial condition of the Company.

Legal Proceedings

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

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

Liens

As of the most recent date available, statutory mechanic's and materialman’s liens which remain unpaid in the amount of $8.7 million have been filed against the related assets.

NOTE 22 - SUBSEQUENT EVENTS

COVID-19

In addition, in March 2020, members of OPEC failed to agree on production levels which has caused an increased supply and has led to a substantial decrease in oil prices and an increasingly volatile market. The oil price war ended with a deal to cut global petroleum output but did not go far enough to offset the impact of COVID-19 on demand. There has been an increase in supply which has pushed prices down further since March. If the depressed pricing continues for an extended period it will lead to i) additional reductions in the borrowing base under our credit facility which would require us to make additional borrowing base deficiency payments, ii) reductions in reserves, and iii) additional impairment of proved and unproved oil and gas properties. We also expect disclosures of supplemental oil and gas information to be impacted by price declines.

In response to recent commodity prices and our efforts to strengthen our capital through reducing operating costs, during April 2020 the Company elected to shut-in 12 wells which were identified as uneconomic as a result of the continued decline in commodity prices in 2020 and 19 additional wells have been identified for short term shut-in through May and June. The 19 wells identified for short term shut-in are naturally flowing wells and could be turned back to sales quickly as market conditions dictate. The Company has also implemented an employee furlough program to further reduce general and administrative costs. The furloughed employees will not receive compensation from the Company during the furlough period; however, subject to local regulations, these employees will be eligible for unemployment benefits. The furlough period is uncertain at this time and will be reassessed as business conditions dictate.

The full impact of the COVID-19 outbreak and the decline in oil prices continues to evolve as of the date of this Annual Report. As such, it is uncertain as to the full magnitude that they will have on the Company’s financial condition, liquidity, and future results of operations.

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Coronavirus Aid, Relief, and Economic Security Act

On March 27, 2020, President Trump signed into law the Coronavirus Aid, Relief, and Economic Security (the “CARES Act”). The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer side social security payments, net operating loss carryback periods, alternative minimum tax credit refunds, modifications to the net interest deduction limitations, increased limitations on qualified charitable contributions, and technical corrections to tax depreciation methods for qualified improvement property.

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Lilis Energy, Inc. and Subsidiaries

Supplementary Information on Oil and Natural Gas Exploration,

Development and Production Activities

(Unaudited)

The Company’s oil and natural gas reserves are attributable solely to properties within the United States, which constitutes one cost center.

Costs Incurred for Oil and Natural Gas Producing Activities

The following table sets forth the costs incurred in the Company’s oil and natural gas acquisition, exploration and development activities and includes costs whether capitalized or expensed as well as revisions and additions to the estimated future asset retirement obligations:



	December 31,
	2019		2018
	(In thousands)
Acquisition costs:
Unproved properties	$	1,644	$	93,926
Proved properties	—		22,356
Exploration costs	40,284		89,351
Development costs	51,198		78,103
Total	$	93,126	$	283,736

Results of Operations for Oil and Natural Gas Producing Activities

The following table sets forth the results of operations for oil and natural gas producing activities:



	December 31,
	2019			2018
	(In thousands)
Revenues	$	66,063		$	70,216
Production costs	(16,127		)	(13,843		)
Production taxes	(3,302		)	(3,709		)
Accretion of asset retirement obligation	(433		)	(85		)
Depletion, depreciation and amortization	(33,071		)	(25,159		)
Full cost ceiling impairment	(228,324		)	—
Total	$	(215,194	)	$	27,420

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Reserves Quantity Information

The following table provides a roll forward of the total proved reserves for the years ended December 31, 2019 and 2018, as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year:



	Crude Oil (Bbls)		Natural Gas (Mcf)		NGLs (Bbls)
January 1, 2018	7,171,339		16,059,926		1,604,570
Extensions and discoveries	15,881,727		38,957,588		4,565,994
Purchase of reserves	1,883,047		8,897,115		682,964
Revisions of previous estimates	(2,641,353	)	17,690,723		1,769,448
Production	(1,089,724	)	(2,855,739	)	(246,425	)
December 31, 2018	21,205,036		78,749,613		8,376,551
Extensions and discoveries	856,838		2,477,061		190,203
Revisions of previous estimates	(15,596,115	)	(48,718,235	)	(6,067,700	)
Production	(1,130,855	)	(3,063,927	)	(220,832	)
December 31, 2019	5,334,904		29,444,512		2,278,222

Proved Developed Reserves, included above:
Balance, January 1, 2018	2,531,397		6,594,446		644,102
Balance, December 31, 2018	6,278,036		27,046,195		2,653,908
Balance, December 31, 2019	5,334,904		29,444,512		2,278,222
Proved Undeveloped Reserves, included above:
Balance, January 1, 2018	4,639,942		9,465,480		960,468
Balance, December 31, 2018	14,927,000		51,703,418		5,722,643
Balance, December 31, 2019	—		—		—

Extensions and discoveries of 1.5 MBOE during the year ended December 31, 2019, resulted from the drilling of exploratory wells during the year that are included in proved reserves and productive wells as of December 31, 2019.

Revisions of previous reserves estimates decreased 2019 proved reserves by 29.8 MBOE. Reserves decreased by approximately 8.3 MBOE as a result of lower SEC pricing and costs for 2019 compared to 2018, as well as operational factors. The remaining revisions of 21.5 MBOE were the result of reclassification of all PUD reserves to unproved because of the uncertainty regarding the availability of capital to us for development these reserves as of December 31, 2019.

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the properties. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties and consideration of expected future economic and operating conditions.

The estimates of future cash flows and future production and development costs as of December 31, 2019 and 2018 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions which are held constant throughout the life of the properties. All wellhead prices are held flat over the forecast period for all reserves categories. The estimated future net cash flows are then discounted at a rate of 10%.

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The standardized measure of discounted future net cash flows relating to proved oil, natural gas and NGL reserves is as follows:



	December 31,
	2019			2018
	(In thousands)
Future cash inflows	$	358,127		$	1,500,263
Future production costs	(176,498		)	(414,117		)
Future development costs	(7,284		)	(346,225		)
Future income tax expense	—			(62,842		)
Future net cash flows	174,345			677,079
10% discount to reflect timing of cash flows	(54,171		)	(384,345		)
Total	$	120,174		$	292,734

In the foregoing determination of future cash inflows, sales prices used for oil, natural gas and NGLs for December 31, 2019 and 2018, were estimated using the average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-month price for each month. Prices were adjusted by lease for quality, transportation fees and regional price differentials. Future costs of developing and producing the proved natural gas and oil reserves reported at the end of each year shown were based on costs determined at each such year-end, assuming the continuation of existing economic conditions.

At December 31, 2019, the tax basis of our oil and gas properties exceeded the pre-tax cash inflows; therefore, in the preparation of the Standardized Measure no future taxable income is expected to be generated from our oil and natural gas properties, primarily due to the reclassification of all PUD reserves to unproved because of the uncertainty regarding the availability of capital for developing those reserves.

The Company cautions that the disclosures shown are based on estimates of proved reserves quantities and future production schedules which are inherently imprecise and subject to revision and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations and no value may be assigned to probable or possible reserves.

Changes in the standardized measure of discounted future net cash flows relating to proved oil, natural gas and NGL reserves are as follows:



	Year Ended December 31,
	2019			2018
	(In thousands)
Balance at beginning of period	$	292,734		$	68,812
Net changes in prices and production costs (1)	(275,539		)	24,261
Sales of oil and natural gas produced during the year, net	(42,442		)	(49,271		)
Changes in estimated future development costs (2)	272,579			(39,938		)
Net change due to extensions and discoveries	18,044			161,785
Net change due to purchases of minerals in place	—			55,278
Previously estimated development costs incurred during the year	36,298			68,349
Net changes due to revision of previous quantity estimates (3)	(255,125		)	28,350
Accretion of discount	29,273			6,881
Other - unspecified (4)	9,327			3,252
Net change in income taxes	35,025			(35,025		)
Balance at end of period	$	120,174		$	292,734

(1) Net changes from prices and production costs were primarily the result of a 19% decrease in oil and natural gas prices and 45% increase in production costs from December 31, 2018 to December 31, 2019.

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(2) Future development costs decreased $272.6 million from December 31, 2018 to December 31, 2019. Our December 31, 2019 proved reserves report reflects the reclassification of all PUD reserves to unproved because of the uncertainty regarding the availability of capital for developing those reserves. Our December 31, 2018 proved reserves report included future development costs of $329.5 million associated with PUD reserves not included in our December 31, 2019 proved reserves report.

(3) Negative revisions for 2019 are primarily the result of the reclassification of proved undeveloped reserves to unproved as reflected in our December 31, 2019 reserves report.

(4) Other changes are the result of significant changes to our proved reserves from December 31, 2018 to December 31, 2019 and include significant estimates of the effects of changes in the economic lives of producing wells and reclassification of proved undeveloped reserves to unproved as reflected in our December 31, 2019 reserves report.

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Exhibit 4.15

DESCRIPTION OF SECURITIES REGISTERED
UNDER SECTION 12 OF THE EXCHANGE ACT

As of April 30, 2020, Lilis Energy, Inc., a Nevada corporation (the “Company”), has one class of securities registered under Section 12 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), which class is its common stock, par value $0.0001 per share (the “Common Stock”). As of April 30, 2020, the Common Stock is listed on the NYSE American under the symbol “LLEX.” In addition to the Common Stock, the Company’s Amended and Restated Articles of Incorporation (as amended and including the Certificates of Designation (as defined below), the “Charter”) authorize the Company to issue shares of its preferred stock, par value $0.0001 per share (the “Preferred Stock”), in one or more series as described below. As of April 30, 2020, no class or series of the Preferred Stock is registered under Section 12 of the Exchange Act.

This document describes certain matters related to the Common Stock. Because the rights of the Common Stock may be affected by the rights of one or more series of the Preferred Stock, this document also describes certain matters related to the Preferred Stock. The information in this document is based on the Charter, the Company’s Amended and Restated Bylaws (the “Bylaws”) and applicable law, including Chapters 78 and 92A of the Nevada Revised Statutes (the “NRS”), each as in effect on April 30, 2020. This document does not contain complete descriptions of the terms of the Common Stock, the Preferred Stock or any series of the Preferred Stock, and the information herein is qualified in its entirety be reference to the Company’s Charter and Bylaws, copies of which are filed as exhibits to the Company’s Annual Report on Form 10-K to which this document also is filed as an exhibit (the “Form 10-K”), as well as to the provisions of applicable law, including Chapters 78 and 92A of the NRS.

Common Stock

Authorized, Issued and Outstanding Shares

The Company is authorized by its Charter to issue 150,000,000 shares of Common Stock. As of April 30, 2020, there were 95,422,277 shares of Common Stock issued and outstanding and 253,598 shares of Common Stock held by the Company as treasury stock. Such number of issued and outstanding shares of Common Stock does not include (a) shares of Common Stock issuable upon conversion of outstanding shares of the Series E Preferred Stock (as defined below), (b) shares of Common Stock issuable upon exercise of outstanding warrants, or (c) shares of Common Stock issuable upon exercise of outstanding stock options issued under the Company’s equity incentive plans.

The authorized but unissued shares of Common Stock are available for future issuance without stockholder approval, unless otherwise required by law or applicable stock exchange rules.

Voting Rights; Amendment of Charter; Election of Directors

Except as otherwise required by law and subject to the voting rights of holders of outstanding shares of Preferred Stock as described below, holders of shares of Common Stock are entitled to one vote per share on all matters submitted to a vote of the Company’s stockholders, including the election of directors. Generally, except as otherwise required by law (including with respect to certain matters described below) and subject to the voting rights of holders of outstanding shares of Preferred Stock as described below, all matters to be voted on by the Company’s stockholders, other than the election of directors, must be approved by a majority of the votes entitled to be cast by all shares of Common Stock that are present in person or represented by proxy at a meeting duly called and held for the purpose of acting on the applicable matter and at which a quorum is present. Under the Company’s Bylaws, the presence, in person or represented by proxy, at a meeting of the holders of a majority of the issued and outstanding stock of the Company entitled to vote at the meeting will constitute a quorum.

Except as otherwise provided by law and subject to the voting rights of holders of outstanding shares of Preferred Stock as described below, amendments to the Company’s Charter generally must be approved by a majority of the votes entitled to be cast by all outstanding shares of Common Stock. Additionally, under Chapter 92A of the NRS, with certain exceptions and subject to the voting rights of holders of outstanding shares of Preferred Stock, the approval of certain plans of merger, conversion or exchange requires the approval of a majority of the votes entitled to be cast by all outstanding shares of Common Stock.

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Pursuant to Chapter 78 of the NRS and the Company’s Charter and Bylaws, directors of the Company are elected by a plurality of the votes cast in the election. The Company’s Charter and Bylaws do not provide for cumulative voting in the election of directors. The Company’s Charter and Bylaws also do not provide for classification of the Company’s board of directors. Section 78.335 of the NRS provides that directors may be removed by stockholders only by the vote of stockholders representing not less than two-thirds of the voting power of the issued and outstanding stock entitled to vote.

The Company’s Bylaws provide that, except as otherwise provided in any applicable provision of the NRS, any action required or permitted to be taken at a meeting of the Company’s stockholders may be taken without a meeting by written consent signed by stockholders holding a majority of the voting power of the Company’s stockholders or such greater proportion of the voting power as may otherwise be required for the approval of such action at a meeting.

Dividend Rights

Subject to the terms of any series of Preferred Stock of which shares are outstanding as described below, holders of Common Stock are entitled to receive such dividends, if any, as may be declared from time to time by the Company’s board of directors out of funds legally available for the payment of dividends.

Rights on Liquidation

In the event of the liquidation or dissolution of the Company, holders of Common Stock would be entitled to share ratably in all of the Company’s assets that remain after satisfaction of all of the Company’s liabilities and the payment of any liquidation preference to holders of outstanding shares of Preferred Stock as described below.

Other Rights

Holders of Common Stock have no preemptive rights to acquire additional shares of Common Stock or other securities. The Common Stock is not subject to any redemption or sinking fund provisions and carries no conversion or subscription rights.

Preferred Stock

Authorized, Issued and Outstanding Shares

The Company is authorized to issue 10,000,000 shares of Preferred Stock. The Company’s Charter authorizes the Company’s board of directors to issue such shares of Preferred Stock in one or more series and to fix for each such series the designations, voting powers, preferences and relative, participating, optional or other special rights of such series and the limitations, qualifications and restrictions thereof.

As of April 30, 2020, an aggregate of 279,254 shares of Preferred Stock had been designated as to series and were issued and outstanding, consisting of:


•	100,000 shares of Series C-1 9.75% Participating Preferred Stock (the “Series C-1 Preferred Stock”);


•	25,000 shares of Series C-2 9.75% Participating Preferred Stock (together with the Series C-1 Preferred Stock, the “Series C Preferred Stock”);


•	39,254 shares of Series D 8.25% Participating Preferred Stock (the “Series D Preferred Stock”);


•	60,000 shares of Series E 8.25% Convertible Participating Preferred Stock (the “Series E Preferred Stock”); and


•	55,000 shares of Series F 9.00% Participating Preferred Stock (the “Series F Preferred Stock” and, together with the Series C Preferred Stock, the Series D Preferred Stock and the Series E Preferred Stock, the “Existing Preferred Stock”).

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Certain Terms of the Existing Preferred Stock

The terms of each series of the Existing Preferred Stock are set forth in the Certificate of Designation of Preferences, Rights and Limitations of such series of the Existing Preferred Stock (as amended and restated in the case of the Series C Preferred Stock and the Series D Preferred Stock) filed by the Company with the Secretary of State of the State of Nevada (each, a “Certificate of Designation” and, collectively, the “Certificates of Designation”). The Certificates of Designation constitute a part of the Company’s Charter, and a copy of each of the Certificates of Designation is filed as an exhibit to the Form 10-K.

Ranking. Each series of the Existing Preferred Stock ranks senior to the Common Stock with respect to dividends and rights on the liquidation, dissolution or winding up of the Company. The Series F Preferred Stock ranks senior to each other series of the Existing Preferred Stock, the Series E Preferred Stock ranks senior to the Series D Preferred Stock and the Series C Preferred Stock, and the Series D Preferred Stock ranks senior to 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. Each series of the Existing Preferred Stock has 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 each series of the Existing Preferred Stock are entitled to receive cumulative preferential (based on the relative ranking of each series) dividends, payable and compounded quarterly in arrears, at the following rates per annum of the applicable Stated Value:


•	for the Series C Preferred Stock, (a) through April 26, 2021, 9.75% and (b) after April 26, 2021, (i) 12.00% if paid in full in cash or (ii) 15.00% if paid in full or in part in kind;


•	for the Series D Preferred Stock, (a) through April 26, 2021, 8.25% and (b) after April 26, 2021, (i) 12.00% if paid in full in cash or (ii) 15.00% if paid in full or in part in kind;


•	for the Series E Preferred Stock, (a) 8.25% or (b) after April 26, 2021, 9.25% if paid in full or in part in kind; and


•	for the Series F Preferred Stock, (a) 9.00% or (b) after April 26, 2021, 10.00% if paid in full or in part in kind.

Dividends on each series of the Existing Preferred Stock are payable, at the Company’s option, (i) in cash, (ii) in kind by increasing the applicable Stated Value by the amount per share of the applicable dividend or (iii) in a combination thereof.

In addition to the preferential dividends described above, holders of each series of the Existing Preferred Stock are entitled to participate in dividends paid on the Common Stock. For holders of the Series C Preferred Stock, the Series D Preferred Stock and the Series E 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 such series of Existing Preferred Stock had been converted into a number of shares of Common Stock equal to the applicable 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 (such price, as so adjusted, the “Participation Price”) (regardless of the fact that shares of each such series of the Existing Preferred Stock are not convertible into 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.

Optional Redemption. The Company has the right to redeem the outstanding shares of each series of the Existing Preferred Stock, in whole or in part, at any time (subject to certain limitations on partial redemptions and, with respect to the Series E Preferred Stock, subject to the additional limitations described below) at a price per share equal to (in each case, the applicable “Optional Redemption Price”):

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•	for the Series C Preferred Stock, (a) (i) the Stated Value thereof then in effect multiplied by (ii) 125% plus (b) accrued and unpaid dividends thereon and any other amounts payable by the Company in respect thereof;


•	for the Series D Preferred Stock, (a) (i) the Stated Value thereof then in effect multiplied by (ii) 117.5% plus (b) accrued and unpaid dividends thereon and any other amounts payable by the Company in respect thereof;

•

for the Series E Preferred Stock, (a) (i) the Stated Value thereof then in effect multiplied by (ii) (1) 105%, if the optional redemption date occurs on or prior to March 5, 2021, or (2) 100%, if the optional redemption date occurs after March 5, 2021 (provided, however, that, for any optional redemption effected in connection with or following a Change of Control (as defined in the Certificate of Designation for the Series E Preferred Stock) or any mandatory redemption in connection with a Change of Control as described below, clause (2) above will apply regardless of when the redemption or Change of Control occurs), plus (b) accrued and unpaid dividends thereon and any other amounts payable by the Company in respect thereof (the “Series E Optional Redemption Price”); and


•	for the Series F Preferred Stock, (a) (i) the Stated Value thereof then in effect multiplied by (ii) 115% plus (b) accrued and unpaid dividends thereon and any other amounts payable by the Company in respect thereof.

The Company may not effect an optional redemption of the Series E Preferred Stock unless:


•	either (a) as of the optional redemption date, there are no shares of the Series F Preferred Stock outstanding or (b) 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 Certificate of Designation for the Series F Preferred Stock;


•	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 volume weighted average trading price of the Common Stock 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.

Shares of each series of the Existing Preferred Stock are not redeemable at the option of the holders thereof except in connection with a Change of Control as described below and are perpetual unless redeemed or, in the case of the Series E Preferred Stock, converted in accordance with the applicable Certificate of Designation.

Conversion. Each share of the Series E Preferred Stock is convertible at any time at the option of the holder into a number of shares of Common Stock equal to (a) the Series E Optional Redemption Price then in effect divided by (b) the Conversion Price (as defined below) (the “Conversion Rate”). However, for purposes of determining the Conversion Rate, the Series E Optional Redemption Price will calculated on the basis applicable to an optional redemption occurring after March 5, 2021 (i.e., multiplying the Stated Value by 100%), 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. 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.

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Shares of the Series C Preferred Stock, the Series D Preferred Stock and the Series F Preferred Stock are not convertible into Common Stock.

Change of Control. Upon the occurrence of a Change of Control (as defined in the Certificates of Designation), each holder of shares of each series of the Existing Preferred Stock will have the option to:

•

cause the Company to redeem all of such holder’s shares of such series of Existing Preferred Stock for cash in an amount per share equal to the applicable Optional Redemption Price in effect immediately prior to the Change of Control plus, in the case of the Series C Preferred Stock and the Series D Preferred Stock, 2.5% of the applicable Stated Value in effect immediately prior to the Change of Control;


•	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


•	continue to hold such holder’s shares of such series of Existing 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 C Preferred Stock, Series D Preferred Stock or Series F Preferred will be entitled to receive, after any distributions on shares of any series of Preferred Stock ranking senior to such series of the Existing Preferred Stock (as applicable) and prior to any distributions on shares of any series of Preferred Stock ranking junior to such series of the Existing Preferred Stock (as applicable), the Common Stock or other capital stock of the Company ranking junior to such series of the Existing Preferred Stock, an amount per share equal to the greater of (a) the applicable Optional Redemption Price then in effect and (b) the proceeds the holders of the Existing Preferred Stock of such series would be entitled to receive if, immediately prior to the payment of such amount, each then-outstanding share of such series of the Existing Preferred Stock had been converted into a number of shares of Common Stock equal to the applicable Optional Redemption Price divided by the Participation Price (regardless of the fact that shares of each such series of Preferred Stock are not convertible into Common Stock); and

•

holders of shares of Series E Preferred Stock will be entitled to receive, after any distributions on shares of 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 (a) the Series E Optional Redemption Price then in effect and (b) 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 Certificate of Designation for the Series C Preferred Stock provides that holders of the Series C Preferred Stock have the right, voting separately as a class, to designate two members of the Company’s board of directors for so long as the aggregate Stated Value of all outstanding shares of the Series C Preferred Stock is at least equal to $31,250,000.

The Certificate of Designation for the Series D Preferred Stock provides that holders of the Series D Preferred Stock have the right, voting separately as a class, to designate one member of the Company’s board of directors for as long as the aggregate Stated Value of all outstanding shares of the Series D Preferred Stock is at least equal to $9,813,500.

The Certificate of Designation for the Series E Preferred Stock provides that holders of the Series E Preferred Stock have the right, voting separately as a class, to designate one member of the Company’s board of directors for as long as the shares of Common Stock issuable on conversion of the outstanding shares of Series E Preferred Stock

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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 Certificate of Designation for the Series F Preferred Stock provides that holders of the Series F Preferred Stock have the right, voting separately as a class, to designate one member of the Company’s board of directors for as long as the aggregate Stated Value of all outstanding shares of the Series F Preferred Stock is at least equal to $13,750,000.

Voting Rights; Negative Covenants. 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 entitles the holder thereof 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 (a) the then-applicable Conversion Price and (b) $1.88, subject to adjustment in the same manner as the Conversion Price may be adjusted as described above.

Holders of shares of the Series C Preferred Stock, the Series D Preferred Stock and the Series F Preferred Stock are not be entitled to vote with the holders of the Common Stock as a single class on any matter.

Each of the Certificates of Designation provides that, as long as any shares of the Existing Preferred Stock of the applicable series are outstanding, the Company may not, without the prior affirmative vote or prior written consent of the holders of a majority of the outstanding shares of the Existing Preferred Stock of each such series, as applicable:


•	amend the Company’s Charter or Bylaws in any manner that materially and adversely affects any rights, preferences, privileges or voting powers of the applicable series of the Existing Preferred Stock or holders of shares of such series of the Existing Preferred Stock;

•

issue, authorize or create, or increase the issued or authorized amount of, the applicable series of the Existing Preferred Stock, any class or series of capital stock ranking senior to or in parity with such series of the Existing Preferred Stock, or any security convertible into or evidencing the right to purchase any shares of such series of the Existing Preferred Stock or any such senior or parity securities, other than equity, the proceeds of which, are used to immediately redeem all of the outstanding shares of the Existing Preferred Stock of the applicable series pursuant to the Company’s optional redemption rights described above;


•	subject to certain exceptions, declare or pay any dividends or distributions on, or redeem or repurchase, or permit any of its controlled subsidiaries to redeem or repurchase, shares of Common Stock or any other shares of capital stock of the Company ranking junior to the applicable series of the Existing Preferred Stock, subject to certain exceptions;

•

authorize, issue or transfer, or permit any of its controlled subsidiaries to authorize, issue or transfer, any equity in any subsidiary of the Company other than (a) equity issued or transferred to the Company or another wholly-owned subsidiary of the Company or (b) equity, the proceeds of which, are used to immediately redeem all of the outstanding shares of the applicable series of the Existing Preferred Stock pursuant to the Company’s optional redemption rights described above; or


•	subject to certain exceptions, modify the number of directors constituting the entire the board of directors of the Company at any time when holders of shares of the applicable series the Existing Preferred Stock have the right to designate a member of the board of directors.

Each of the Certificates of Designation further provides that, (a) in the case of the Series C Preferred Stock, as long as shares of Series C Preferred Stock having an aggregate Optional Redemption Price of at least $50 million are outstanding, (b) in the case of the Series D Preferred Stock, as long as shares of Series D Preferred Stock having an aggregate Optional Redemption Price of at least $19.627 million are outstanding, (c) in the case of the Series E Preferred Stock, as long as shares of Series E Preferred Stock having an aggregate Optional Redemption Price of at least $30 million are outstanding, and (d) in the case of the Series F Preferred Stock, as long shares of the Series F Preferred Stock having an aggregate Optional Redemption Price of at least $27.5 million are outstanding, the Company

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may not, and may not permit any of its controlled subsidiaries to, without the prior affirmative vote or prior written consent of the holders of a majority of the outstanding shares of the applicable series of the Existing Preferred Stock:


•	subject to certain exceptions, incur indebtedness or permit to exist any liens on the assets or properties of the Company or its subsidiaries;

•

enter into, adopt or agree to any “restricted payment” or similar provision that restricts or limits the payment of dividends on, or the redemption of, shares of the applicable series of the Existing Preferred Stock under any credit facility, indenture or other similar instrument of the Company that would be more restrictive on the payment of dividends on, or redemption of, shares of the applicable series of the Existing Preferred Stock than those existing as of the date on which shares of the applicable series of the Existing Preferred Stock were first issued;


•	liquidate or dissolve the company;


•	enter into any material new line of business or fundamentally change the nature of the Company’s business, including any acquisition of oil and gas properties outside the Permian Basin;


•	enter into certain transactions with affiliates of the Company unless made on an arm’s-length basis and approved by a majority of the disinterested members of the Company’s board of directors;


•	subject to certain exceptions, make dispositions of assets or property of the Company or its subsidiaries;


•	subject to certain exceptions, make loans or investments; or


•	voluntarily commence any bankruptcy or similar proceeding or take other similar actions.

Status of Converted or Redeemed Preferred Stock. Each Certificate of Designation provides that shares of the applicable series of the Existing Preferred Stock that are converted, redeemed or otherwise reacquired by the Company will resume the status of authorized and unissued shares of Preferred Stock undesignated as to series.

Future Series of Preferred Stock

Authorized and unissued shares of Preferred Stock may be issued by the Company from time to time in one or more series upon authorization of such issuance and fixing of the terms of the applicable series by the Company’s board of directors as described above. Such issuances may be effected without any vote of or action by holders of Common Stock, except as may be required by applicable stock exchange rules in the case of shares of Preferred Stock that are convertible into shares of Common Stock. Any such future series of Preferred Stock so issued could have priority over the Common Stock with respect to dividend or liquidation rights and could have other rights and preferences, including voting rights, that limit or qualify the rights and preferences of the Common Stock.

Anti-Takeover and Other Potential Effects of Existing or Future Series of Preferred Stock

Certain terms of the Existing Preferred Stock could have the effect of delaying, deferring or preventing a change of control of the Company. For example, the ability of holders of the Existing Preferred Stock to require that their shares of the Existing Preferred Stock be redeemed in connection with a Change of Control could deter potential acquirers of the Company or all or substantially all of its assets or could reduce the consideration received by holders of the Common Stock in any such transaction. Additionally, the approval rights of holders of each series of the Existing Preferred Stock could allow the holders to block sales of assets or other transactions that holders of the Common Stock might consider to be desirable. Additionally, the right of holders of the Series E Preferred Stock to vote together as a single class with the Common Stock could allow holders of the Series E Preferred Stock to exercise significant influence over any vote of the Company’s stockholders on a change of control transaction or other matter.

-7-

Any additional series of Preferred Stock issued in the future may have similar or other terms or rights that could have the effect of delaying, deferring or preventing a change of control of the company or limit, qualify or otherwise adversely affect the economic, voting or other rights of holders of the Common Stock.

Further, the issuance of shares of Preferred Stock, or the issuance of rights to purchase such shares, could be used to discourage an unsolicited acquisition proposal. Although the Company’s board of directors is required to make any determination to issue shares of Preferred Stock based on its judgment as to the best interests of the Company’s stockholders, the board could act in a manner that would discourage an acquisition attempt or other transaction that some, or a majority, of the holders of the Common Stock might believe to be in their best interests or in which such holders might receive a premium for their shares of Common Stock over the then market price of the Common Stock.

Anti-Takeover Provisions under Nevada Law

The NRS contains provisions that (a) prohibit a Nevada corporation from engaging in certain business combinations with an “interested stockholder” (Sections 78.411 to 78.444 of the NRS) and (b) restrict the voting rights of acquiring persons with respect to certain “control shares” (Sections 78.378 to 78.3793 of the NRS). The NRS provides that a Nevada corporation may elect not to be governed by Sections 78.411 to 78.444 or Sections 78.378 to 78.3793 by a provision in its articles of incorporation. The Company’s Charter includes such an opt-out provision with respect to both Sections 78.411 to 78.444 and Sections 78.378 to 78.3793. Accordingly, these provisions do not apply to the Company.

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EXECUTION VERSION CRUDE OIL GATHERING AGREEMENT May 21, 2018 SALT CREEK MIDSTREAM, LLC “Gatherer” And LILIS ENERGY, INC. “Shipper”

TABLE OF CONTENTS Page ARTICLE I CERTAIN DEFINITIONS ........................................................................................ 1 ARTICLE II TERM ....................................................................................................................... 8 2.1 Term .................................................................................................................. 8 ARTICLE III DEDICATION ........................................................................................................ 9 3.1 Dedication ......................................................................................................... 9 3.2 Subsequently Acquired Interests ........................................................................9 3.3 New Dedications and Commitments............................................................... 10 3.4 Releases and Exclusions from the Dedication; Reservations ..........................10 3.5 Covenant Running with the Land ................................................................... 12 3.6 Memorandum of Agreement ........................................................................... 12 ARTICLE IV COMMENCEMENT DATE AND CONSTRUCTION OF FACILITIES ........... 12 4.1 Commencement Date ...................................................................................... 13 4.2 Construction of Commencement Date Facilities .............................................13 4.3 Construction of Receipt Point(s); Drilling Plans .............................................13 4.4 License and Right-of-Use ............................................................................... 16 4.5 Construction Delay ..........................................................................................16 4.6 Connecting Pipelines....................................................................................... 17 ARTICLE V DELIVERY TO CONNECTING PIPELINES ...................................................... 17 ARTICLE VI GATHERER OBLIGATIONS ............................................................................. 18 6.1 Provision of Services .......................................................................................18 6.2 Gatherer’s Prorationing Obligations; Priority Service .....................................18 ARTICLE VII NOMINATIONS AND OTHER TERMS ........................................................... 18 7.1 Nominations .....................................................................................................18 7.2 Unused Capacity ............................................................................................. 18 7.3 Tariff ............................................................................................................... 19 7.4 Linefill ............................................................................................................. 19 7.5 Off-Spec Crude Oil ......................................................................................... 19 7.6 Loss Allowance ................................................................................................20 7.7 Commingling; Quality Bank ........................................................................... 20 7.8 Possession and Control; Liability ....................................................................20 ARTICLE VIII FEES .................................................................................................................. 21 8.1 Tariff Filings and Rates................................................................................... 21 8.2 Governmental Modifications ...........................................................................21 8.3 Fee Escalation ................................................................................................. 21 ARTICLE IX WARRANTY OF TITLE ..................................................................................... 22 i

9.1 Title Warranty ................................................................................................. 22 9.2 Proceeds of Production ....................................................................................22 9.3 Indemnification ............................................................................................... 22 9.4 Title to Shipper Crude Oil ............................................................................... 22 ARTICLE X WAIVER OF CERTAIN DAMAGES ................................................................... 22 ARTICLE XI FORCE MAJEURE .............................................................................................. 23 11.1 Suspension of Obligations ...............................................................................23 11.2 Definition of Force Majeure ........................................................................... 23 11.3 Interruption of Operations. ............................................................................... 24 ARTICLE XII DISPUTE RESOLUTION ................................................................................... 24 12.1 Resolution of Disputes ..................................................................................... 24 12.2 Dispute Notice ................................................................................................ 24 12.3 Direct Negotiation ........................................................................................... 24 12.4 Jurisdiction and Venue; Jury Waiver .............................................................. 24 12.5 Costs and Expenses ..........................................................................................25 12.6 Confidentiality of Dispute Resolution .............................................................25 ARTICLE XIII DUTY TO SUPPORT ........................................................................................ 26 13.1 Arm's Length Negotiations ............................................................................. 26 13.2 Shipper Support ...............................................................................................26 13.3 No Tariff Rate Revision Proceedings ............................................................. 26 13.4 Third Party Proceedings .................................................................................. 26 13.5 Modification of Agreement ............................................................................. 27 ARTICLE XIV COMMON CARRIER AND COMPLIANCE WITH APPLICABLE LAWS . 27 14.1 Common Carrier Pipeline ............................................................................... 27 14.2 Compliance with Laws ................................................................................... 27 ARTICLE XV TAXES ................................................................................................................ 27 ARTICLE XVI ASSIGNMENT .................................................................................................. 28 ARTICLE XVII OFFER .............................................................................................................. 29 17.1 Effect of Unsigned Copy ................................................................................ 29 17.2 Irrevocable Offer by Shipper .......................................................................... 29 ARTICLE XVIII NOTICES AND STATEMENTS ................................................................... 29 18.1 Notice .............................................................................................................. 29 18.2 Change of Address ...........................................................................................31 ARTICLE XIX DEFAULTS AND REMEDIES ........................................................................ 31 19.1 Shipper Default ............................................................................................... 31 19.2 Remedies on Shipper Default ..........................................................................31 19.3 Gatherer Default .............................................................................................. 32 19.4 Remedies on Gatherer Default .........................................................................32 19.5 Excused Performance ...................................................................................... 33 ii

19.6 Adequate Assurances ...................................................................................... 33 19.7 Audit ............................................................................................................... 33 ARTICLE XX MISCELLANEOUS ............................................................................................ 33 20.1 Entire Agreement; Amendments. ..................................................................... 33 20.2 Governing Law ............................................................................................... 33 20.3 No Drafting Presumption ................................................................................ 34 20.4 Waiver ............................................................................................................. 34 20.5 No Third Party Beneficiaries .......................................................................... 34 20.6 No Partnership .................................................................................................34 20.7 Confidentiality ................................................................................................ 34 20.8 Headings ......................................................................................................... 35 20.9 Rules of Construction ......................................................................................35 20.10 Survival ............................................................................................................36 20.11 Severability ..................................................................................................... 36 20.12 Further Assurances ...........................................................................................36 20.13 Liquidated Damages ....................................................................................... 36 20.14 Counterpart Execution .................................................................................... 36 Exhibits Exhibit A Dedicated Area Exhibit B Initial Receipt Points; Initial Delivery Points; MDQ; Rates Exhibit C Form of Memorandum of Agreement Exhibit D Commencement Date Facilities Exhibit E Form of New Receipt Point Notification Exhibit F Pro Forma Tariff Exhibit G Prior Dedications iii

CRUDE OIL GATHERING AGREEMENT This Crude Oil Gathering Agreement (this “Agreement”) is made and entered into effective as of this 21st day of May, 2018 (the “Effective Date”), by and between Salt Creek Midstream, LLC, a Delaware limited liability company (“Gatherer”), and Lilis Energy, Inc., a Nevada corporation (“Shipper”). Shipper and Gatherer may be referred to individually as “Party,” or collectively as the “Parties.” WITNESSETH: WHEREAS, Shipper is the owner and operator of certain interests in land, Wells and leases with the right to produce Crude Oil therefrom and is or will be the operator of certain producing properties located in Loving and Winkler Counties, Texas and Lea County, New Mexico; and WHEREAS, Shipper has title to or the right to gather Shipper Crude Oil; and WHEREAS, Shipper desires that Gatherer, in accordance with the terms set forth in this Agreement, (i) design, engineer and construct the Gathering System to enable Gatherer to provide gathering services for Shipper Crude Oil, and (ii) gather Shipper Crude Oil on the Gathering System; and WHEREAS, Gatherer desires to (i) construct, own and operate the Gathering System, and (ii) gather Shipper Crude Oil on the Gathering System, all in accordance with the terms set forth in this Agreement; and WHEREAS, Gatherer and Shipper are not Affiliates and are entering into this Agreement as independent parties. NOW THEREFORE, in consideration of the mutual promises, covenants and agreements herein contained, the Parties hereby covenant and agree as follows: ARTICLE I CERTAIN DEFINITIONS Unless otherwise required by the content, the terms defined in this ARTICLE I shall have, for all purposes of this Agreement, the respective meanings set forth in this ARTICLE I: “Actual Shipments” shall mean, for any period of time, the volumes of Shipper Crude Oil that Shipper delivers to Gatherer hereunder at the Receipt Points and that are ultimately delivered by Gatherer to Shipper hereunder at the Delivery Points. “ADV” shall mean, for any period of calculation, the average Daily volume of Shipper Crude Oil accepted into all Receipt Point(s) hereunder during such period, which will be calculated by dividing (A) the sum of (i) the aggregate volume of all Shipper Crude Oil accepted into the Gathering System hereunder during such period, plus (ii) the sum, for each Day in such period, of the volume of Shipper Crude Oil, up to the MDQ in effect on each such Day during

such period, that Shipper was ready, willing and able to deliver on such Day but which Gatherer was unable or failed to accept on such Day as required under this Agreement during such period, by (B) the number of Days in such period. “Affiliate” shall mean any Person that directly or indirectly through one or more intermediaries, controls or is controlled by or is under common control with another Person. The term “control” (including its derivatives and similar terms) shall mean possessing the power to direct or cause the direction of the management and policies of a Person, whether through ownership, by contract, or otherwise. Any Person shall be deemed to be an Affiliate of any specified Person if such Person owns fifty percent (50%) or more of the voting securities of the specified Person, or if the specified Person owns fifty percent (50%) or more of the voting securities of such Person, or if fifty percent (50%) or more of the voting securities of the specified Person and such Person are under common control. “Agreement” shall have the meaning given to such term in the preamble of this Agreement. “API” shall mean the American Petroleum Institute. “Applicable Law” shall mean all applicable laws, statutes, directives, codes, ordinances, rules, regulations, municipal by-laws, judicial, arbitral, administrative, ministerial, departmental or regulatory judgments, orders, decisions, rulings or awards, consent orders, consent decrees and policies of any Governmental Authority. “Barrel” or “bbl” shall mean forty-two (42) gallons of 231 cubic inches per gallon at 60 degrees Fahrenheit (60° F) and equilibrium vapor pressure of the liquid. “BLM” shall mean the Bureau of Land Management and any lawful successor agency thereto. “BPD” shall mean Barrels per Day. “Business Day” shall mean any calendar day other than Saturdays and Sundays that commercial banks in Houston, Texas are open for business. “Central Clock Time” shall mean the then prevailing time in the Central Time Zone of the United States of America. “Claims” shall mean any and all claims, demands and causes of action of any kind and all losses, damages, liabilities, fines, penalties, costs and expenses of whatever nature (including court costs and reasonable attorneys’ fees). “COGA” shall mean a Crude Oil Gathering Agreement executed by a Priority Shipper with Gatherer with respect to the Gathering System pursuant to the Open Season. “Commencement Date” shall have the meaning given to such term in Section 4.1 of this Agreement. 2

“Commencement Date Facilities” shall mean those facilities specifically described on Exhibit D, including without, limitation, the Initial Receipt Point(s), the Initial Delivery Point(s). Gatherer’s Wink Terminal, and the Crude Oil pipeline and equipment and facilities located at and downstream of the Initial Receipt Points necessary to commence Services with respect to the receipt, gathering, handling and delivery of Crude Oil as contemplated by this Agreement; provided, however, truck racks and truck injection facilities are specifically excluded from the Commencement Date Facilities. “Committed Volume” shall mean (i) with respect to a Priority Shipper that has committed to deliver a specified volume of Crude Oil to the Gathering System pursuant to such Priority Shipper’s COGA, such specified volume (expressed in BPD), and (ii) with respect to a Priority Shipper that has not committed to deliver a specified volume of Crude Oil, but has made an acreage dedication pursuant to such Priority Shipper’s COGA, a volume of Crude Oil (expressed in BPD) equal to such Priority Shipper’s Maximum Daily Quantity. “Connecting Pipelines” shall mean all downstream pipeline systems now and hereafter connected to the Gathering System at the Delivery Point(s), which, as of the Effective Date, are contemplated to be (i) the Plains All-American, LP Pipeline or other pipeline with direct, long- haul transportation to the Midland, Texas area, and (ii) the EPIC Crude Oil Pipeline or other pipeline with direct, long-haul transportation to the Corpus Christi, Texas area, provided that, as of the Effective Date, the EPIC Crude Oil Pipeline is not expected to be in service until the second half of 2019. “Contract Year” shall mean a period commencing at 7:00 a.m., Central Clock Time, on the Commencement Date and ending at 7:00 a.m., Central Clock Time on the same day and calendar month of the following calendar year and thereafter for succeeding periods of twelve (12) consecutive Months each. “Crude Oil” shall have the meaning given to such term in the Tariff. “Day” or “Daily” shall mean a period of twenty-four (24) hours, commencing at 7:00 a.m., Central Clock Time, on a calendar day and ending at 7:00 a.m., Central Clock Time, on the next succeeding calendar day. “Dedicated Area” shall mean the area depicted and described in Exhibit A attached hereto. “Dedication” shall have the meaning given to such term in Section 3.1 of this Agreement. “Delay Period” shall have the meaning given to such term in Section 4.5(b) of this Agreement. “Delivery Point(s)” shall mean the furthest downstream flange of Gatherer’s facilities on the Gathering System where Gatherer redelivers Crude Oil in accordance with the Services to Shipper or for Shipper’s account, and includes, collectively, (i) the Initial Delivery Points, (ii) any additional points of interconnection specified by Shipper and added to the Gathering System pursuant to Section 4.6, and (iii) any other points of interconnection between the Gathering 3

System and any Connecting Pipeline as mutually agreed upon by the Parties at which Gatherer will redeliver Shipper Crude Oil for the account of Shipper. “Dispute” shall mean any controversy or claim, whether based on contract, tort, statute or other legal or equitable theory (including, but not limited to, any claim of fraud, misrepresentation or fraudulent inducement or any question of validity or effect of this Agreement including this clause) arising out of or related to this Agreement (including any amendments or extension), or breach or termination thereof. “Dispute Notice” shall have the meaning given to such term in Section 12.2 of this Agreement. “Effective Date” shall have the meaning given to such term in the preamble to this Agreement. “Energy Costs” shall mean the total actual, out-of-pocket cost of purchased electricity or fuel (without mark-up), including actual transmission costs, loss and other costs associated with providing such electricity services to equipment associated with the Receipt Point(s), including, without limitation, Gatherer’s LACT(s); provided, however, “Energy Costs” shall not include any costs or expenses related to Gatherer’s installation or construction of any utility lines, measurement equipment or other infrastructure necessary to provide electricity or fuel. “Extended Term” shall have the meaning given to such term in Section 2.1 of this Agreement. “FERC” shall mean the United States Federal Energy Regulatory Commission and any lawful successor agency thereto. “Force Majeure” shall have the meaning given to such term in Section 11.2 of this Agreement. “Gatherer” shall have the meaning given to such term in the preamble of this Agreement. “Gatherer Default” shall have the meaning given to such term in Section 19.3 of this Agreement. “Gatherer Default Notice” shall have the meaning given to such term in Section 19.4 of this Agreement. “Gatherer Indemnified Party” means Gatherer and its Affiliates, and all of its and their respective equityholders, partners, members, directors, officers, managers, employees, agents and representatives. “Gatherer’s Wink Terminal” means that certain Crude Oil terminal facility located in Wink, Texas, being more particularly described on Exhibit D. “Gathering System” means the Crude Oil gathering system, Receipt Point(s), Delivery Point(s), LACTs, Gatherer’s Wink Terminal, any Service related facilities, including, pipelines, 4

controls, pumps, pig receiving facilities, tanks, meters and measurement facilities, treating (if any treating is performed hereunder) and other conditioning facilities, meters and measurement facilities, storage and handling facilities, truck racks and truck injection facilities, vapor recovery units, rights of way, fee parcels, surface rights, and permits, and all appurtenant facilities, constructed or to be constructed and owned and operated by Gatherer to provide Services to Shipper or other shippers. “Governmental Authority” shall mean (i) the United States of America, (ii) any state, county, parish, municipality or other governmental subdivision within the United States of America, and (iii) any court or any governmental department, commission, board, bureau, agency or other instrumentality of the United States of America or of any state, county, municipality or other governmental subdivision within the United States of America. “Impaired Party” shall have the meaning given to such term in Section 19.6 of this Agreement. “Initial Delivery Points” shall mean the Delivery Points identified on Exhibit B attached hereto. “Initial Receipt Points” shall mean the Receipt Points identified on Exhibit B attached hereto. “Insecure Party” shall have the meaning given to such term in Section 19.6 of this Agreement. “Interests” shall mean any right, title, or interest in lands, Wells, or leases with the right to produce oil and/or gas therefrom whether arising from fee ownership, working interest ownership, mineral ownership, leasehold ownership, or arising from any pooling, unitization or communitization of any of the foregoing rights. “LACT” shall mean a lease automatic custody transfer unit whereby custody of Shipper Crude Oil will transfer from one Party to the other Party or its designee, as applicable, that is installed and operated in accordance with the latest revision of API Manual of Petroleum Measurement Standards, Chapter 6.1. “Losses” shall mean any actual loss, cost, expense, liability, damage, demand, suit, sanction, claim, judgment, lien, fine or penalty, including attorneys’ fees, asserted by a third party not Affiliated with the Party incurring such, and which are incurred by the applicable indemnified Persons on account of injuries (including death) to any person or damage to or destruction of any property, sustained or alleged to have been sustained in connection with or arising out of the matters for which the indemnifying party has indemnified the applicable indemnified Persons. “Maximum Daily Quantity” shall mean the maximum volume of Crude Oil (expressed in BPD) a Priority Shipper, including Shipper, is allowed to deliver to the Gathering System pursuant to such Priority Shipper’s COGA. 5

“Memorandum” shall have the meaning given to such term in Section 3.6 of this Agreement. “Month” shall mean a period of time beginning at 7:00 a.m., Central Clock Time on the first day of the calendar month and ending at 7:00 a.m., Central Clock Time on the first day of the next succeeding calendar month. “New Receipt Point Notification” shall have the meaning given to such term in Section 4.3(b) of this Agreement. “Nomination” (including “Nominates” and the syntactical variants thereof) shall mean the written or electronic communication from Shipper to Gatherer, pursuant to and in accordance with the Tariff, requesting that Gatherer transport for Shipper in a given Month a stated volume of Crude Oil from a specified Receipt Point to the applicable Delivery Point pursuant to this Agreement. “Notification Date” shall have the meaning given to such term in Section 4.3(b) of this Agreement. “Off-Spec Crude Oil” shall have the meaning given to such term in Section 7.5 of this Agreement. “Open Season” shall mean the open season initiated and conducted by Gatherer to determine interest by Priority Shippers in the Gathering System. “Parties” shall have the meaning given to such term in the preamble of this Agreement. “Party” shall have the meaning given to such term in the preamble of this Agreement. “Person” shall mean any individual, firm, corporation, trust, partnership, limited liability company, association, joint venture, other business enterprise or Governmental Authority. “Primary Term” shall have the meaning given to such term in Section 2.1 of this Agreement. “Prior Dedications” shall mean, as of the applicable date of determination, any and all existing agreements or arrangements (including any joint operating agreements, pooling agreements, unitization or communitization agreements) or rights of any third Persons that are binding on the applicable Person or on the applicable Interest within the Dedicated Area or any Crude Oil produced therefrom that would require or necessitate (i) Shipper Crude Oil to be gathered on any gathering system or similar system other than the Gathering System (including deliveries of Shipper Crude Oil as necessary to satisfy any minimum volume or similar commitment), or (ii) Shipper Crude Oil to be trucked by a third party from the Dedicated Area. “Priority Rate” shall have the meaning given to such term in the Tariff. “Priority Service” shall have the meaning given to such term in Section 6.2 of this Agreement. 6

“Priority Shipper” shall mean Shipper and any other Shipper whose COGA provides for a term of at least ten (10) years and either (i) a commitment to deliver a specified volume of Crude Oil on the Gathering System of at least 2,000 BPD, or (ii) with respect to a Priority Shipper that has not committed to deliver a specified volume of Crude Oil, but has made an acreage dedication pursuant to such Priority Shipper’s COGA, a dedication of Interests covering at least 2,000 net acres of lands located in Winkler County, Texas, Loving County, Texas and/or Lea County, New Mexico. “Project Deadline” shall have the meaning given to such term in Section 4.5(a) of this Agreement. “Receipt Point” shall mean, a point where the custody and control of Shipper Crude Oil transfers from Shipper to Gatherer located at the inlet flange of Gatherer’s LACT through which such Shipper Crude Oil flows into the Gathering System. “Services” shall mean receipt, gathering and transportation on the Gathering System of Crude Oil for Shipper’s account from the Receipt Point(s) and delivery to the Delivery Point(s) specified in Shipper’s Nomination, together with all other services to be provided by Gatherer as contemplated in this Agreement. “Shipper” shall have the meaning given to such term in the preamble of this Agreement. “Shipper Crude Oil” shall have the meaning given to such term in Section 3.1 of this Agreement. “Shipper Default” shall have the meaning given to such term in Section 19.1 of this Agreement. “Shipper Default Notice” shall have the meaning given to such term in Section 19.2 of this Agreement. “Shipper Indemnified Party” means Shipper and its Affiliates, and all of its and their respective equityholders, partners, members, directors, officers, managers, employees, agents and representatives. “Shipper’s Maximum Daily Quantity” or “MDQ” shall mean, with respect to any Contract Year, the volume of Crude Oil (expressed in BPD) set forth for such Contract Year in the table captioned “MDQ” in Exhibit B attached hereto, for which Shipper shall receive Priority Service as set forth in Section 6.2 hereof. With respect to any Contract Year beginning on or after the fourth (4th) anniversary of the Commencement Date, Gatherer shall have the option, by delivering written notice to Shipper on or before the date that is thirty (30) Days prior to the start of any such Contract Year, to reduce Shipper’s Maximum Daily Quantity for such Contract Year to an amount equal to the lesser of (x) the MDQ that was in effect at the end of the immediately preceding Contract Year or (y) 110% of the ADV of Shipper Crude Oil delivered or available for delivery hereunder by Shipper to Gatherer during the immediately preceding twelve (12) Month period. Conversely, beginning on or after the fourth (4th) anniversary of the Commencement Date, Shipper shall have the option, by delivering written notice to Gatherer on or before the date that is thirty (30) Days prior to the start of any such Contract Year, to request an increase in 7

Shipper’s Maximum Daily Quantity for such Contract Year to an amount equal to 120% of the ADV of Shipper Crude Oil delivered or available for delivery hereunder by Shipper to Gatherer during the immediately preceding twelve (12) Month period, and if, in the sole determination of Gatherer, consistent with Gatherer’s obligations under Section 6.2 hereunder and to the extent permitted by Applicable Law, Gatherer has adequate capacity eligible for Priority Service in the Gathering System and related facilities to provide Priority Service with respect to such requested amount, then such requested increase shall become effective. “Shipper’s Permitted Liens” shall mean (i) any liens, security interests or other encumbrances benefiting one or more lenders to Shipper as part of a financing provided by such lenders to Shipper for which such lenders have not taken actions to foreclose on such liens; and (ii) normal and customary liens under financing agreements, operating agreements, unitization agreements, pooling orders, drilling contracts and similar agreements for upstream operators and mechanic's and materialman's liens, tax liens or mineral liens related to claims or obligations that are not delinquent or that are being contested in good faith and by appropriate proceedings. “Shipper’s Priority Rate” shall have the meaning given to such term in Section 8.1(a) of this Agreement. “Shipper’s Uncommitted Rate” shall have the meaning given to such term in Section 8.1(b) of this Agreement. “Target RP In-Service Date” shall have the meaning given to such term in Section 4.3(b) of this Agreement. “Tariff” shall mean Gatherer’s rate, rules and regulations tariff for the Gathering System on file and in effect with the FERC or other Governmental Authority, as such tariff may be amended or supplemented by Gatherer from time to time, a pro forma copy of which, materially in the form expected to be filed by Gatherer with the FERC, is attached hereto as Exhibit F. “Tariff Rate Revision Proceeding” shall have the meaning given to such term in Section 13.3 of this Agreement. “Taxes” shall mean any or all current or future taxes, fees, levies, charges, assessments and/or other impositions levied, charged, imposed, assessed or collected by any Governmental Authority having jurisdiction. “Term” shall have the meaning given to such term in Section 2.1 of this Agreement. “Uncommitted Rate” shall have the meaning given to such term in the Tariff. “Well” shall mean a well for the production of gas and/or liquid hydrocarbons, including Crude Oil, which is operated by Shipper or its Affiliates. ARTICLE II TERM 8

2.1 Term. The term of this Agreement shall commence on the Effective Date, and unless sooner terminated as provided herein, shall remain in full force and effect through the twelfth (12th) anniversary of the Effective Date (the “Primary Term”); provided, however, this Agreement shall continue beyond the expiration of the Primary Term for additional terms of one year each (each an “Extended Term,” and, the Primary Term as may be extended by one or more Extended Terms, the “Term”) unless this Agreement is terminated by either Party as of the end of the Primary Term or the then-current Extended Term, as applicable, by providing not less than sixty (60) Days written notice of termination prior to the end of the Primary Term or such Extended Term to the other Party. ARTICLE III DEDICATION 3.1 Dedication. Subject to the other terms and conditions hereof, Shipper hereby (i) dedicates for Services with respect to Shipper Crude Oil under this Agreement to Gatherer all Interests now owned or hereafter acquired by Shipper and/or its Affiliates and their respective successors and assigns that cover lands located within the Dedicated Area, and (ii) dedicates for Services under this Agreement and shall deliver, or cause to be delivered, hereunder to Gatherer, at the Receipt Points, the following (the “Dedication,” and the Crude Oil that is the subject of the Dedication being herein referred to as “Shipper Crude Oil”): (a) all Crude Oil produced and saved on or after the Commencement Date for the remainder of the Term from those Wells for which Shipper and/or any of its Affiliates is the operator now or hereafter located within the Dedicated Area or on lands pooled or unitized therewith, to the extent such Crude Oil is attributable to the Interests within the Dedicated Area now owned or hereafter acquired by Shipper and/or its Affiliates and their respective successors and assigns; and (b) with respect to those Wells for which Shipper and/or any of its Affiliates is the operator, Crude Oil produced on or after the Commencement Date for the remainder of the Term from such Wells which is attributable to the Interests in such Wells owned by other working interest owners and royalty owners which is not taken “in-kind” by such working interest owners and royalty owners and for which Shipper and/or its Affiliates has the right or obligation to deliver such Crude Oil and only for the period that Shipper and/or its Affiliates has such right or obligation. For the avoidance of doubt, Shipper shall not be required to deliver Crude Oil from any well operated by an operator other than Shipper or its Affiliates, including any well where Shipper would be required to install split stream connection facilities or similar facilities to take such Crude Oil in kind, and such Crude Oil shall not be Shipper Crude Oil subject to the Dedication hereunder. 3.2 Subsequently Acquired Interests. In the event that after the date hereof Shipper and/or any of its Affiliates acquire Interests within the Dedicated Area, then the Shipper Crude Oil produced and saved from such Interests shall automatically be included within the Dedication; provided, however, if any of the Shipper Crude Oil produced from such Interests is subject to a Prior Dedication, then such Shipper Crude Oil shall be excluded from the 9

Dedication, to the extent and only to the extent of such Prior Dedication, until such Prior Dedication expires or terminates. In the event that any such Prior Dedication expires or terminates, then the Shipper Crude Oil subject to such Prior Dedication shall, to the extent not already subject to the Dedication, automatically be included within the Dedication and subject to this Agreement without any further actions by the Parties. 3.3 New Dedications and Commitments. Shipper represents and warrants to Gatherer that, as of the Effective Date, except as set forth on Exhibit G attached hereto, none of the Interests owned by Shipper and/or its Affiliates within the Dedicated Area are subject to a Prior Dedication. With respect to any such Interests which are subject to a Prior Dedication, Shipper shall have the right to comply with such Prior Dedication and the Shipper Crude Oil produced from such Interests shall be excluded from the Dedication, to the extent and only to the extent of such Prior Dedication, until such Prior Dedication expires or terminates. In the event that any such Prior Dedication expires or terminates, then the Shipper Crude Oil subject to such Prior Dedication shall, to the extent not already subject to the Dedication, automatically be included within the Dedication and subject to this Agreement without any further actions by the Parties. Commencing on the Effective Date of this Agreement, Shipper shall not, as to the Interests owned by Shipper and/or its Affiliates within the Dedicated Area as of the Effective Date, enter into any dedication or commitment for Crude Oil gathering or transportation services burdening such Interests if the term of such dedication or commitment extends beyond the Commencement Date; provided, however, Shipper may enter into such dedication and commitment (i) for periods beyond the Commencement Date, to the extent that Shipper reasonably anticipates that Commencement Date Facilities will not be completed and placed in-service on or before the anticipated Commencement Date set forth in Section 4.5, but not for a period in excess of six (6) Months past the anticipated Commencement Date, and (ii) during periods when Shipper is released from Dedication pursuant to the terms and conditions of this Agreement. 3.4 Releases and Exclusions from the Dedication; Reservations. Notwithstanding Section 3.1 hereof, (a) if, at any time during the Term, Gatherer suspends, curtails, is unable or fails to receive all volumes of Shipper Crude Oil hereunder, for more than twenty-four (24) consecutive hours for any reason, including an event of Force Majeure, the affected Well(s) (including the volumes of Crude Oil associated therewith) delivering to the affected Receipt Point(s) where all such volumes of Shipper Crude Oil are not received shall automatically be temporarily released from this Agreement; provided, however, during such suspension, curtailment, or interruption event, Gatherer shall have the right, but shall have no obligation, to (or to cause its designee to) truck all or a portion of the Shipper Crude Oil delivered hereunder, and by doing so, such Shipper Crude Oil trucked by Gatherer or its designee shall be considered received hereunder and not temporarily released hereunder. If Gatherer elects the option to truck Barrels of Shipper Crude Oil as provided in the immediately preceding sentence, (i) Shipper’s Priority Rate will apply to all such Barrels, and (ii) Gatherer shall redeliver such Shipper Crude Oil to Gatherer’s Wink Terminal via the Gathering System (if available) or to one or more alternative markets, purchasers, pipelines, processor or transporters designated by Producer in close proximity thereto (if Gatherer’s Wink Terminal is not available). Shipper may, at its sole option, store or deliver all or any portion of the Shipper Crude Oil temporarily released hereunder to Gatherer’s Wink Terminal via the Gathering System (if available) or an alternative 10

market, purchaser, pipeline, processor or transporter (if Gatherer’s Wink Terminal is not available); provided, however, to the extent that Gatherer does not elect its trucking option under this Section 3.4(a) and the temporary release is not attributable to a Force Majeure or an interruption of operations described in Section 11.3, Gatherer shall reimburse Producer for Producer’s out of pocket costs incurred during such release period on a per Barrel basis to truck Shipper Crude Oil to Gatherer’s Wink Terminal via the Gathering System (if available) or such alternative markets, purchasers, pipelines, or transporters (if Gatherer’s Wink Terminal is not available), less the Shipper’s Priority Rate per Barrel. This temporary release shall cease, and Shipper shall resume deliveries of such temporarily released Shipper Crude Oil, as soon as Shipper, exercising commercially reasonable efforts, can terminate all alternative gathering and/or marketing arrangements without penalty, but in no event later than the first Day of the Month commencing after the passage of ninety (90) Days after Gatherer has provided Shipper written notice that Gatherer is ready, willing and able to resume receiving the affected volumes of Shipper Crude Oil. (b) If Gatherer suspends, curtails, is unable or fails to receive all volumes of Shipper Crude Oil (i) for any reason other than an event of Force Majeure, for one hundred twenty (120) consecutive Days or one hundred twenty (120) or more cumulative Days during any consecutive one hundred eighty (180) Day period following the Commencement Date, or (ii) as a result of an event of Force Majeure, for two hundred seventy (270) consecutive Days or two hundred seventy (270) Days or more cumulative Days during any consecutive three hundred sixty-five (365) Day period following the Commencement Date, then Shipper shall have the right, immediately following such period, to request and receive a permanent release from Gatherer of the affected Well(s) and Interest(s) delivering to the affected Receipt Point(s) where all such volumes of Shipper Crude Oil are not received (including the volumes of Crude Oil associated therewith). (c) Shipper Crude Oil may be released from the Dedication in accordance with Sections 4.3(c) and (e) hereof. (d) Shipper reserves the following rights respecting Shipper Crude Oil: (i) to operate the Well(s) and Interests in its sole discretion, including, without limitation, the right, but never the obligation, to drill new Well(s), to repair and rework old Well(s), renew or extend, in whole or in part, any oil and gas lease covering any of lands within the Dedicated Area, and to cease production from or abandon any Well or surrender any such oil and gas lease, in whole or in part, in Shipper’s discretion; (ii) to deliver or furnish to Shipper’s and its Affiliates’ lessors and holders of other existing burdens on production such Shipper Crude Oil as is required to satisfy the terms of the applicable oil and gas leases and other applicable instrument creating the burdens; (iii) to pool, communitize, or unitize the lands covered by the Interests of Shipper and its Affiliates’, including with lands not covered by such Interests; provided that Shipper’s and/or its Affiliates’ share of Crude Oil produced from 11

such pooled, communitized, or unitized interests shall be dedicated and committed to this Agreement to the extent that such Crude Oil would constitute Shipper Crude Oil hereunder; (iv) to construct, install, maintain, own and operate any treating and/or conditioning facilities upstream of the Gathering System as reasonably necessary to (i) comply with any environmental, legal, or Interest requirements, or (ii) meet the quality specifications of the Gathering System set forth in this Agreement and/or the quality specification of any Connecting Pipeline; (v) to deliver or furnish to Shipper’s and its Affiliates’ non-operators or other Persons all Crude Oil that such non-operators or Persons elect to separately take in-kind and market; and (vi) to retain any and all Crude Oil that is not Shipper Crude Oil dedicated and committed to this Agreement, including, without limitation, Crude Oil produced prior to the Commencement Date or released hereunder, and to transport by truck and/or sell or otherwise dispose of such Crude Oil. (e) In the event of a release from the Dedication hereunder, at the request of Shipper, the Parties shall execute a release reasonably acceptable to Shipper (which, in the case of a permanent release, shall be in recordable form) reflecting the release of any Receipt Point(s), Well(s), Interest(s) and Shipper Crude Oil released from Dedication hereunder. 3.5 Covenant Running with the Land. So long as this Agreement is in effect, this Agreement shall (i) be a covenant running with the Interests now owned or hereafter acquired by Shipper and/or its Affiliates within the Dedicated Area (including, without limitation, all Wells operated by Shipper or its Affiliates) and (ii) be binding on and enforceable by Gatherer and its successors and assigns against Shipper, its Affiliates and their respective successors and assigns. Notwithstanding this Section 3.5, to the extent all or a portion of such Interests within the Dedicated Area are sold to a non-Affiliated Person, such acquiring Person shall only be required to dedicate for delivery hereunder that Crude Oil that is produced from such Interests within the Dedicated Area acquired by such non-Affiliated Person from Shipper. The acquiring Person shall not be required to dedicate Crude Oil produced from Interests already held by or acquired after such date by such acquiring Person. Notwithstanding the foregoing, with prior written notice to Gatherer, Shipper and its Affiliates shall each be permitted to convey, sell, assign, or otherwise transfer its interest in the Interests that are not connected to or in the process of being connected to the Gathering System free of the Dedication hereunder in an “acreage swap” or exchange transaction in which such undeveloped Interests within the Dedicated Area are exchanged for other properties or Interests of approximately equal net acreage and projected production located in the Dedicated Area that are not subject to a Prior Dedication and would become subject to the Dedication hereunder. Gatherer and Shipper shall prepare, execute, acknowledge, deliver, and record any such instruments and other documents reasonably necessary to effectuate such release and memorialize such acquired Interests subject to the Dedication. 12

3.6 Memorandum of Agreement. Contemporaneously with the execution of this Agreement, the Parties shall execute, acknowledge, deliver and record a “short form” memorandum of this Agreement in the form of Exhibit C attached hereto (the “Memorandum”). ARTICLE IV COMMENCEMENT DATE AND CONSTRUCTION OF FACILITIES 4.1 Commencement Date. The “Commencement Date” under this Agreement shall be the first Day of the Month following the date Gatherer notifies Shipper that (i) Gatherer has obtained all required operating permits and/or approvals of regulatory authorities, and (ii) all of the Commencement Date Facilities are ready to be placed in-service and operational to the extent necessary to commence the full performance of the Services as contemplated by this Agreement from the Receipt Point(s) to the Connecting Pipeline(s) (subject to Shipper’s obligation to provide its pro rata share of line fill hereunder). Gatherer shall, subject to Force Majeure, use commercially reasonable efforts to achieve the Commencement Date within one hundred eighty (180) Days after the Effective Date; provided, however, the Parties acknowledge and agree that there are a number of contingencies that may affect the actual Commencement Date, and, accordingly, except for the rights and remedies set out in Section 4.5, neither Party shall have any right or remedy against the other Party if the actual Commencement Date is earlier or later than the anticipated Commencement Date. 4.2 Construction of Commencement Date Facilities. Except for new facilities provided by Gatherer pursuant to Section 4.3 hereof, Shipper shall, at its sole cost and expense, install, own, operate and maintain all facilities and equipment upstream of the Receipt Points, including on-lease tank batteries. Without limitation of the foregoing, Shipper shall arrange for the supply of, and pay all Energy Costs associated with supplying of, continuous electrical power service as required to operate all equipment, including Gatherer’s equipment, at all Receipt Points to the extent Shipper has power available. If Shipper does not have power available at a Receipt Point, Gatherer will use its commercially reasonable efforts to make power available for its operations and Shipper will reimburse Gatherer for all Energy Costs. Shipper shall not bear any responsibility for any Energy Costs attributable to the Gathering System downstream of the Receipt Point(s). Gatherer shall, at its sole cost and expense, design, engineer, modify, construct and equip, maintain and operate or caused to be designed, engineered, modified, constructed and equipped, maintained and operated, the Gathering System, including the Commencement Date Facilities and any facilities constructed by Gatherer pursuant to Section 4.3 hereof to connect new Receipt Point(s), as necessary to perform the Services and all its obligations under this Agreement as a reasonably prudent operator and in accordance with the Tariff. Gatherer may design and shall expand, and may add or remove components of the Gathering System, as it determines to be best, provided that such operations are consistent with Gatherer’s obligations hereunder. Except through the payment of the rates specified in Article VIII or as otherwise expressly provided in this Agreement, Shipper shall have no responsibility for the cost of the Gathering System or any facilities constructed or to be constructed by Gatherer. The Receipt Point(s), including the Initial Receipt Point(s), installed by Gatherer hereunder, at its sole cost and expense, will contain a LACT and transfer pumps with the capacity at each such Receipt Point to measure and pump at least 5,000 BPD of Shipper Crude Oil. Gatherer’s LACTs shall include pipeline sample pots with capabilities to record quantity, API gravity, sediment and water and sulfur content. 13

4.3 Construction of Receipt Point(s); Drilling Plans. (a) In order to assist Gatherer in planning for future facilities which Gatherer may install under this Agreement following the Effective Date, every six (6) Months during the Term, Shipper shall provide to Gatherer copies of its current drilling plan(s) with respect to the Dedicated Area. Shipper shall provide Gatherer with an update to its drilling plan(s) promptly following any material change to a plan previously provided to Gatherer. Each drilling plan and any associated updates provided to Gatherer by Shipper of the drilling plan(s) shall include (i) the name and location of any new potential Receipt Point, (ii) Shipper’s estimate of the spud date, completion date and date of first production with respect to each new Well(s) associated with such new potential Receipt Point, and (iii) Shipper’s good faith estimate of the average daily volume from such new potential Receipt Point. (b) If, at any time after the Effective Date, Shipper desires that a new Receipt Point for any Well(s) located within the Dedicated Area (other than Wells delivering Crude Oil to the Initial Receipt Points identified in Exhibit B) be connected to the Gathering System, Shipper shall provide written notice to Gatherer for new Receipt Points associated with Shipper Crude Oil setting forth the expected date of first flow to Gatherer (the “Notification Date”), location and volume profile for such Receipt Point in the form attached hereto as Exhibit E (a “New Receipt Point Notification”). Following Gatherer’s receipt of a New Receipt Point Notification, Gatherer shall promptly commence and diligently conduct all reasonable operations at Gatherer’s sole cost and expense necessary to extend the existing Gathering System to each such new Receipt Point described in such New Receipt Point Notification that Shipper desires to be connected to the Gathering System by the later of (i)(A) for a new Receipt Point that is within two (2) miles of the existing Gathering System and does not require BLM approval to be connected to the Gathering System, one hundred twenty (120) Days after Gatherer’s receipt of the applicable New Receipt Point Notification, or (B) for a new Receipt Point that is either more than two (2) miles from the existing Gathering System and/or requires BLM approval to be connected to the Gathering System, one hundred eighty (180) Days after Gatherer’s receipt of the applicable New Receipt Point Notification, and (ii) the Notification Date (each such date, a “Target RP In-Service Date”); provided, however, with respect to Receipt Point(s) that are identified in New Receipt Point Notification(s) delivered by Shipper to Gatherer between the Effective Date and the Commencement Date, the Target RP In-Service Date with respect to such Receipt Point(s) shall be the later of the (i) Target RP In-Service Date (as defined above) or (ii) within sixty (60) Days after the Commencement Date. (c) If Gatherer fails or is unable to connect any such additional Receipt Point by the applicable Target RP In-Service Date for any reason, then the Shipper Crude Oil associated with such Receipt Point and the affected Well(s) and Interest(s) to which such Shipper Crude Oil is attributable shall be temporarily released from the Dedication until such time as such Receipt Point is connected, provided that, during such period, Gatherer shall have the right, but shall have no obligation, to (or to cause its designee to) truck all or a portion of the Shipper Crude Oil associated with such Receipt Point prior to the completion of such connection to Gatherer’s Wink Terminal via the Gathering System (if available) or to one or more alternative markets, purchasers, pipelines, processor or transporters designated by Producer in close proximity thereto (if Gatherer’s Wink Terminal is not available), and by doing so, such Shipper Crude Oil trucked by Gatherer or its designee shall be considered received hereunder and not 14

temporarily released hereunder. If Gatherer elects the option to truck Barrels of Shipper Crude Oil as provided in the immediately preceding sentence, (w) Shipper’s Priority Rate will apply to all such Barrels, and (x) Gatherer shall redeliver such Shipper Crude Oil to Gatherer’s Wink Terminal via the Gathering System (if available) or to one or more alternative markets, purchasers, pipelines, processor or transporters designated by Producer in close proximity thereto (if Gatherer’s Wink Terminal is not available). Shipper may, at its sole option, store or deliver all or any portion of the Shipper Crude Oil temporarily released hereunder to Gatherer’s Wink Terminal via the Gathering System (if available) or an alternative market, purchaser, pipeline, processor or transporter (if Gatherer’s Wink Terminal is not available); provided, however, to the extent that Gatherer does not elect its trucking option under this Section 4.3(c) and the temporary release is not attributable to a Force Majeure, Gatherer shall reimburse Producer for Producer’s out of pocket costs incurred during such release period on a per Barrel basis to truck Shipper Crude Oil to Gatherer’s Wink Terminal via the Gathering System (if available) or such alternative markets, purchasers, pipelines, or transporters (if Gatherer’s Wink Terminal is not available), less the Shipper’s Priority Rate per Barrel. (d) In addition to Gatherer’s obligations set forth in Section 4.3(c) above, if Gatherer fails or is unable to connect any such additional Receipt Point by the date that is thirty (30) Days beyond the applicable Target RP In-Service Date for any reason other than Force Majeure, then, for each Day of unexcused delay until Gatherer connects such additional Receipt Point beyond the Target RP In-Service Date, Gatherer shall temporarily reduce Shipper’s Priority Rate to $0.375 per Barrel and Shipper’s Uncommitted Rate to $0.370 per Barrel for Shipper Crude Oil delivered to such additional Receipt Point for only a period of time equal to the amount of Days from the deadline set forth in the first sentence of this Section 4.3(d) until the date such additional Receipt Point is connected; provided, however, on the first Day after the expiration of such period of time, Shipper’s Priority Rate and Shipper’s Uncommitted Rate will be increased to such rates, respectively, set out in Article VIII and Exhibit B. By means of example, if Gatherer connects a requested Receipt Point fifty (50) Days after the Target In- Service Date for such additional Receipt Point, and such delay is not due to an event of Force Majeure, then the reduction in Shipper’s Priority Rate and Shipper’s Uncommitted Rate described in the preceding sentence would apply to Shipper Crude Oil received at such additional Receipt Point for the first twenty (20) Days after such additional Receipt Point is connected. (e) Notwithstanding anything in this Section 4.3 to the contrary, if Gatherer fails or is unable to connect any such additional Receipt Point by the date that is (i) one hundred eighty (180) Days beyond the applicable Target RP In-Service Date for any reason other than Force Majeure or (ii) two hundred seventy (270) Days beyond the applicable Target RP In- Service Date due to Force Majeure, then Shipper shall have the right, immediately following such period, to request and receive a permanent release from Gatherer of the affected Interest(s) and Well(s) delivering to such additional Receipt Point (including the volumes of Crude Oil associated therewith). Shipper acknowledges that the rights and remedies set forth in this Section 4.3 shall be its sole and exclusive remedies in the event of Gatherer’s failure to timely connect a requested additional Receipt Point. (f) In the event that Gatherer completes an interconnection requested by Shipper and paid for by Gatherer for any new Receipt Point, and after one hundred eighty (180) Days following the date of completion of any such Receipt Point, Shipper has not used the 15

additional Receipt Point for any reason other than Force Majeure, then Shipper shall reimburse any and all reasonable and documented out-of-pocket costs, expenses or fees incurred by Gatherer related to the connection of such Receipt Point to the Gathering System (but excluding trunklines, terminals or other facilities located downstream of the lateral gathering lines constructed to connect such Receipt Point); provided that (i) Shipper shall not be required to reimburse such costs, expenses or fees in the event Gatherer is otherwise utilizing the installed pipelines and related equipment in a manner that is not reasonably expected to result in lost profits or additional costs beyond the amounts anticipated for connecting the applicable additional Receipt Point to the Gathering System, (ii) Gatherer shall prepare and deliver to Shipper an itemized invoice of such costs, fees and expenses, which total amount shall be reimbursed by Shipper in equal Monthly installments over a five (5) year period, with the first such installment due within thirty (30) Days of receipt of Gatherer’s invoice, and (iii) in the event Shipper reimburses Gatherer for all or a portion of such costs, fees and expenses and, subsequently, such additional Receipt Point is later used by Shipper to deliver Shipper Crude hereunder, then Shipper shall receive a credit, equal to the total or partial amount of such costs, fees and expenses so reimbursed by Shipper, towards the payment of the amounts that would be due from Shipper to Gatherer hereunder for the delivery of such Shipper Crude Oil at such new Receipt Point. 4.4 License and Right-of-Use. Gatherer is responsible, at its sole cost and expense, for the acquisition and maintenance of easements, rights-of-way, fee lands and surface use and/or surface access agreements necessary to construct, own and operate the Gathering System. Notwithstanding the foregoing, upon Gatherer’s written request, to the extent that Shipper is legally and contractually entitled to do so without the incurrence of cost or expense, Shipper shall grant to Gatherer for purposes of constructing, owning, operating, repairing, replacing and maintaining any portion of the Gathering System, a non-exclusive license and right-of-use (including, without limitation, such license or right-of-use encompassed in Shipper’s or its Affiliates’ oil and gas leases or other agreements with third parties) over, across and under Shipper’s or its Affiliates, Interests as are reasonably necessary for such purposes. Shipper shall have no obligation to execute any easements, rights-of-way, and/or other conveyances of real property in connection with the foregoing license and right-of-use. All facilities and other equipment acquired, placed, or installed by Gatherer for the purposes of this Agreement pursuant to the provisions of this Section 4.4, will remain the property of Gatherer. In the event Shipper identifies any issue with such Gatherer’s facilities on Shipper’s or its Affiliates’ Interests, Shipper will notify Gatherer of such issue and Gatherer and Shipper will work collaboratively to remedy the same. Gatherer shall be responsible for and release, defend, indemnify, and hold the Shipper Indemnified Parties harmless from and against any and all Claims and Losses, arising from or relating to Gatherer’s use of, or operations on, any such non-exclusive license and right-of-use granted by Shipper, except to the extent such Claims or Losses are caused by or attributable to the negligence, gross negligence or willful misconduct of any of the Shipper Indemnified Parties. Shipper shall be responsible for and release, defend, indemnify, and hold the Gatherer Indemnified Parties harmless from and against any and all Claims and Losses, arising from or relating to Shipper’s use of, or operations on, any fee lands, easements, right-of-way, or similar surface access rights owned or maintained by Gatherer, except to the extent such Claims or Losses are caused by or attributable to the negligence, gross negligence or willful misconduct of any of the Gatherer Indemnified Parties. 16

4.5 Construction Delay. (a) If the Commencement Date does not occur within two hundred ten (210) Days after the Effective Date (“Project Deadline”), then Gatherer shall reimburse Shipper for Shipper’s out of pocket costs on a per Barrel basis minus $0.75 per Barrel to truck Shipper Crude Oil from the Dedicated Area to Gatherer’s Wink Terminal via the Gathering System (if available) or to one or more alternative markets, purchasers, pipelines, processor or transporters designated by Producer in close proximity thereto (if Gatherer’s Wink Terminal is not available) after the Project Deadline that if not for the delay in the Commencement Date such Shipper Crude Oil would have been gathered and transported on the Gathering System. Gatherer’s payment obligation under this Section 4.5 hereunder shall continue until the earlier of the Commencement Date or the termination of this Agreement. However, Gatherer shall have the right, but shall have no obligation, to (or cause its designee to) truck all or a portion of such Shipper Crude Oil as contemplated above and Shipper shall pay Gatherer Shipper’s Priority Rate with respect to such trucking services. In the event that Gatherer’s Wink Terminal is not complete during such period described above, Shipper Crude Oil may be trucked to an to one or more alternative markets, purchasers, pipelines, processor or transporters designated by Producer in close proximity thereto. Notwithstanding anything herein to the contrary, if the Project Deadline is delayed due to a properly noticed event of Force Majeure, then the Project Deadline shall be extended for each Day of any such delay. (b) In addition to Gatherer’s obligations set forth in Section 4.5(a) above, if the Commencement Date does not occur by the Project Deadline, then upon the Commencement Date, Gatherer shall temporarily reduce Shipper’s Priority Rate to $0.375 per Barrel and Shipper’s Uncommitted Rate to $0.370 per Barrel for only a period of time equal to the amount of Days from the Project Deadline until the Commencement Date (“Delay Period”); provided, however, on the first Day after the expiration of the period of time after the Commencement Date equal to the Delay Period, Shipper’s Priority Rate and Shipper’s Uncommitted Rate will be increased to such rates, respectively, set out in Article VIII and Exhibit B. By way of example, if the Delay Period is equal to thirty (30) Days, then Shipper’s Priority Rate and Shipper’s Uncommitted Rate will be $0.375 per Barrel and $0.370 per Barrel, respectively, for only the first 30 Days after the Commencement Date and on the 31st Day after the Commencement Period, Shipper’s Priority Rate and Shipper’s Uncommitted Rate shall be as set out in Article VIII and Exhibit B. Notwithstanding anything herein to the contrary, if the Project Deadline is delayed due to a properly noticed event of Force Majeure, then the Project Deadline shall be extended for each Day of any such delay. (c) If Gatherer fails to cause the Commencement Date to occur on or before the four hundred eightieth (480th) Day after the Effective Date for any reason, due to Force Majeure or otherwise, then Shipper, at Shipper’s option, shall be entitled to terminate this Agreement in its entirety. Shipper’s right to terminate pursuant to this Section 4.5(c) shall expire when the Commencement Date occurs. 4.6 Connecting Pipelines. Gatherer shall install two (2) initial interconnections with Connecting Pipelines: (i) at the Initial Delivery Point as of the Commencement Date, and (ii) at one additional Delivery Point with the EPIC Crude Oil Pipeline or other pipeline with direct, long-haul transportation to the Corpus Christi, Texas area, which Gatherer shall use 17

commercially reasonable efforts to install on or before December 31, 2019, subject to any delay in the in service date for the EPIC Crude Oil Pipeline. In addition to such two (2) initial interconnections, Shipper has the right to propose that Gatherer, at Gatherer’s sole cost and expense, construct up to two additional interconnections with Connecting Pipelines, provided that such additional interconnections are within five (5) miles of the Gathering System. In the event Shipper reasonably requests additional interconnections with Connecting Pipelines in excess of such two additional interconnections described in the immediately preceding sentence, if Shipper agrees to pay Gatherer pursuant to a mutually agreeable facilities reimbursement agreement an amount equal to all of the actual reasonable, direct and out-of-pocket costs associated with such additional facilities, as determined by Gatherer, then Gatherer shall be obligated to construct the proposed interconnection(s). ARTICLE V DELIVERY TO CONNECTING PIPELINES Gatherer shall deliver Shipper Crude Oil in accordance with the Services to Shipper or for Shipper’s account at the Delivery Point(s) pursuant to the Tariff. ARTICLE VI GATHERER OBLIGATIONS 6.1 Provision of Services. Subject to the terms and conditions of this Agreement, Gatherer shall, commencing on the Commencement Date and continuing through the remainder of the Term of this Agreement, provide Services for Shipper Crude Oil in accordance with this Agreement, including the Tariff, which is incorporated herein by reference and constitutes part of this Agreement, expressly including provisions in the Tariff relating to the charges and rules and regulations applicable to Shipper as a Party to this Agreement. Other than Gatherer’s working tanks required in the process of transporting Crude Oil, the Services do not include any terminaling, tankage or storage. 6.2 Gatherer’s Prorationing Obligations; Priority Service. As set forth in the Tariff, notwithstanding any other provisions of this Agreement, to the extent permitted by Applicable Law, the terms of the Tariff shall provide generally that, subject to Gatherer’s rights and remedies under Article XIX hereof, Defaults and Remedies, a tender of Shipper Crude Oil by Shipper for transport on the Gathering System not exceeding Shipper’s Maximum Daily Quantity and paying the Priority Rate for levels of applicable service on the Gathering System (“Priority Service”), shall be entitled to the highest level of service on the Gathering System and not be subject to prorationing to accommodate nominations of uncommitted volumes for transport on the Gathering System or nominations of volumes for transport on the Gathering System by shippers who do not elect to pay (or are not eligible thereunder) the Priority Rate for such nominations. The allocation of the operational capacity of the Gathering System at any given time among Priority Shippers and other Shippers is set forth in the Tariff. Notwithstanding anything herein to the contrary, consistent with the Tariff, Gatherer agrees that, during the Term of this Agreement, it will not enter into contracts with other Priority Shippers which, when taken in the aggregate, along with Gatherer’s obligations to provide Priority Service to Shipper hereunder, would obligate Gatherer to provide Priority Service on the Gathering System that would exceed ninety percent (90%) of the capacity of the Gathering System. Gatherer agrees 18

that during the Term of this Agreement, Gatherer shall note create a higher level than Priority Service. ARTICLE VII NOMINATIONS AND OTHER TERMS 7.1 Nominations. Commencing on the Commencement Date and continuing thereafter during the Term, Shipper agrees to tender (or cause to be tendered) at the Receipt Points, Shipper Crude Oil to Gatherer for gathering and transportation on the Gathering System as set forth on Exhibit B, in accordance with the nomination and tender procedures set forth in the Tariff. Shipper expressly acknowledges and affirms that Gatherer is relying on Shipper’s Dedication, together with the volume commitments and dedications from other Priority Shippers executing COGAs, in order to establish the economic justification for the Gathering System. 7.2 Unused Capacity. Shipper agrees, to the extent Shipper does not nominate or tender up to Shipper’s Maximum Daily Quantity on the Gathering System in any Month, Gatherer shall be free to utilize such unused capacity on the Gathering System for the provision of gathering and transportation services to other shippers, but only to the extent and duration of Shipper’s under-utilization of its capacity, without impacting the payment obligations of Shipper or any other obligations of Shipper, including, but not limited to Shipper’s obligations pursuant to Article III or otherwise crediting or paying Shipper in any manner. Nothing in this Section 7.2 shall operate to reduce or otherwise alter Shipper’s Maximum Daily Quantity. 7.3 Tariff. Shipper’s nominations and tenders of Crude Oil for shipment, and Gatherer’s scheduling, acceptance, gathering, transporting, measuring and delivering of Crude Oil, shall, at all times, be subject to, and implemented in accordance with the Tariff. Shipper shall comply with the Tariff at all times. The Tariff is subject to amendment by Gatherer in accordance with Section 14.1 and Section 20.1. 7.4 Linefill. Shipper shall provide (a) its share of linefill sufficient for the operation of the Gathering System utilized by Shipper as required by the Tariff and (b) at least thirty (30) Days prior to the Commencement Date (to the extent that the Commencement Date Facilities can receive such linefill at such time), its proportionate share of linefill for the Gathering System to be utilized by Shipper, as reasonably determined by Gatherer and specified in a written notice given by Gatherer to Shipper at least thirty (30) Days prior to the Commencement Date. Gatherer shall not be required to provide the Services hereunder until Shipper provides its pro rata portion of linefill. 7.5 Off-Spec Crude Oil. The Tariff sets out that Gatherer reserves the right to reject all tenders of Crude Oil and refuse transportation if Gatherer determines that Shipper has delivered Crude Oil that does not conform to the Tariff’s specifications (as defined in the Tariff, “Off-Spec Crude Oil”), all of which shall be determined by Gatherer in its reasonable discretion. The Tariff also sets out under what conditions Gatherer may accept Off-Spec Crude Oil and commingle the same with the common stream. In addition to the provisions in the Tariff, Shipper and Gatherer may agree that (i) Gatherer will install and operate treatment facilities at Receipt Point(s), for a mutually agreeable treating fee (which treating fee would be in lieu of Shipper’s reimbursement of the actual costs and expenses incurred by Gatherer to treat, handle, 19

or otherwise dispose of such Off-Spec Crude Oil, as authorized in the Tariff), or (ii) Shipper or its designee will install and operate treatment facilities upstream of the Receipt Point(s), provided that such Party that is to install (or cause to be installed) such facilities shall use commercially reasonable efforts to install (or cause to be installed) such facilities in a timely manner. If Shipper and Gatherer agree that either Gatherer or Shipper shall install and operate such treating facilities pursuant to the immediately preceding sentence, then Off-Spec Crude Oil shall be temporarily released from this Agreement (free of any obligation to pay Gatherer the Priority Rate or the Uncommitted Rate, as applicable), and Shipper may deliver such Off-Spec Crude Oil to a third party, from the time such Crude Oil is determined to be Off-Spec Crude Oil until such time as Gatherer is able to accept such Off-Spec Crude following the installation of such treating facilities, provided, that Gatherer shall have the right, but shall have no obligation, to (or cause its designee to) truck all or a portion of such Off-Spec Crude Oil to Gatherer’s Wink Terminal via the Gathering System, and by doing so, such Off-Spec Crude Oil trucked by Gatherer or its designee shall be considered received hereunder and accepted under the Tariff, and not temporarily released hereunder. If Gatherer elects the option to truck Barrels of Off- Spec Crude Oil as provided in the immediately preceding sentence, (i) Shipper’s Priority Rate will apply to all such Barrels, and (ii) Gatherer shall redeliver such Off-Spec Crude Oil to Gatherer’s Wink Terminal via the Gathering System. Notwithstanding the foregoing, if Shipper and Gatherer do not agree (x) upon the terms under which Gatherer will install and operate treatment facilities, or (y) that Shipper or its designee shall install and operate treatment facilities upstream of the Receipt Point(s), within thirty (30) Days of the date of Gatherer’s initial proposal to Shipper regarding the same, then, subject to Gatherer’s right to truck Off-Spec Crude Oil as set forth in the previous two sentences of this Section 7.5, Off-Spec Crude Oil shall be temporarily released from this Agreement from the time such Crude Oil is determined to be Off- Spec Crude Oil; provided, however, after the expiration of such thirty (30) Day period until the date that Shipper and Gatherer agree that either Gatherer or Shipper shall install and operate treating facilities as provided in this Section 7.5, Shipper may continue to deliver such Off-Spec Crude Oil to a third party, but shall pay Gatherer the Priority Rate or the Uncommitted Rate, as applicable, for such volumes of Off-Spec Crude Oil as if such volumes were delivered to Gatherer hereunder. For the avoidance of doubt, Shipper shall not be entitled to a release of Off- Spec Crude Oil except as provided in this Section 7.5. 7.6 Loss Allowance. Pursuant to the Tariff, Gatherer shall deduct the actual losses of Shipper Crude Oil on a pro rata basis to cover losses inherent in the transportation of Shipper’s Crude Oil on the Gathering System, provided that such loss allowance shall not exceed (i) two- tenths of one percent (0.20%) of the volumes of Shipper Crude Oil received into the Gathering System, with respect to Shipper Crude Oil having an API Gravity of 49.9 degrees or less, or (ii) four-tenths of one percent (0.40%) of the volumes of Crude Oil received in the Gathering System, with respect to Shipper Crude Oil having an API Gravity of 49.9 degrees to 60 degrees (Gatherer will not accept for transportation Crude Oil with API Gravity above 60 degrees). The volumes delivered to Shipper or its designee from Gatherer’s facilities shall be net of such deduction. 7.7 Commingling; Quality Bank. Pursuant to the Tariff, Gatherer shall be entitled to commingle Shipper Crude Oil with other Crude Oil delivered to the Gathering System from other shippers, and to transport Crude Oil in a common stream to the Delivery Point(s), provided that Gatherer shall not knowingly accept any shipper’s delivery of Off-Spec Crude Oil if 20

Gatherer determines that the quality of such Off-Spec Crude Oil, when commingled as a common stream, would not meet the quality specifications in the Tariff. Gatherer shall not be liable to Shipper for changes in gravity or quality of Shipper’s Crude Oil which may occur from commingling or intermixing Shipper Crude Oil with other Crude Oil in the same common stream while in transit, except to the extent that such commingling or intermixing would render Shipper’s Crude Oil to be Off-Spec Crude Oil or undeliverable as a result of Off-Spec Crude Oil received from other shippers. Shipper acknowledges that Shipper Crude Oil may be commingled with other Crude Oil that Gatherer has purchased from and/or gathered for others; therefore, the Crude Oil delivered at the Delivery Point(s) may not contain the same molecules as those received by Gatherer at the Receipt Point(s). In the event that Crude Oil delivered from the common stream to one or more Priority Shippers on the Gathering System consistently has an API Gravity greater than ten degrees API than the Crude Oil delivered by such Priority Shipper to Gatherer into the Gathering System, and (ii) a majority of Priority Shippers (at least two out of three) request a quality bank agreement to address such differences in gravity, then Gatherer and all Priority Shippers shall negotiate in good faith in an effort to enter into such an agreement, and to the extent entered into, all Shippers on the Gathering System shall be subject thereto and settled thereunder. 7.8 Possession and Control; Liability. As between Shipper and Gatherer, (i) Shipper is deemed in control and possession of Shipper Crude Oil delivered for Services hereunder until Shipper delivers, or causes to be delivered, such Shipper Crude Oil at the Receipt Point(s) and after Gatherer re-delivers, or causes to be re-delivered, such Shipper Crude Oil at the Delivery Point(s), and (ii) Gatherer is deemed in control and possession of Shipper Crude Oil delivered for Services hereunder from and after the time Shipper delivers, or causes to be delivered, such Shipper Crude Oil at the Receipt Point(s) until Gatherer re-delivers, or causes to be re-delivered, such Shipper Crude Oil at the Delivery Point(s). ARTICLE VIII FEES 8.1 Tariff Filings and Rates. Shipper shall pay rates for all volume of Crude Oil transported by Shipper on the Gathering System in accordance with the Tariff, which shall, to the extent permitted by Applicable Law, provide for the following: (a) Rate for Volumes up to Shipper’s Maximum Daily Quantity. For Actual Shipments on the Gathering System each Day during a Month up to Shipper’s Maximum Daily Quantity, Shipper shall pay to Gatherer a per Barrel Tariff rate (“Shipper’s Priority Rate”) equal to the applicable base priority rate corresponding to Shipper’s average Daily Actual Shipments during such Month, which shall be, as of the Commencement Date, the applicable base priority rate set forth in Exhibit B attached hereto, and which shall be increased by Gatherer annually, effective each January 1st after the Commencement Date, as provided in Section 8.3 hereof. (b) Rate for Volumes in Excess of Shipper’s Maximum Daily Quantity. For Actual Shipments on the Gathering System each Day during a Month in excess of Shipper’s Maximum Daily Quantity, Shipper shall pay to Gatherer a per Barrel Tariff rate (“Shipper’s Uncommitted Rate”) equal to the applicable base uncommitted rate corresponding to Shipper’s average Daily Actual Shipments during such Month on the Gathering System, which shall be, as 21

of the Commencement Date, the applicable base uncommitted rate set forth in Exhibit B attached hereto, and which shall be increased by Gatherer annually, effective each January 1st after the Commencement Date, as provided in Section 8.3 hereof. 8.2 Governmental Modifications. Notwithstanding anything herein to the contrary, the Parties acknowledge that the Tariff rates payable for all Services are subject to the approval of and modification by the FERC or any other Governmental Authority having jurisdiction, subject in all respects to the terms and provisions and limitations of Article XIII. 8.3 Fee Escalation. Effective as of 9:00 a.m., Central Clock Time, on the first January 1st that occurs two years after the Commencement Date, and each January 1st occurring thereafter, Shipper’s Priority Rates and Shipper’s Uncommitted Rates shall be adjusted upwards or downwards following FERC’s indexing adjustment, as set out in 18 C.F.R. § 342.3, including future amendments or modifications thereof, provided, however, that such indexing adjustment shall not result in an increase or decrease in the Shipper’s Priority Rate and/or Shipper’s Uncommitted Rate that exceeds two percent (2%) or a decrease in the Shipper’s Priority Rate and/or Shipper’s Uncommitted Rate that would result in a rate less than the rates set out in Exhibit B. In the event that Gatherer is unable to make a tariff filing pursuant to 18 C.F.R. § 342.4(c) to adjust Shipper’s Uncommitted Rates, then Gatherer will make a tariff filing to adjust Shipper’s Uncommitted Rates effective as of the subsequent July 1 pursuant to 18 C.F.R. § 342.3. However, if the FERC indexing adjustment is eliminated, the Parties agree to increase or decrease Shipper’s Priority Rates and Shipper’s Uncommitted Rates to reflect any positive changes or negative changes in the Producer Price Index for Finished Goods, on a year-over-year basis, subject to the above-noted increase and decrease limitations. ARTICLE IX WARRANTY OF TITLE 9.1 Title Warranty. Shipper represents and warrants to Gatherer that Shipper has title to and/or the right to transport all Shipper Crude Oil delivered hereunder, and that, other than Shipper’s Permitted Liens, said Shipper Crude Oil is free from liens, claims, encumbrances and adverse claims, including liens to secure payment of production taxes, severance taxes, and other taxes. SHIPPER SHALL RELEASE, INDEMNIFY, DEFEND, AND HOLD HARMLESS THE GATHERER INDEMNIFIED PARTIES FROM AND AGAINST ALL CLAIMS OF ANY AND ALL PERSONS RELATING TO OWNERSHIP OF SAID SHIPPER CRUDE OIL OR TO ROYALTIES, OVERRIDING ROYALTIES, TAXES, LICENSE FEES, OR CHARGES THEREON. Gatherer shall not allow any liens, claims, encumbrances or adverse claims arising by, through or under Gatherer to attach to Shipper Crude Oil while in the possession and control of Gatherer, and GATHERER SHALL RELEASE, INDEMNIFY, DEFEND, AND HOLD HARMLESS THE SHIPPER INDEMNIFIED PARTIES FROM AND AGAINST ALL CLAIMS OF ANY AND ALL PERSONS RELATING TO ANY SUCH LIENS, CLAIMS, ENCUMBRANCES OR ADVERSE CLAIMS. 9.2 Proceeds of Production. Shipper agrees to make payment of all royalties, overriding royalties, production payments, and all other payments for interests attributable to 22

Shipper Crude Oil delivered hereunder due to any Person under any leases or other documents in accordance with the terms thereof. 9.3 Indemnification. Shipper agrees to indemnify and hold the Gatherer Indemnified Parties harmless from any and all Claims and Losses incurred in connection with, or in any manner whatsoever relating to (i) any breach of the representations and warranties made by Shipper pursuant to Section 9.1 above, and (ii) payment of Taxes, royalties, overriding royalties, production payments, and all other payments for interests attributable to Shipper Crude Oil delivered hereunder. 9.4 Title to Shipper Crude Oil. Title to Shipper Crude Oil delivered or caused to be delivered by Shipper to Gatherer hereunder at the Receipt Point(s) shall remain with Shipper and shall not pass to nor vest in Gatherer at any point under this Agreement. ARTICLE X WAIVER OF CERTAIN DAMAGES NOTWITHSTANDING ANYTHING TO THE CONTRARY IN THIS AGREEMENT, IN NO EVENT SHALL EITHER PARTY BE LIABLE TO THE OTHER PARTY OR ITS AFFILIATES, ANY SUCCESSORS IN INTEREST OR ANY BENEFICIARY OR ASSIGNEE OF THIS AGREEMENT FOR ANY CONSEQUENTIAL, INCIDENTAL, INDIRECT, SPECIAL, OR PUNITIVE DAMAGES, INCLUDING, WITHOUT LIMITATION, ANY LOST PROFITS OR REVENUES THAT CONSTITUTE SUCH DAMAGES, THAT ARISE OUT OF OR RELATE TO THIS AGREEMENT OR ANY BREACH HEREOF; PROVIDED, HOWEVER, THE FOREGOING SHALL NOT BE CONSTRUED AS LIMITING AN OBLIGATION OF A PARTY HEREUNDER TO INDEMNIFY, DEFEND AND HOLD HARMLESS PERSONS ENTITLED TO INDEMNIFICATION HEREUNDER AGAINST CLAIMS ASSERTED BY UNAFFILIATED THIRD PARTIES, INCLUDING, BUT NOT LIMITED TO, THIRD PARTY CLAIMS FOR SPECIAL, INDIRECT, CONSEQUENTIAL, PUNITIVE OR EXEMPLARY DAMAGES. ARTICLE XI FORCE MAJEURE 11.1 Suspension of Obligations. If either Party is unable to perform any obligations due to an event of Force Majeure, such failure shall not be a default under this Agreement, insofar as such obligations are affected by such event of Force Majeure, for the duration of such event of Force Majeure, and any additional period when Gatherer remains unable to perform such obligations as a result of such event of Force Majeure. The Party incurring the Force Majeure event will make reasonable attempts to remedy such event (it being agreed, without limitation, that the terms of settlement of any strike, lockout, or other industrial disturbance will be wholly in the discretion of such Party). The Party incurring the Force Majeure event will promptly notify the other Party in writing of any event of Force Majeure affecting the ability to perform its obligations and will provide a nonbinding, written estimate of the anticipated duration of such Force Majeure event. Notwithstanding the foregoing, the existence of an event 23

of Force Majeure will not relieve either Party’s obligations hereunder to the extent any action or inaction is not the result of Force Majeure. 11.2 Definition of Force Majeure. The term “Force Majeure” shall mean any cause or causes not reasonably within the control of the Party claiming suspension and which, by the exercise of reasonable diligence, such Party is unable to prevent or overcome, including acts of God, acts of Governmental Authorities, compliance with rules, regulations or orders of any Governmental Authority, strikes, lockouts or other industrial disturbances, acts of the public enemy, acts of terrorism, wars, blockades, insurrections, riots, epidemics, landslides, lightning, earthquakes, fires, extreme cold, storms, hurricanes, floods, or other adverse weather conditions, washouts, arrests and restraint of rulers and people, civil disturbances, explosions, breakage or accident to machinery, equipment or pipelines, freezing of wells, pipelines or equipment, requisitions, directives, diversions, embargoes, priorities or expropriations of government or Governmental Authorities, legal or de facto, whether purporting to act under some constitution, decree, law or otherwise, failure of pipelines or other gatherers to gather or furnish facilities for transportation, failures, disruptions, or breakdowns of machinery or of facilities for production, manufacture, transportation, distribution, processing or consumption (including, but not by way of limitation, the Gathering System), allocation or curtailment by third parties of downstream capacity, inability to secure or delays in securing permits from Governmental Authorities, transportation embargoes or failures or delays in transportation or poor road conditions, partial or entire failure of Crude Oil supply and downstream pipeline market constraints. “Force Majeure” shall expressly exclude (i) delays in permitting that are not extraordinary or unusual for the Dedicated Area and the development of the Permian Basin and other relevant basins, or (ii) any matters within the reasonable control of Gatherer (such as easement, right-of-way, fee land and surface right acquisition, the availability of labor, materials and supplies, and other similar matters). 11.3 Interruption of Operations. Pursuant to the Tariff, Gatherer may, without liability to Shipper (but subject to and without limitation of Shipper’s release rights pursuant to the terms and conditions of Section 3.4), interrupt the operations of its facilities for the purpose of performing inspections, pigging, maintenance, testing, alterations, modifications, expansions, connections, repairs or replacements, but such interruption shall be for only such time as may be reasonable. Gatherer shall give Shipper at least thirty (30) Days’ advance written notice, except in case of emergency, of its intention to interrupt operations and of the estimated time thereof. ARTICLE XII DISPUTE RESOLUTION 12.1 Resolution of Disputes. Any Dispute shall be resolved pursuant to the provisions of this ARTICLE XII, which shall be the sole and exclusive procedures for the resolution of any such Dispute. While the procedures in this ARTICLE XII are pending, each Party shall continue to perform its existing obligations under the Agreement to the extent those obligations are not the subject of the Dispute. 12.2 Dispute Notice. Prior to submitting any Dispute for resolution by a court, a Party shall provide written notice (a “Dispute Notice”) to the other of the occurrence of such dispute. The Dispute Notice shall contain (i) a concise statement describing the Dispute, including a 24

description of its nature, circumstances and cause, (ii) an explanation of the basis and justification for the Dispute, including reference to any pertinent provision(s) of the Agreement, (iii) if applicable, the estimated dollar amount of the Dispute and how that estimate was determined, (iv) the claiming Party's desired resolution, and (v) any other information the claiming Party deems relevant. 12.3 Direct Negotiation. Commencing within thirty (30) Days after the Dispute Notice is received and concluding fifteen (15) Business Days thereafter, the authorized representatives of the Parties with decision-making authority shall meet in person in Houston, Texas (or in a place mutually agreed upon by the Parties to the Dispute) in an attempt to resolve the Dispute raised in the Dispute Notice. If the Parties are unable to resolve the Dispute for any reason within such fifteen (15) Business Day period, then either Party shall be entitled to pursue any remedies available at law or in equity; or as otherwise provided in this Agreement; provided, however, this ARTICLE XII shall not limit a Party’s right to initiate litigation prior to the expiration of the time periods set forth in this Section 12.3 if application of such limitations would prevent a Party from filing a lawsuit or claim within the applicable period for filing lawsuits (e.g. statutes of limitation, prescription, etc.). 12.4 Jurisdiction and Venue; Jury Waiver . The Parties hereby irrevocably consent to the exclusive jurisdiction of the state or federal courts located in Houston, Harris County, Texas and irrevocably and unconditionally waive, to the fullest extent they may legally and effectively do so, any objection which they may now or hereafter have to the laying of venue of any suit, action or proceeding arising out of or relating to this Agreement or the transactions contemplated hereby in any federal or state court located in Houston, Harris County, Texas. EACH PARTY HEREBY IRREVOCABLY AND UNCONDITIONALLY WAIVES ANY RIGHT SUCH PARTY MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY LITIGATION DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT. 12.5 Costs and Expenses. The prevailing Party in any litigation pertaining to any Dispute hereunder shall be entitled to recover its reasonable costs, expenses and attorney’s fees in connection with such litigation. 12.6 Confidentiality of Dispute Resolution. 25

(a) The Parties agree that any Dispute and any negotiations among the Parties in relation to any Dispute shall be subject to the confidentiality provisions of this Agreement. The Parties further agree that any information, documents or materials produced for the purposes of, or used in, negotiations of any Dispute shall be subject to the confidentiality provisions of this Agreement. The Parties further agree that upon the request of the providing Party, any information, documents or materials produced by such Party for the purpose of negotiations of any Dispute shall be destroyed or returned to the providing Party within thirty (30) Days of the resolution of such Dispute or the issuance of a final decision with respect to such Dispute; provided, however, any confidential information (i) found in drafts, notes, studies and other documents prepared by or for the receiving Party or its representatives, or (ii) found in electronic format as part of receiving Party’s off-site or on-site data storage/archival process system, will be held by the receiving Party or destroyed at the receiving Party’s option. (b) Without limiting the foregoing, the Parties agree that disclosure of confidential information to third parties may only be made if: (i) necessary to enforce any of the provisions of this Agreement, including without limitation, any court judgment; (ii) such third party is an auditor, advisor, insurer, expert witness or Affiliate of the disclosing party and has a legitimate need to know such confidential information; (iii) the disclosing Party is under a legal or regulatory obligation to make such disclosure, but such disclosure shall be limited to the extent of such legal obligation; or (iv) the non-disclosing Party provides prior written consent to the disclosing Party to disclose such information. (c) The Parties agree to submit to the jurisdiction of a court of competent jurisdiction located in Houston, Harris County, Texas for the purpose of any proceedings to enforce this Section 12.6 and, except as permitted under this Section 12.6(b), the receiving Party shall prevent any information, documents or materials belonging to a disclosing Party from being disclosed to third parties. ARTICLE XIII DUTY TO SUPPORT 13.1 Arm's Length Negotiations. Each of the Parties acknowledges and agrees that this Agreement is the result of good faith, arm's length negotiations which have resulted in an agreement that is fair and equitable to Gatherer and Shipper. 13.2 Shipper Support. Shipper hereby agrees to any tariff rate filings for the Gathering System which are made in accordance with this Agreement. Shipper agrees (i) not to challenge, nor to encourage or recommend to any other Person that it challenge, or voluntarily assist in any way any other Person in challenging, in any forum, any or all of the tariff rates for the Gathering System and (ii) not to protest or file a complaint, nor encourage or recommend to any other 26

Person that it protest or file a complaint, or voluntarily assist in any way any other Person in protesting or filing a complaint, with respect to any or all of the tariff rates for the Gathering System in each case so long as the tariff rates are in accordance with, or not inconsistent with, the terms of this Agreement. Furthermore, Shipper hereby agrees at its own cost, upon written request by Gatherer provided at least ten (10) Days prior to the deadline for such action: (a) to support Gatherer's applications for necessary certificates, approvals, authorizations and permits of the FERC and Texas and New Mexico regulating bodies, if any, in relation to the Gathering System; (b) to support the tariff rates calculated in accordance with the terms of this Agreement, and not take any action directly or indirectly that could be interpreted as evidence of Shipper's lack of support for such Tariff rates; and (c) to support the pro forma Tariff materially in the form attached as Exhibit F, in any and all regulatory proceedings relating thereto and not take any action or inaction that could be interpreted as evidence of Shipper's lack of support therefor; provided that nothing in the foregoing shall obligate Shipper to support future changes to the Tariff rates that are inconsistent with this Agreement, or prevent Shipper from opposing any position taken by Gatherer before FERC and/or Texas and/or New Mexico regulating bodies that is inconsistent with this Agreement. 13.3 No Tariff Rate Revision Proceedings. Each of the Parties further acknowledges that the setting of Tariff rates for the Gathering System is subject to the approval of, and potential modification by, the FERC, from time to time, and each of the Parties hereby agrees not to, directly or indirectly, commence or support any application, motion or other proceeding (a "Tariff Rate Revision Proceeding") before the FERC for the purpose of requesting the FERC to set tariff rates applicable to the Gathering System which are inconsistent with this Agreement. 13.4 Third Party Proceedings. In the event of any Tariff Rate Revision Proceeding being commenced by a third party or by the FERC itself, and in the event of any other proceedings pursuant to which the Tariff rates for the Gathering System may be reviewed by the FERC or other Governmental Authority having jurisdiction, Shipper agrees to support or defend the setting of Tariff rates applicable to the Gathering System that are consistent with this Agreement. In the event of any other proceedings challenging any of the terms of this Agreement being commenced by a third party or by the FERC itself, Shipper agrees to provide all reasonable support and cooperation in defending such terms or otherwise resolving the complaint or other challenge (which may include, without limitation, modifying the terms of this Agreement that are the subject of the challenge) as shall be requested by Gatherer. 13.5 Modification of Agreement. Notwithstanding anything to the contrary set forth herein, it is the intent of the Parties that Gatherer provide the Services to Shipper on a negotiated- contract basis pursuant to the terms and conditions of this Agreement and the Tariff, and the Parties hereby agree that, in the event that FERC or any other Governmental Authority seeks to modify any rates under, or terms or conditions of, this Agreement that would have a greater than de minimis detrimental economic or operational impact on either Party, then: (a) to the maximum extent permitted by Applicable Law, it is the intent of the Parties that the rates and terms and conditions established by FERC or such Governmental Authority having jurisdiction will not alter the rates or terms and conditions set forth in this Agreement, and the Parties shall vigorously defend and support in good faith the enforceability of the rates and terms and conditions of this Agreement; and 27

(b) if FERC or such Governmental Authority modifies the rates or terms and conditions set forth in this Agreement, then the Parties hereby agree to negotiate in good faith to enter into such amendments to this Agreement and or enter into a separate arrangement in order to give effect, to the greatest extent permitted by law, to the rates and other provisions of this Agreement; provided, however, if Gatherer and Shipper cannot arrive at such agreement following such negotiations, either Party may terminate this Agreement by delivering written notice thereof to the other Party, with such termination to be effective ninety (90) Days after the delivery of such notice. ARTICLE XIV COMMON CARRIER AND COMPLIANCE WITH APPLICABLE LAWS 14.1 Common Carrier Pipeline. The Gathering System will be operated as a common carrier pipeline, and Shipper's rights hereunder shall be subject to all laws related to and governing the operation of common carrier pipelines, including, without limitation, laws and regulations that prevent discrimination in favor of any given shipper or the provision of service for consideration other than the rate set forth in a published tariff. The Tariff shall apply to the Services provided hereunder, and if there is a conflict between a provision of this Agreement and the Tariff, the terms and conditions of the Tariff shall control and govern. Gatherer reserves the right to modify or amend the Tariff, in its sole discretion, as it deems necessary in a manner consistent with this Agreement and subject to the terms and conditions of Article XIII. 14.2 Compliance with Laws. Both Parties shall, in carrying out the terms and provisions of this Agreement, abide by all present and future laws of any Governmental Authorities. ARTICLE XV TAXES Gatherer shall not be responsible for or pay, and Shipper hereby agrees to pay and indemnify, defend and hold harmless the Gatherer Indemnified Parties for, any and all Taxes, import duties, license fees or other governmental charges, if any, levied on (i) Shipper Crude Oil tendered under this Agreement, including property Taxes on such Crude Oil in the Gathering System, (ii) the gathering of Shipper Crude Oil, (iii) Tariff rates, surcharges, or any other payment, fee, charge or amount provided for in this Agreement or (iv) the provision of Services hereunder; provided, however, that Shipper shall not be liable hereunder for (x) Taxes (including ad valorem taxes) assessed against Gatherer based on Gatherer’s income, revenues, gross receipts, net worth or ownership of the Gathering System, and (y) state franchise, license and similar Taxes required for the maintenance of Gatherer’s corporate existence. In the event Gatherer is required to pay any Tax for Shipper, Shipper shall reimburse Gatherer for the same per invoice provided by Gatherer. The payment, indemnity, defense and hold harmless obligations set forth in this ARTICLE XV shall survive the termination of this Agreement. ARTICLE XVI ASSIGNMENT 28

This Agreement shall extend to and inure to the benefit of and be binding upon the Parties, and their respective successors and permitted assigns, including any assigns of Shipper’s Interests covered by the Dedication and of any interest of Gatherer in the Gathering System; provided, however, (i) neither Party may assign this Agreement without the prior written consent of the non-assigning Party, such consent not to be unreasonably withheld, conditioned or delayed, (ii) any transfer by Shipper of any of its Interests in the Dedicated Area and any transfer by Gatherer of any of its interest in the Gathering System or this Agreement shall be expressly made subject to the terms and conditions of this Agreement and (iii) if requested by the non- assigning Party, the assigning Party shall not transfer or assign this Agreement or its Interests in the Dedicated Area or Gathering System, as applicable, without first requiring the transferee to execute and deliver to the non-assigning Party an agreement expressly assuming the assigning Party’s obligations under this Agreement and including such other items that need to be addressed in connection with any such transfer or assignment or as may be reasonably requested by the non-assigning Party. Assignment by either Party in compliance with the foregoing requirements shall not relieve such Party of any liabilities, obligations or duties accruing hereunder before the date of such assignment, but shall relieve such Party of any liabilities, obligations or duties accruing hereunder after the date of such assignment. Notwithstanding the foregoing: (a) Shipper may assign its rights and obligations under this Agreement to any Person to whom Shipper assigns or transfers an interest in any of the Interest(s) or Well(s), insofar and only insofar as, this Agreement relates to such Interest(s) or Well(s), without the consent of Gatherer; provided that (i) such Person is at least as creditworthy as Shipper is as of the Effective Date and at the time of such assignment, (ii) such Person assumes in writing the obligations of Shipper under this Agreement insofar as it relates to such Interest(s) or Well(s), and (ii) if such transfer or assignment is to a Person that is not an Affiliate of Shipper, Shipper shall be released from its obligations under this Agreement with respect to such Interest(s) or Well(s) so assigned or transferred, except for its obligations arising prior to the date of assignment. For the avoidance of doubt, (i) no assignee or transferee of Shipper shall assume the Dedication of this Agreement in its entirety, but shall only be subject to, and assume, such Dedication insofar and only insofar as the Interest(s) or Well(s) assigned or transferred to such assignee or transferee and (ii) Gatherer shall not be required to install supplemental meters or other facilities at existing Receipt Points, or undertake additional obligations or incur additional expenses as a result of such assignment (provided the Parties shall reasonably cooperate to establish a procedure for the allocation of Crude Oil delivered at existing Receipt Points between Shipper and such transferee or assignee, if applicable); and (b) either Party may assign (or grant a lien or security interest in) this Agreement to any Person as security in connection with arranging financing for such Party or any Affiliate of such Party or upon enforcement of any such lien or security (and each Party agrees to execute all consents, estoppels, waivers and other documents and instruments reasonable requested by any such Person). Any assignment made in violation of this ARTICLE XVI shall be void ab initio. ARTICLE XVII OFFER 29

17.1 Effect of Unsigned Copy. The submission of an unsigned copy of this Agreement to Shipper shall not constitute an offer. 17.2 Irrevocable Offer by Shipper. Shipper acknowledges that, upon closing of the Open Season, Gatherer will undertake significant work and incur significant expense in connection with the Gathering System. Further, Gatherer may be required to allocate capacity among potential Priority Shippers; provided, however, such allocation shall not limit or otherwise alter Shipper’s MDQ as set forth in this Agreement. In consideration of the foregoing and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged by Shipper, Shipper agrees that the submission of a signed copy of this Agreement by Shipper to Gatherer shall constitute an offer by Shipper that shall be irrevocable. ARTICLE XVIII NOTICES AND STATEMENTS 18.1 Notice. Any notice, statement, payment, claim or other communication required or permitted hereunder shall be in writing and shall be sent by: (i) facsimile transmission; (ii) email, (iii) delivered by hand; (iv) sent by United States mail with all postage fully prepaid; or (v) by courier with charges paid in accordance with the customary arrangements established by such courier, in each of the foregoing cases addressed to the Party at the following addresses: Gatherer: NOTICES AND CORRESPONDENCE: Salt Creek Midstream, LLC 200329 State Highway 249 Floor 4 Houston, TX 77070 Attn: Paul Williams Email: paul.williams@armenergy.com With a copy to: Salt Creek Midstream, LLC 20329 State Highway 249 Floor 4 Houston, TX 77070 Attn: Contract Administration Email: contracts@armenergy.com ACCOUNTING MATTERS: 30

Salt Creek Midstream, LLC 200329 State Highway 249 Floor 4 Houston, TX 77070 Attn: Bryan Fullmer Email: bryan.fullmer@armenergy.com PAYMENTS Bank Name: ABA No.: Account No.: Shipper: NOTICES AND CORRESPONDENCE: Lilis Energy, Inc. 300 E. Sonterra Blvd, Suite 1220 San Antonio, TX 78258 Attention: Accounting and Operations Telephone: 210-999-5400 Facsimile 210-999-5401 With a copy to: RDP Producer Services, LLC 10300n Town Park, Suite SE1000 Houston, TX 77072 Attn: David Lipp Fax: 281-849-8911 Email: dlipp@republicpartnersllc.com ACCOUNTING MATTERS: Lilis Energy, Inc. 300 E. Sonterra Blvd, Suite 1220 San Antonio, TX 78258 Attention: Patrick Tumer Telephone: 817-502-1635 Facsimile: 210-999-5401 Email: AP@Lilisenergy.com PAYMENTS Bank Name: 31

Account Name: Account Number: ABA: Such notices, statements, payments, claims or other communications shall be deemed received as follows: (i) if delivered personally, upon delivery; (ii) if sent by United States mail, whether by express mail, registered mail, certified mail or regular mail, the Day receipt is refused or is confirmed orally or in writing by the receiving Party; (iii) if sent by a courier service, upon delivery; or (iv) if sent by facsimile or email, upon completion of the transmission thereof, except that if such transmission is on any Day other than a Business Day, or on or after 4:00 p.m., Central Clock Time, such notice shall be deemed to be received on the next Business Day. 18.2 Change of Address and Payment Instructions. Notices of change of address or payment instructions of either of the Parties shall be given in writing to the other Party in the manner aforesaid and shall be observed in the giving of all future notices, statements, payments, claims or other communications required or permitted to be given hereunder. ARTICLE XIX DEFAULTS AND REMEDIES 19.1 Shipper Default. The following events shall be a “Shipper Default”: the occurrence and continuation of (i) a breach or default by Shipper of any of its payment obligations under this Agreement or the Tariff, or (ii) a material breach or default by Shipper of any of its obligations under this Agreement or the Tariff, unless such breach or default, or material breach or default, as applicable, occurs as a result of a breach or default by Gatherer of its obligations under this Agreement or the Tariff. 19.2 Remedies on Shipper Default. Upon the occurrence of a Shipper Default, Gatherer may provide written notice to Shipper, describing the Shipper Default in reasonable detail and requiring Shipper to cure the Shipper Default (the “Shipper Default Notice”). If (a) a Shipper Default comprising Shipper’s failure to make any payment due hereunder has not been cured within ten (10) Business Days following receipt by Shipper of a Shipper Default Notice, or (b) a Shipper Default comprising Shipper’s failure to comply with any obligation under this Agreement or the Tariff, other than a payment obligation, has not been cured within thirty (30) Days after receipt by Shipper of a Shipper Default Notice, or, if such failure is not reasonably capable of being cured within a thirty (30) Day period, but Shipper expeditiously commences to cure the same following its receipt of a Shipper Default Notice and diligently proceeds with such cure, within such longer period of time as shall be reasonably necessary to cure such failure, then in any such case, Gatherer may, by written notice to Shipper: (a) inform Shipper of its intention to terminate this Agreement if such Shipper Default is not cured within a further thirty (30) Day period, and if any such Shipper Default has not been cured within such further period of thirty (30) Days, Gatherer may, by written notice to Shipper, terminate this Agreement, any such termination to be effective upon receipt of such termination notice by Shipper; and/or 32

(b) temporarily suspend Shipper's right to be treated as a Priority Shipper for purposes of the prorationing rule of the Tariff until such default is cured. The rights and remedies under this Section 19.2 shall be in addition to all of Gatherer's other rights and remedies under this Agreement or which Gatherer may otherwise have at law, in equity or by statute or regulation, and the exercise of one or more rights or remedies shall not prejudice or impair the concurrent or subsequent exercise by Gatherer of other rights or remedies. 19.3 Gatherer Default. Subject to Section 11.1 hereof, the following events shall be a “Gatherer Default”: the occurrence and continuation of (i) a breach or default by Gatherer of any of its payment obligations under this Agreement or the Tariff, or (ii) a material breach or default by Gatherer of any of its obligations under this Agreement, unless such breach or default, or material breach or default, as applicable, occurs as a result of a breach or default by Shipper of its obligations under this Agreement or the Tariff. 19.4 Remedies on Gatherer Default. Upon the occurrence of a Gatherer Default, Shipper may provide written notice to Gatherer, describing the Gatherer Default in reasonable detail and requiring Gatherer to cure the Gatherer Default (the “Gatherer Default Notice”). If (a) a Gatherer Default comprising Gatherer's failure to make any payment due hereunder has not been cured within ten (10) Business Days following receipt by Gatherer of a Gatherer Default Notice, or (b) a Gatherer Default comprising Gatherer's failure to comply with any obligation under this Agreement or the Tariff, other than a payment obligation, has not been cured within thirty (30) Days after receipt by Gatherer of a Gatherer Default Notice, or, if such failure is not reasonably capable of being cured within a thirty (30) Day period, but Gatherer expeditiously commences to cure the same following its receipt of a Gatherer Default Notice and diligently proceeds with such cure, within such longer period of time as shall be reasonably necessary to cure such failure, then in any such case, Shipper may, by written notice to Gatherer, inform Gatherer of its intention to terminate this Agreement if such Gatherer Default is not cured within a further thirty (30) Day period, and if any such Gatherer Default has not been cured within such further period of thirty (30) Days, Shipper may, by written notice to Gatherer, terminate this Agreement, any such termination to be effective upon receipt of such termination notice by Gatherer. The rights and remedies under this Section 19.4 shall be in addition to all of Shipper’s other rights and remedies under this Agreement or the Tariff or which Shipper may otherwise have at law, in equity or by statute or regulation, and the exercise of one or more rights or remedies shall not prejudice or impair the concurrent or subsequent exercise by Shipper of other rights or remedies. 19.5 Excused Performance. Either Party shall be entitled to suspend performance hereunder in the event: (a) the other Party has voluntarily filed for bankruptcy protection under any chapter of the United States Bankruptcy Code; (b) the other Party is the subject of an involuntary petition of bankruptcy under any chapter of the United States Bankruptcy Code, and such involuntary petition has not been settled or otherwise dismissed within ninety (90) Days of such filing; or 33

(c) the other Party otherwise becomes insolvent, whether by an inability to meet its debts as they come due in the ordinary course of business or because its liabilities exceed its assets on a balance sheet test; and/or however such insolvency may otherwise be evidenced. 19.6 Adequate Assurances. When reasonable grounds for insecurity of payment or performance arise with respect to a Party (the “Impaired Party”), including, without limitation, as a result of the occurrence of a material change in the creditworthiness of the Impaired Party or the Impaired Party’s failure to timely pay any amounts due hereunder other than amounts subject to a good-faith dispute, the other Party (the “Insecure Party”) may demand adequate assurance of performance, and in the absence of the provision of such assurance from the Impaired Party within three (3) Business Days of request, suspend further performance and/or exercise its rights under this Article XIX, including the right to terminate this Agreement. Adequate assurance shall mean security in the form, amount and for the term reasonably specified by the Insecure Party, including, but not limited to, a standby irrevocable letter of credit issued by a financial institution reasonably acceptable to the Insecure Party, a prepayment or a guarantee by an entity deemed creditworthy at the sole discretion of the Insecure Party, advance cash payment or other satisfactory security reasonably acceptable to the Insecure Party. 19.7 Audit. Either Party, upon notice in writing to the other Party, may during normal business hours audit the accounts and records relating to any invoice under this Agreement and the Tariff within the twenty four (24) Month period following the end of the calendar year in which an invoice was rendered; provided, however, that the auditing Party must make a claim in writing upon the other Party for all discrepancies disclosed by said audit within said twenty four (24) Months. Any audit shall be conducted by the auditing Party or its representative at the auditing Party’s expense. Any invoices or settlement statements shall be final as to all Parties unless questioned within said twenty four (24) Months. ARTICLE XX MISCELLANEOUS 20.1 Entire Agreement; Amendments. This Agreement and the Exhibits hereto constitute the entire agreement and understanding between the Parties with respect to the subject matter hereof and thereof, supersede all prior agreements and understandings with respect thereto, and may be amended, restated or supplemented only by written agreement of the Parties. Notwithstanding the foregoing, the Tariff is subject to amendment by Gatherer from time to time subject to Applicable Law (and subject to the limitations of Section 14.1 and Article XIII). 20.2 Governing Law. This Agreement shall be governed and construed in accordance with the laws of the state of Texas without giving effect to the conflict of law rules thereof. 20.3 No Drafting Presumption. No presumption will operate in favor of or against any Party as a result of any responsibility that any Party may have had for drafting this Agreement. Shipper and Gatherer acknowledge and mutually agree that this Agreement and all contents herein were jointly prepared by the Parties. 34

20.4 Waiver. No waiver of any term, provision or condition of this Agreement shall be effective unless in writing signed by the Parties, and no such waiver shall be deemed to be or construed as a further or continuing waiver of any such term, provision or condition or as a waiver of any other term, provision or condition of the Agreement, unless specifically so stated in such written waiver. 20.5 No Third Party Beneficiaries. Except for Persons indemnified hereunder, this Agreement is not for the benefit of any third party and nothing herein, expressed or implied, confers any right or remedy upon any Person not a party hereto. 20.6 No Partnership. It is not the intention of the Parties to create, nor is there created hereby, a partnership, trust, joint venture or association. The status of each Party hereunder is solely that of an independent contractor. 20.7 Confidentiality. (a) Except with respect to the Memorandum and as otherwise set forth herein, each Party agrees that it shall maintain all terms and conditions of this Agreement in strictest confidence, and that it shall not cause or permit disclosure of this Agreement or any provisions contained herein without the express written consent of the other Party. (b) Permitted Disclosures. Notwithstanding Section 20.7(a) of this Agreement, disclosures of any terms and provisions of this Agreement otherwise prohibited may be made by either Party (i) to the extent necessary for such Party to enforce its rights hereunder against the other Party; (ii) to the extent to which a Party is required to disclose all or part of this Agreement by a statute or by the order or rule of a court, agency, or other governmental body exercising jurisdiction over the subject matter hereof, by order, by regulations, or by other compulsory process (including, but not limited to, deposition, subpoena, interrogatory, or request for production of documents); (iii) to the extent required by the applicable regulations of a securities or commodities exchange; (iv) to a third Person in connection with a proposed sale or other transfer of a Party’s interest in this Agreement, provided such third Person agrees in writing to be bound by the terms of this Section 20.7; (v) to its own directors, officers, employees, agents and representatives; (vi) to an Affiliate; or (vii) to a co-working interest owner or royalty owner of Shipper Crude Oil delivered hereunder, provided such co-working interest owner or royalty owner agrees in writing to be bound by the terms of this Section 20.7. (c) Notification. If either Party is or becomes aware of a fact, obligation, or circumstance that has resulted or may result in a disclosure of any of the terms and conditions of this Agreement authorized by Section 20.7(b) (ii), (iii) or (iv) above, it shall so notify in writing the other Party promptly and shall provide documentation or an explanation of such disclosure as soon as it is available. (d) Party Responsibility. Each Party shall be deemed solely responsible and liable for the actions of its directors, officers, employees, agents, representatives and Affiliates for maintaining the confidentiality commitments of this Section 20.7. (e) Public Announcements. The Parties agree that prior to making any public announcement or statement with respect to this Agreement or the transaction represented herein, 35

the Party desiring to make such public announcement or statement shall provide the other Party with a copy of the proposed announcement or statement prior to the intended release date of such announcement. The other Party shall thereafter consult with the Party desiring to make the release, and the Parties shall exercise their reasonable best efforts to (i) agree upon the text of a joint public announcement or statement to be made by both such Parties or (ii) in the case of a statement to be made solely by one Party, obtain approval of the other Party to the text of a public announcement or statement. Nothing contained in this Section 20.7 shall be construed to require either Party to obtain approval of the other Party to disclose information with respect to this Agreement or the transaction represented herein to any Governmental Authority to the extent required by Applicable Law or necessary to comply with disclosure requirements of the Securities and Exchange Commission, New York Stock Exchange, or any other regulated stock exchange. 20.8 Headings. The headings and captions in this Agreement have been inserted for convenience of reference only and shall not define or limit any of the terms and provisions hereof. 20.9 Rules of Construction. In construing this Agreement, the following principles shall be followed: (a) examples shall not be construed to limit, expressly or by implication, the matter they illustrate; (b) the word “includes” and its syntactical variants mean “includes, but is not limited to” and corresponding syntactical variant expressions; (c) the plural shall be deemed to include the singular and vice versa, as applicable; (d) all references in this Agreement to an “Article,” “Section,” “subsection,” or “Exhibit” shall be to an Article, Section, subsection, or Exhibit of this Agreement, unless the context requires otherwise; (e) unless the context otherwise requires, the words “this Agreement,” “hereof,” “hereunder,” “herein,” “hereby,” or words of similar import shall refer to this Agreement as a whole and not to a particular Article, Section, subsection, clause or other subdivision hereof; and (f) each Exhibit to this Agreement is attached hereto and incorporated herein as a part of this Agreement, but if there is any conflict or inconsistency between the main body of this Agreement and any Exhibit, the provisions of the main body of this Agreement shall prevail, except as to any conflicts with the Tariff. 20.10 Survival. Notwithstanding the termination of this Agreement for any reason, (a) ARTICLES VIII, IX, X, XII, XIII, XV, XVIII, XIX and XX shall survive the termination of this Agreement; and (b) each Party to this Agreement will be liable for all of its accrued obligations hereunder up to and including the date on which the termination becomes effective. 36

20.11 Severability. If any provision of this Agreement shall be held to be invalid, illegal or unenforceable, (i) the validity, legality and/or enforceability of the remaining provisions shall not, in any way, be affected or impaired thereby and (ii) in lieu of such invalid, illegal or unenforceable provision, there shall be automatically added to this Agreement a provision as similar to such invalid, illegal or unenforceable provision as may be possible and be legal, valid and enforceable. 20.12 Further Assurances. Each Party shall take such acts and execute and deliver such documents as may be reasonably required to effectuate the purposes of this Agreement. 20.13 Liquidated Damages. The circumstances of this Agreement are such that a Party will be exposed to substantial injury if the other Party does not timely perform under this Agreement, and the injuries that may occur to such Party could take a variety of forms. Where this Agreement imposes on a Party an obligation to pay to the other Party certain monetary sums, or provide other value to the other Party, as a result of certain non-performance or delayed performance under this Agreement, such sums or other value are intended to serve as liquidated damages for certain of the injuries to such other Party. The Parties stipulate and agree that (a) the injury that would be caused to a Party as a result of the other Party’s non-performance or delayed performance would be difficult to estimate accurately, (b) the sums or other value to be provided to such Party under this Agreement in such circumstances are intended to serve as a liquidated damages and not as a penalty, and (c) such sums or other value represent the Parties’ reasonable estimate at this time of the probable damages that would be suffered by a Party in the various scenarios addressed in this Agreement. 20.14 Counterpart Execution. This Agreement may be executed in any number of counterparts, each of which shall be considered an original, and all of which shall be considered one and the same instrument. Neither Party shall be bound until both Parties have executed a counterpart. Facsimile or other electronic copies of signatures shall constitute original signatures for all purposes of this Agreement and any enforcement hereof. [Signature page follows] 37

IN WITNESS WHEREOF, the Parties have executed this Agreement to be effective as of the Effective Date. GATHERER SALT CREEK MIDSTREAM, LLC By: /s/ Michael S. Christopher Name: Michael Christopher Title: Chief Financial Officer SHIPPER LILIS ENERGY, INC. By: /s/ Joseph C. Daches Name: Joseph C. Daches Title: CFO 38

EXHIBIT A DEDICATED AREA TEXAS AND NEW MEXICO Legal Description County Sec. 1, Blk. 75 Winkler Sec. 1, Blk. C-24 Winkler Sec. 10, Blk. 74 Winkler Sec. 10, Blk. C-23 Winkler Sec. 11, Blk. 74 Winkler Sec. 11, Blk. C-23 Winkler Sec. 12, Blk 74 Winkler Sec. 12, Blk. C-23 Winkler Sec. 13, Blk. 74 Winkler Sec. 13, Blk. C-23 Winkler Sec. 14, Blk. 74 Winkler Sec. 14, Blk. C-23 Winkler Sec. 15, Blk. 27 Winkler Sec. 15, Blk. C-17 Reeves Sec. 15, Blk. C-23 Winkler Sec. 16, Blk. C-23 Winkler Sec. 17, Blk. C-23 Winkler Sec. 17, T26S R36E Lea Sec. 18, Blk. C-23 Winkler Sec. 18, T25S R36E Lea Sec. 18, T26S R36E Lea Sec. 19, Blk. C-23 Winkler Sec. 19, Blk. C-25 Loving Sec. 19, T25S R36E Lea Sec. 19, T26S R36E Lea Sec. 2, Blk. C-24 Winkler/Loving Sec. 20, Blk. C-23 Winkler Sec. 20, T26S R36E Lea Sec. 21, Blk. C-23 Winkler Sec. 21, T26S R35E Lea Sec. 22, Blk. 74 Winkler Sec. 22, Blk. C-23 Winkler Sec. 23, Blk. 74 Winkler Sec. 23, Blk. C-17 Reeves Sec. 23, Blk. C-23 Winkler Sec. 24, Blk. 74 Winkler Sec. 24, Blk. C-23 Winkler Sec. 25, Blk. 74 Winkler Sec. 25, Blk. C-23 Winkler Sec. 26, Blk. 74 Winkler Sec. 26, Blk. C-23 Winkler Sec. 27, Blk. 74 Winkler Sec. 27, Blk. C-23 Winkler Sec. 27, T26S R36E Lea Sec. 29, Blk. 74 Winkler Sec. 29, T25S R36E Lea Sec. 3, Blk. C-24 Winkler/Loving

Sec. 30, Blk. 74 Winkler Sec. 30, T25S R36E Lea Sec. 31, Blk. 74 Winkler Sec. 32, Blk. 74 Winkler Sec. 33, Blk. 74 Winkler Sec. 4, Blk. C-24 Winkler/Loving Sec. 5, Blk. 74 Winkler Sec. 6, Blk. 27 Winkler/Loving Sec. 6, Blk. 74 Winkler Sec. 6, T26S R36E Lea Sec. 7, Blk 74 Winkler Sec. 7, Blk. C-23 Winkler Sec. 7, T26S R36E Lea Sec. 8, Blk. 74 Winkler Sec. 8, Blk. C-23 Winkler Sec. 9, Blk. 74 Winkler Sec. 9, Blk. C-23 Winkler The above-described Dedicated Area is depicted in the attached plat.

2 E 2 E 2 E 2 2E 2 E 2 E 2 E 2 E 2 E 2 2 E 2 E 2 2E 2 E 2 E 2 E 2 E 2 E 2 E D E 2 A E Y Y D D D D E 2 E E 2 E 2 2E 2 E 2 E 2 E 2 E 2 E 2 E 22 2 2E 2 E 2 E 2 E 2 E 2 E 2 E 2 E 2 E M C22 C2 C C2 C2 2 2 C2 2 A V N G 2 2 2 2 2 2 2 2 2 \ LILIS_ACREAGE.mxdLilis \ 2 LILIS 2 C2 C2 2 \ Energy Companies 2 E E N E 2 E E N E \ SALT_CREEK Projects \ 2 \ GIS C2 ‘ Miles Document Path: M:

EXHIBIT B INITIAL RECEIPT POINTS; INITIAL DELIVERY POINTS; MDQ; RATES Shipper’s MDQ of 35,000 BPD Priority Rate of $0.75 per Barrel Uncommitted Rate of $0.74 per Barrel Other Charges: Notwithstanding anything to the contrary in the Tariff, Shipper shall not be subject to or obligated to pay any truck loading or unloading charges for any Crude Oil shipments trucked hereunder, regardless of whether trucked by Shipper or Gatherer, that are delivered to truck injection points on the Gathering System that are owned or controlled by Gatherer. Notwithstanding anything to the contrary in the Tariff, Shipper shall not be subject to or obligated to pay any tax, fee or other charges levied against Gatherer in connection with such Crude Oil by any Governmental Authority for the purpose of creating a fund for the prevention, containment, clean up, and/or removal of spills and/or the reimbursement of Persons sustaining a loss therefrom or any program where Gatherer is acting as a collecting agent. Initial Receipt Point(s): Those Receipt Point(s) depicted on Exhibit D. Initial Delivery Points(s): Meter Number Points of Delivery Name County, State Lat/Long TBD Plains All-American, LP Winkler County, TX TBD Pipeline or other pipeline with direct, long-haul transportation to the Midland, Texas area

EXHIBIT C FORM OF MEMORANDUM OF AGREEMENT MEMORANDUM OF AGREEMENT THIS MEMORANDUM OF CRUDE OIL GATHERING AGREEMENT (this “Memorandum”) is made and entered into as of May [ ], 2018 (the “Effective Date”), by and between Salt Creek Midstream, LLC, a Delaware limited liability company (“Gatherer”), and Lilis Energy, Inc., a Nevada corporation (“Shipper”). Shipper and Gatherer may be referred to individually as “Party,” or collectively as the “Parties.” RECITALS: WHEREAS, Shipper and Gatherer have entered into that certain Crude Oil Gathering Agreement dated as of the Effective Date (the “Agreement”), pursuant to which Gatherer will (i) design, engineer and construct the Gathering System to enable Gatherer to provide gathering services for Shipper Crude Oil, and (ii) gather Shipper Crude Oil on the Gathering System, as more particularly described below and in the Agreement; WHEREAS, any capitalized term used but not defined in this Memorandum shall have the meaning given to such term in the Agreement; and WHEREAS, the Parties desire to file this Memorandum of record in the official public records of Loving and Winkler Counties, Texas and Lea County, New Mexico to give notice of the existence of the Agreement and the dedication of Shipper Crude Oil and certain other provisions contained therein. FOR GOOD AND VALUABLE CONSIDERATION, the receipt and sufficiency whereof are hereby acknowledged, the Parties hereby agree as follows: 1. Notice. Notice is hereby given of the existence of the Agreement and certain provisions contained therein, which are summarized in Sections 2 – 4 below. 2. Term: The term of the Agreement shall commence on the Effective Date, and unless sooner terminated as provided herein, shall remain in full force and effect through the twelfth (12th) anniversary of the Effective Date (the “Primary Term”); provided, however, the Agreement shall continue beyond the expiration of the Primary Term for additional terms of one year each (each an “Extended Term,” and, the Primary Term as may be extended by one or more Extended Terms, the “Term”) unless the Agreement is terminated by either Party as of the end of the Primary Term or the then-current Extended Term, as applicable, by providing not less than sixty (60) Days written notice of termination prior to the end of the Primary Term or such Extended Term to the other Party. 3. Dedication. Subject to the terms and conditions of the Agreement and certain exclusions from dedication described in the Agreement, Subject to the other terms and conditions thereof, Shipper hereby (i) dedicates for Services with respect to Shipper Crude Oil under the Agreement to Gatherer all Interests now owned or hereafter acquired by Shipper and/or its Affiliates and 2

their respective successors and assigns that cover lands located within the Dedicated Area, and (ii) dedicates for Services under the Agreement and shall deliver, or cause to be delivered, under the Agreement to Gatherer, at the Receipt Points, the following (the “Dedication,” and the Crude Oil that is the subject of the Dedication being therein referred to as “Shipper Crude Oil”): (a) all Crude Oil produced and saved on or after the Commencement Date for the remainder of the Term from those Wells for which Shipper and/or any of its Affiliates is the operator now or hereafter located within the Dedicated Area (a description of which is attached to Schedule 1) or on lands pooled or unitized therewith, to the extent such Crude Oil is attributable to the Interests within the Dedicated Area now owned or hereafter acquired by Shipper and/or its Affiliates and their respective successors and assigns; and (b) with respect to those Wells for which Shipper and/or any of its Affiliates is the operator, Crude Oil produced on or after the Commencement Date for the remainder of the Term from such Wells which is attributable to the Interests in such Wells owned by other working interest owners and royalty owners which is not taken “in-kind” by such working interest owners and royalty owners and for which Shipper and/or its Affiliates has the right or obligation to deliver such Crude Oil and only for the period that Shipper and/or its Affiliates has such right or obligation. For the avoidance of doubt, Shipper shall not be required to deliver Crude Oil from any well operated by an operator other than Shipper or its Affiliates, including any well where Shipper would be required to install split stream connection facilities or similar facilities to take such Crude Oil in kind, and such Crude Oil shall not be Shipper Crude Oil subject to the Dedication under the Agreement. 4. Covenant Running with the Land. So long as the Agreement is in effect, the Agreement shall (i) be a covenant running with the Interests now owned or hereafter acquired by Shipper and/or its Affiliates within the Dedicated Area (including, without limitation, all Wells operated by Shipper or its Affiliates) and (ii) be binding on and enforceable by Gatherer and its successors and assigns against Shipper, its Affiliates and their respective successors and assigns. Notwithstanding anything in the Agreement to the contrary, to the extent all or a portion of such Interests within the Dedicated Area are sold to a non-Affiliated Person, such acquiring Person shall only be required to dedicate for delivery under the Agreement that Crude Oil that is produced from such Interests within the Dedicated Area acquired by such non-Affiliated Person from Shipper. The acquiring Person shall not be required to dedicate Crude Oil produced from Interests already held by or acquired after such date by such acquiring Person. Notwithstanding the foregoing, with prior written notice to Gatherer, Shipper and its Affiliates shall each be permitted to convey, sell, assign, or otherwise transfer its interest in the Interests that are not connected to or in the process of being connected to the Gathering System free of the Dedication under the Agreement in an “acreage swap” or exchange transaction in which such undeveloped Interests within the Dedicated Area are exchanged for other properties or Interests of approximately equal net acreage and projected production located in the Dedicated Area that are not subject to a Prior Dedication and would become subject to the Dedication. Gatherer and Shipper shall prepare, execute, acknowledge, deliver, and record any such instruments and other documents reasonably necessary to effectuate such release and memorialize such acquired Interests subject to the Dedication. 3

5. No Amendment to Agreement. This Memorandum is executed and recorded solely for the purpose of giving notice and shall not amend nor modify the Agreement in any way. To the extent of a conflict between any provisions of this Memorandum and any provisions of the Agreement, the provisions of the Agreement shall govern and control. 6. Miscellaneous. This Memorandum may be executed in multiple counterparts, each of which, when executed, will be deemed an original, and all of which will constitute but one and the same instrument. Remainder of page intentionally left blank: Signature page follows 4

DULY AUTHORIZED REPRESENTATIVES of the Parties have executed this Memorandum on the dates of their respective acknowledgments below, effective for all purposes as of the Effective Date. GATHERER SALT CREEK MIDSTREAM, LLC By: Name: Title: SHIPPER LILIS ENERGY, INC. By: Name: Title: 5

Acknowledgements STATE OF [ ] § § COUNTY OF [ ] § This instrument was acknowledged before me on day of , 20 , by , of Salt Creek Midstream, LLC, a Delaware limited liability company, on behalf of such limited liability company. Notary Public in and for [ ] Printed or Typed Name of Notary STATE OF [ ] § § COUNTY OF [ ] § This instrument was acknowledged before me on day of , 20 , by , of Lilis Energy, Inc., a Nevada corporation, on behalf of such corporation. Notary Public in and for [ ] Printed or Typed Name of Notary 6

Schedule 1 DEDICATED AREA

EXHIBIT D COMMENCEMENT DATE FACILITIES [ATTACHED]

6 6 6 5 4 2 1 6 5 4 2 1 6 5 4 2 1 6 5 4 2 1 6 5 4 1 15 1 9 1 24 22 21 14 2 25 A25 2 12 1 7 8 5 7 8 9 1 11 12 7 8 9 1 11 12 7 8 9 1 11 12 7 8 9 1 11 12 4 1 7 8 9 11 5 12 Pri e Hog BWZ 11 16 5 4 2 1 6 1 17 2 18 17 16 15 14 1 18 17 16 15 14 1 18 17 16 15 14 1 18 17 16 15 14 1 1 22 9 18 8 17 16 5tate Com 1H 2 8 14 1 6 7 8 9 1 7 11 21 1 15 19 2 25N D R E W 156 19 2 21 22 2 24 19 2 21 22 2 24 19 2 21 22 2 24 19 2 21 22 2 24 1 ● Wi dhogN D BWXR E W 5 255 255 255 255 9 2 21 . 24 A54 17 24 28 255 5tate Com 1H 2 34E 35E 36E 37E 15 14 12 11 ● 18 22 29 38E A15 5 26 21 29 28 27 26 25 29 28 27 26 25 29 28 27 26 25 29 28 27 26 25 25 29 28 27 A41 28 16 26 16 17 18 19 2 A2 22 27 1 2 1 28 6 4 1 2 4 5 6 1 2 4 5 6 1 2 4 5 6 1 2 4 5 6 1 2 29 1 2 29 7 5 25 24 2 22 21 A 54 1 4 4 5 1 6 9 6 5 4 2 1 6 5 4 2 1 L 6 E 5 4 2 1 6 5 4 2 1 6 5 4 2 2 7 1 8 45 T2 5 4 2 1 9 8 7 4 7 7 8 9 1 11 12 7 8 9 1 11 12 7 8 9 1 11 12 7 8 9 1 11 12 7 8 9 6 41 48 5 42 47 5 6 7 8 9 1 8 46 45 6 9 1 18 17 16 15 14 1 18 17 16 15 14 1 18 17 16 15 14 1 18 17 16 15 14 1 1 8 17 16 1 44 4 4 2 8 265 38E 15 14 A51 6 12 11 15 45 T1 265 265 35E 265 36E 265 37E 4 9 7 A57 9 2 14 A 57 16 1 2 24 19 2 21 22 2 24 19 2 21 22 2 21 1 1 17 8 19 2134E 22 2 ● . 24 19 2 21 22 2 24 1 16 17 18 19 2 18 46 7 7 6 18 29 2 19 14 6 28 5 11 2 29 28 27 26 25 29 28 27 26 25 29 28 27 26 25 29 28 27 26 25 21 26 45 TI 25 24 2 22 21 25 12 19 1 1 2 24 14 21 1 2 4 5 6 1 2 4 5 6 1 2 4 5 6 1 2 4 5 6 2 2 22 15 9 2757 1 19 25 5 2 19 7 6 8 8 A57 18 28 2 19 6 14 27 1 12 6 2 1 11 7 15 4 18 1 7 7 A 57 17 22 6 29 28 16 2 18 8 5 5 4 7 46 46 24 6 21 11 4 C22 9 24 2 21 5 4 7 9 1 26 C2 14 5 4 88 25 12 1 16 1 2 Gri 5 26 T1 2 17 8 2 7 17 9 1 .22 11 1 6 27 . 1 2 8 4 22 2 12 24 C 2H 8 1 1 4 12 25 15 77 2 Gri 267 9 16 9 22 17 C24 2 1 19 29 4 C25 4 22 2 1 5 . 16 4 1 11 28 . 18 8 21 . 15 6 . 1H .Lion 7 R . 5 R . 17 14 2 11 . . 15 2 R 4 . 1 42 8 16 G 16 19 G 5 9 1 41 24 8 G 16 1 2 E 18 6 E 12 15 19 E 1 8 17 4 3H 12 15 21 9 . 24 7 N 9 N L 2 Lion . N 7 18 8 14 2 L 11 1 24 18 L 2 1 . I 76 1 I .9 1 21 I 1 26 17 7 6 11 19 K 12 19 2 K 25 6 25 K Hippo 12 22 V V 1 1H 1 6 14 2 V Tiger1 24 11 2 2 2 5 N 1 4 N 9 15 14 25 1 N 19 221 2 5 O 2 O 1 24 4 I 2 O I 11 46 T1S 6 12 5 8 I 6 6 18 18 4 25 74 1 L 21 L . 1 4 14 1 WF L . 46 5 17 2 W 12 Kudu 17 6 26 2 7 W 1H 26 W 2 7 5 6 16 27 1 6 1 16 . 2H .G. Hi5 7 7 2 . 22 . 4 74 TIS 8 15 19 4 12 Kudu 1H 2 . 8 9 15 8 14 2 29 142 19 1H 5 11 24 7 7 24 9 1 21 28 . 4 12 6 1 15 18 2H 25 29. 6 8 11 48 11 22 6 1 9 17 . 5 16 2 5 2 1 21 . 28 Hippo 9 7 .G. Hi 1 2 1 8 14 22 27 1 1 . 12 75 24 4 7 2 26 2 11 11 1 25 4 12 15 16 . Wo e . . 1 16 24 24 . 1H 12 1. 1 17 26 2 5 16 E C1 T 4 22 11 17 2 29 4 1 4 15 1 27 1 6 1 28 7nit 1 . 1 C26 2 18 22 W I N K L E R 5 . 9 14 1 9 W I N K L E R 14 12 18 1 21 25 27 1 8 1 15 46 TIS 7 29 2 8 Bi on 17 21 14 2 26 26 2 7 11 16 25 28 7 15 26 18 18 4 12 19 27 6 1H 12 19 17 29 19 1 16 24 28 6 16 2 1 2 5 17 2 29 4 1 1 6 1 11 27 5 18 22 4 24 21 26 9 5 9 14 6 19 L O V I N G 1 21 25 7 2 2 24 2 8 14 2 8 15 19 22 2 7 15 19 27 26 2 8 7 11 18 21 22 4 12 27 1 9 6 12 17 25 T2 16 24 28 6 21 24 4 48 1 16 26 25 5 11 17 2 29 5 22 27 4 2 1 41 47 14 2 2 22 18 22 4 42 248 2 9 1 21 46 15 5 19 24 1 4 8 14 25 7 45 8 18 1 2 26 25 2 6 19 28 2 8 44 9 17 5 8 16 15 24 27 1 9 4 16 22 21 4 29 2 1 28 6 4 48 41 7 1 4 7 17 29 2 4 2 5 9 6 22 29 4 5 41 47 42 6 5 4 1 7 18 21 42 46 24 1 8 5 25 5 25 2 7 9 14 2 7 45 1 4 26 11 8 2 26 2 8 44 6 12 9 7 15 48 19 27 9 4 2 27 4 1 1 11 I ITIAL RECEIPT P I T 1 2 1 6 ● 28 6 4 28 5 9 14 2 12 48 4 12 29 1 17 29 5 41 47 1 8 19 46 6 5 11 2 7 11 12 14 16 8 4 42 1 18 15 18 WI K TER M I AL 1 6 12 17 24 ■B 7 45 1 9 1 4 17 21 16 12 \ LILIS_Crude_Well_2.mxdLilis 2 \ 2 8 44 2 8 14 1 16 22 1 25 4 1 ■B 5 11 2 4 7 15 2 11 19 SALT CREEK MIDSTREAMC 929 PIPELI E WINK 6 1 15 4 24 2 4 4 48 12 16 24 1 1 9 11 4 9 18 41 47 5 11 17 2 25 1 5 42 46 6 8 14 17 21 9 21 1 14 C627 1 18 5 12 \ Energy Companies LISIS 45 1 21 22 7 15 16 2 1 21 22 51 29 6 2 9 25 16 12 24 2 7 44 2 8 2 14 2 26 17 2 8 6 7 4 7 2 24 71 49 1 5 15 19 27 18 25 9 \ SALT_CREEK 61 4 22 52 4 11 16 24 28 28 5 1 17 6 21 A 91 69 Projects 6 7 1 15 \ 5 9 19 18 8 12 \ GIS 1 2 4 19 27 11 89 5 7 1 21 25 27 7 51 49 2 7 28 F 92 68 16 14 19 26 2 8 9 4 6 1 5 ‘ 27 1 9 29 1 7 47 15 8 1 48 42 15 Miles 48 9 2 16 19 2 28 6 4 5 12 88 54 26 5 41 29 5 7 51 29 9 67 5 5 Document Path: M: 47 4 18 4 42 41 46 47 71 49 2 8 87 74 46 16 11

EXHIBIT E FORM OF NEW RECEIPT POINT NOTIFICATION NEW RECEIPT POINT NOTIFICATION 1. Operator Contact Name 2. Phone Numbers 3. E-Mail 4. Notification Date 5. Receipt Point/New Well 6. County/Township/Range/Section : 7. Expected Date of First Flow/Delivery 8. Projected Volume (Barrels) 9. Receipt Point (location) ’ ” -_ ’ ” 10. Surface site provided by Shipper⁰ or SCM ⁰ 11. Expected Crude Oil composition Attach sample analysis 12. Sulfur Content Expected (Y / N) and quantity (Weight %) 13. Basic Sediment and Water (% of Volume)

SUBMITTED BY SHIPPER: LILIS ENERGY, INC. By: Name: Title: Date: ACKNOWLEDGED BY GATHERER SALT CREEK MIDSTREAM, LLC By: Name: Title: Date:

EXHIBIT F PRO FORMA TARIFF [ATTACHED]

[COGA – EXECUTION] FERC ICA OIL TARIFF F.E.R.C. No. 1.0.0 Salt Creek Midstream, LLC LOCAL TARIFF CONTAINING RULES, REGULATIONS AND RATES GOVERNING THE GATHERING AND TRANSPORTATION OF CRUDE OIL BY PIPELINE Rules and regulations published herein apply only under tariffs making specific reference by number to this tariff; such references will include subsequent reissues hereof. Filed in accordance with 18 CFR 342.2(b) (Establishing initial rates). Issued on [ ( )] days notice under authority of 18 CFR 341.14. This tariff publication is conditionally accepted subject to refund pending a 30 day review period. The provisions published herein will, if effective, not result in an effect on the quality of the human environment. ISSUE DATE: [ ], 2018 EFFECTIVE DATE: [ ], 2018 ISSUED BY: COMPILED BY: [name] [name] [title] [title] Salt Creek Midstream, LLC Salt Creek Midstream, LLC [address] [address] [contact info] [contact info] 1

[COGA – EXECUTION] TABLE OF CONTENTS SECTION I RULES AND REGULATIONS ............................................................................. 3 1. DEFINITIONS ........................................................................................................................... 3 2. COMMODITY ........................................................................................................................... 6 3. QUALITY SPECIFICATIONS .................................................................................................. 6 4. VARIATIONS IN QUALITY AND GRAVITY ....................................................................... 9 5. MINIMUM TENDER ................................................................................................................ 9 6. NOMINATIONS REQUIRED ................................................................................................... 9 7. PRORATIONING PROCEDURES ......................................................................................... 10 8. MEASUREMENT .................................................................................................................... 12 9. RECEIPT FACILITIES ............................................................................................................ 12 10. STORAGE OF CRUDE OIL ................................................................................................. 13 11. DELIVERY FACILITIES ..................................................................................................... 13 12. NOTICE OF ARRIVAL, DELIVERY AT DESTINATION .................................. 13 13. LINE FILL REQUIREMENTS ............................................................................................. 14 14. TITLE ..................................................................................................................................... 16 15. RATES APPLICABLE .......................................................................................................... 16 16. RATES APPLICABLE FROM INTERMEDIATE POINTS .................................. 17 17. PAYMENT OF CHARGES ................................................................................................... 17 18. FINANCIAL ASSURANCES ............................................................................................... 18 19. CHARGE FOR FUND COMPENSATION .......................................................................... 19 20. LIABILITY OF SHIPPER ..................................................................................................... 19 21. LIABILITY OF GATHERER ................................................................................................ 19 22. CLAIMS, SUITS, AND TIME FOR FILING ....................................................................... 20 23. CONNECTIONS .................................................................................................................... 20 24. GATHERER DISCRETION .................................................................................................. 21 25. LOSS ALLOWANCE ............................................................................................................ 21 SECTION II RATES ................................................................................................................. 22 1

[COGA – EXECUTION] SECTION I RULES AND REGULATIONS 1. DEFINITIONS “Affiliate” means any Person that directly or indirectly through one or more intermediaries, controls or is controlled by or is under common control with another Person. The term “control” (including its derivatives and similar terms) means possessing the power to direct or cause the direction of the management and policies of a Person, whether through ownership, by contract, or otherwise. Any Person shall be deemed to be an Affiliate of any specified Person if such Person owns fifty percent (50%) or more of the voting securities of the specified Person, or if the specified Person owns fifty percent (50%) or more of the voting securities of such Person, or if fifty percent (50%) or more of the voting securities of the specified Person and such Person are under common control. “API” means the American Petroleum Institute. “API Gravity” means gravity determined in accordance with the American Society for Testing Materials Designation set out in Item 3(A). “Applicable Law” means all applicable laws, statutes, directives, codes, ordinances, rules, regulations, municipal by-laws, judicial, arbitral, administrative, ministerial, departmental or regulatory judgments, orders, decisions, rulings or awards, consent orders, consent decrees and policies of any Governmental Authority. “ASTM” means the American Society for Testing Materials. “Barrel” means forty-two (42) gallons of 231 cubic inches per gallon at 60 degrees Fahrenheit (60° F) and equilibrium vapor pressure of the liquid. “COGA” means a Crude Oil Gathering Agreement executed by a Priority Shipper with Gatherer with respect to the Gathering System pursuant to the Open Season. “Commencement Date” means the date that the Gathering System commenced initial service. “Committed Volume” means (i) with respect to a Priority Shipper that has committed to deliver a specified volume of Crude Oil to the Gathering System pursuant to such Priority Shipper’s COGA or pay a deficiency payment, such specified volume (expressed in Barrels per day), and (ii) with respect to a Priority Shipper that has not committed to deliver a specified volume of Crude Oil, but has made an acreage dedication pursuant to such Priority Shipper’s COGA, a volume of Crude Oil (expressed in Barrels per day) equal to such Priority Shipper’s Maximum Daily Quantity. “Consignee” means the Person to whom a Shipper has ordered the delivery of Crude Oil. “Consignor” means the Person from whom a Shipper has ordered the receipt of Crude Oil. 2

[COGA – EXECUTION] “Crude Oil” means liquid hydrocarbons that meet the Quality Specifications set forth in Item 3(A). “Delivery Point” means the points of interconnection between the Gathering System and any downstream pipeline as mutually agreed upon by the Parties at which Gatherer will redeliver Shipper Crude Oil for the account of Shipper, as such points are specified in Section II of this tariff. “Encumbered Crude Oil” has the meaning set forth in Item 14(B). “Excess Line Fill” has the meaning set forth in Item 13(B). “Force Majeure” means any cause or causes not reasonably within the control of the Party claiming suspension and which, by the exercise of reasonable diligence, such Party is unable to prevent or overcome, including acts of God, acts of Governmental Authorities, compliance with rules, regulations or orders of any Governmental Authority, strikes, lockouts or other industrial disturbances, acts of the public enemy, acts of terrorism, wars, blockades, insurrections, riots, epidemics, landslides, lightning, earthquakes, fires, extreme cold, storms, hurricanes, floods, or other adverse weather conditions, washouts, arrests and restraint of rulers and people, civil disturbances, explosions, breakage or accident to machinery, equipment or pipelines, freezing of wells, pipelines or equipment, requisitions, directives, diversions, embargoes, priorities or expropriations of government or Governmental Authorities, legal or de facto, whether purporting to act under some constitution, decree, law or otherwise, failure of pipelines or other gatherers to gather or furnish facilities for transportation, failures, disruptions, or breakdowns of machinery or of facilities for production, manufacture, transportation, distribution, processing or consumption (including, but not by way of limitation, the Gathering System), allocation or curtailment by third parties of downstream capacity, inability to secure or delays in securing permits from Governmental Authorities, transportation embargoes or failures or delays in transportation or poor road conditions, partial or entire failure of Crude Oil supply and downstream pipeline market constraints. “Force Majeure” shall expressly exclude (i) delays in permitting that are not extraordinary or unusual for the dedicated area under a COGA and the development of the Permian Basin and other relevant basins, or (ii) any matters within the reasonable control of Gatherer (such as easement, right-of-way, fee land and surface right acquisition, the availability of labor, materials and supplies, and other similar matters). “Gatherer” means Salt Creek Midstream, LLC. “Gathering System” means that portion of Gatherer’s pipeline system, including all appurtenances thereto, related to the provision of gathering and transportation services provided by Gatherer pursuant to this tariff. “Governmental Authority” or “Governmental Authorities” means (i) the United States of America, (ii) any state, county, parish, municipality or other governmental subdivision within the United States of America, and (iii) any court or any governmental department, commission, board, bureau, agency or other instrumentality of the United States of America or of any state, county, municipality or other governmental subdivision within the United States of America. “Guarantee” has the meaning set forth in Item 18(B). 3

[COGA – EXECUTION] “Inaccuracy Period” has the meaning set forth in Item 8(D). “Line Fill” has the meaning set forth in Item 13(A). “Maximum Daily Quantity” shall mean the maximum volume of Crude Oil (expressed in Barrels per day) a Priority Shipper is allowed to deliver to the Gathering System pursuant to such Priority Shipper’s COGA. “Monthly Committed Volume” means the product of (i) the Priority Shipper’s Committed Volume and (ii) the number of days in the applicable month. “Nomination” (including “Nominates” and the syntactical variants thereof) means the written or electronic communication from Shipper to Gatherer, pursuant to and in accordance with this tariff, requesting that Gatherer transport for Shipper in a given month a stated volume of Crude Oil from a specified Receipt Point to the applicable Delivery Point in accordance with the terms of this tariff. “Non-Priority Capacity” means the System Capacity available for allocation to Uncommitted Shippers each Proration Month following the allocation of System Capacity to Priority Shippers under Item 7(C), which shall equal at least ten percent (10%) of the System Capacity, assuming Gatherer receives sufficient Nominations from Uncommitted Shippers. “Notification” has the meaning set forth in Item 13(C)(3). “Off-Spec Crude Oil” has the meaning set forth in Item 3(E). “Open Season” means that open season held by Gatherer to obtain volume commitments and/or acreage dedications on the Gathering System, and any supplemental open season held by Gatherer to obtain additional volume commitments and/or acreage dedications on the Gathering System prior to the commencement of service on the Gathering System. “Party” shall refer to either Shipper or Gatherer, individually, and “Parties” shall refer to Gatherer and Shipper, collectively. “Person” means any individual, corporation, limited liability company, partnership, trust or other entity, or any Governmental Authority. “Priority Rates” means the rates identified as “Priority Rates” in Section II of this tariff. “Priority Service” means that a tender of Crude Oil by a Priority Shipper for transport on the Gathering System not exceeding Shipper’s Maximum Daily Quantity and paying the Priority Rate for levels of applicable service on the Gathering System, shall be entitled to the highest level of service on the Gathering System and not be subject to prorationing to accommodate nominations of uncommitted volumes for transport on the Gathering System or nominations of volumes for transport on the Gathering System by Shippers who do not elect to pay (or are not eligible thereunder) the Priority Rate for such nominations. “Priority Shipper” means a Shipper with which Gatherer has executed a COGA for Priority Service on the Gathering System pursuant to the open season(s) held by Gatherer and such 4

[COGA – EXECUTION] COGA provides for a term of at least ten (10) years and either (i) a commitment to deliver a specified volume of Crude Oil on the Gathering System of at least 2,000 Barrels per day, or (ii) with respect to a Priority Shipper that has not committed to deliver a specified volume of Crude Oil, but has made an acreage dedication pursuant to such Priority Shipper’s COGA, an acreage dedication covering at least 2,000 net acres of lands located in Winkler County, Texas, Loving County, Texas and/or Eddy and Lea Counties, New Mexico. “Prime Rate” has the meaning set forth in Item 17(C). “Proration Month” means the month for which capacity is to be allocated under Item 7. “Qualified Institution” means the domestic office of a commercial bank or trust company that is not an Affiliate of Shipper and that has assets of at least $10 billion and an investment-grade credit rating as established by Standard and Poor’s and Moody’s. “Quality Specifications” has the meaning set forth in Item 3(A). “Receipt Point” means the receipt/inception point(s) where Crude Oil is received into the Gathering System, as such points are specified in Section II of this tariff. “Shipper” means a party that contracts with Gatherer for transportation of Crude Oil in accordance with this tariff and any other applicable tariffs of Gatherer. “Shipper’s Permitted Liens” means (i) any liens, security interests or other encumbrances benefiting one or more lenders to Shipper as part of a financing provided by such lenders to Shipper for which such lenders have not taken actions to foreclose on such liens; and (ii) normal and customary liens under financing agreements, operating agreements, unitization agreements, pooling orders, drilling contracts and similar agreements for upstream operators and mechanic's and materialman's liens, tax liens or mineral liens related to claims or obligations that are not delinquent or that are being contested in good faith and by appropriate proceedings. “System Capacity” means the operational capacity of the Gathering System at any applicable point in time. “Tender” or “Tendered” means delivery by Shipper to Gatherer of a stated quantity of Crude Oil for transportation from a specified Receipt Point to a specified Delivery Point on the Gathering System in accordance with this tariff. “Uncommitted Rates” means the rates identified as “Uncommitted Rates” in Section II of this tariff. “Uncommitted Shipper” means a Shipper that is not a Priority Shipper. “Unremoved Crude Oil” means Crude Oil that Shipper fails to arrange for receipt of, or refuses to receive, upon Gatherer’s delivery at the Nominated Delivery Point. 5

[COGA – EXECUTION] 2. COMMODITY Gatherer is engaged in the transportation on the Gathering System of Crude Oil meeting the Quality Specifications set forth in Item 3 and will not accept any other commodity for transportation under this tariff. 3. QUALITY SPECIFICATIONS A. The quality specifications for Crude Oil set forth below (“Quality Specifications”) shall apply to Shipper’s Tender. Shipper shall not deliver to Gatherer and Gatherer shall not be obligated to accept Crude Oil that, as determined by Gatherer, has on receipt qualities which are outside of the minimum and maximum ranges specified in the following table: Quality Units Min Max Reference Test Method API Gravity (60F) deg. API 36 44 ASTM D287 AND API MPMS CHAPTER 9 Sulfur Content Weight % < 0.4 ASTM D4294 Reid Vapor Pressure PSIA 9.5 ASTM D6377 True Vapor Pressure PSIA 11.0 ASTM D6377 Basic Sediment and % of Volume < 1.0% API MPMS Water CHAPTER 10.4 B. Gatherer shall have the right to change or modify the Quality Specifications provided in Item 3(A) in order to conform Gatherer’s Quality Specifications to those of downstream connecting facilities. C. Shipper shall perform applicable tests to ensure that the Crude Oil it Tenders to Gatherer for transportation on the Gathering System conforms to the Quality Specifications. Gatherer may also require Shipper to furnish a certificate setting forth in detail the specifications of each shipment of Crude Oil offered for transportation hereunder, and Shipper shall be liable for any contamination or damage to other Crude Oil in Gatherer’s custody or to the Gathering System or other facilities caused by failure of the Crude Oil Tendered by Shipper to meet the specifications stated in Shipper’s certification. D. Gatherer or its representative may test all Crude Oil Tendered for transportation on the Gathering System for compliance with the Quality Specifications. All such tests shall be performed by Gatherer, but Shipper, Consignor, or Consignee may 6

[COGA – EXECUTION] be present or represented at the testing provided such witnessing does not unreasonably interfere with Gatherer’s operation of the Gathering System. Gatherer shall provide reasonable advance notice of any such testing (other than the continuous monitoring of the Gathering System) to Shipper. Quantities shall be tested in accordance with applicable API/ASTM standards and pipeline industry practice or such other tests as may be agreed upon by Gatherer and Shipper. All tests performed by Gatherer shall be determinative unless Shipper, Consignor, or Consignee submits to Gatherer, within sixty (60) days of the date of the test, appropriate documentation contesting the test. In the event of variance between Gatherer’s test results and Shipper’s test results or the specifications contained in a certificate provided by Shipper pursuant to Item 3(C), Gatherer’ test results shall prevail (absent error demonstrated by Shipper or fraud). E. Gatherer reserves the right to reject all Tenders of Crude Oil and refuse transportation if Gatherer determines that Shipper has delivered Crude Oil that (i) does not conform to the Quality Specifications, (ii) is not merchantable, (iii) is not readily acceptable for transportation through the Gathering System, (iv) would otherwise adversely affect the Gathering System or other Crude Oil on the Gathering System, (v) would make other Crude Oil on the Gathering System undeliverable at the Delivery Point(s) and/or (vi) would expose any Person or property (including the Gathering System) to an undue risk of harm or property damage (“Off-Spec Crude Oil”), all of which shall be determined by Gatherer, in Gatherer’s reasonable discretion. F. In the event Shipper Tenders Off-Spec Crude Oil to the Gathering System: (i) Gatherer may accept such Shipper’s delivery if Gatherer determines, in its sole discretion, that the quality of the Off-Spec Crude Oil, when commingled as a common stream, will nonetheless meet the Quality Specifications; provided, however, that Gatherer shall not knowingly accept Shipper's delivery of Off-Spec Crude Oil (a) if Gatherer determines that the quality of Off-Spec Crude Oil when commingled as a common stream, would not meet the Quality Specifications or (b) if the common stream is not meeting the Quality Specifications; and (ii) if Gatherer does not accept such Off-Spec Crude Oil as provided in (i) of this Item 3(F), Gatherer may exclude such Shipper with respect to such Off-Spec Crude Oil from further entry into the Gathering System until such time as Shipper returns the quality of its Off-Spec Crude Oil to a level satisfactory to Gatherer in accordance with this tariff. Nothing contained in this tariff, any other tariff filing, any pipeage contract or transportation services agreement or any other document, nor any receipt by Gatherer of Off-Spec Crude Oil (either unknowingly, as a temporary accommodation, or in its sole discretion), shall be construed to affect the Gatherer’s right, at any time and from time to time, to reject Tenders of Off- Spec Crude Oil and to refuse or suspend receipt of such Off-Spec Crude Oil until it is established to such Gatherer’s reasonable satisfaction that subsequent deliveries of Crude Oil will conform to the applicable Quality Specifications. During any period when Gatherer is knowingly accepting Off-Spec Crude Oil, Gatherer shall (x) regularly monitor the API Gravity of the Off-Spec Crude Oil at all Receipt Points from which Off-Spec Crude Oil is knowingly accepted by 7

[COGA – EXECUTION] Gatherer, and (y) manage the cumulative volume of Off-Spec Crude Oil so accepted to reduce the likelihood of the common stream failing to meet the Quality Specifications. G. Gatherer may monitor, but is not responsible for monitoring, receipts or deliveries for contaminants. Further, Gatherer reserves the right to dispose of any Off-Spec Crude Oil (other than such Crude Oil accepted pursuant to Item 3(F)(i)) blocking the Gathering System. Disposal thereof may be made in any reasonable manner, including, but not limited to, commercial sales. Shipper shall be liable for and shall defend, indemnify and hold Gatherer harmless from and against any and all claims, actions, suits, losses, demands, costs and expenses (including attorney’s fees and costs of repairing, inspecting, cleaning and decontaminating the Gathering System or the facilities of third parties) of every kind, nature or description to the extent caused by Off-Spec Crude Oil (other than such Crude Oil accepted pursuant to Item 3(F)(i)) that Shipper has delivered into the Gathering System. H. In addition to any other remedies available to Gatherer, if Crude Oil received by Gatherer into the Gathering System does not meet the Quality Specifications (other than such Crude Oil accepted pursuant to Item 3(F)(i)), Gatherer reserves the right to charge the Shipper the actual costs and expenses incurred by Gatherer to treat, handle, or otherwise dispose of all such Off-Spec Crude Oil so received; provided, however, Shipper shall not be subject to any such costs and expenses to the extent that the treatment of such Crude Oil and the costs related thereto are addressed pursuant to a COGA. In the event that, based upon Gatherer’s own testing, it is determined that Shippers are or have been delivering Crude Oil into the Gathering System at the Receipt Point that does not meet the Quality Specifications, then (i) Gatherer may add an off-spec penalty provision to this tariff in order to discourage deliveries of Crude Oil to the Gathering System that violate the Quality Specifications and (ii) for the avoidance of doubt, any Shipper who has delivered Off-Spec Crude Oil that, when commingled as a common stream, results in the common stream not meeting the Quality Specifications, shall be liable for damages caused to other Shippers’ Crude Oil to the extent that such Shipper’s delivery of Off-Spec Crude Oil results in other Shippers receiving Crude Oil that does not meet the Quality Specifications (other than such Crude Oil accepted pursuant to Item 3(F)(i)). I. As set forth in Item 3(G), Shipper shall not be liable for any claims or losses or other damages caused by or resulting from Crude Oil accepted pursuant to Item 3(F)(i), and Gatherer hereby waives its claims against Shipper with respect to any such claims or losses or other damages. 4. VARIATIONS IN QUALITY AND GRAVITY A. Gatherer shall not be liable to Shipper for changes in gravity or quality of Shipper’s Crude Oil which may occur from commingling or intermixing Shipper’s Crude Oil with Crude Oil from other Shippers in the same common stream while in transit except to the extent that such commingling or intermixing 8

[COGA – EXECUTION] would render Shipper’s Crude Oil to be Off-Spec Crude Oil or undeliverable as a result of Off-Spec Crude Oil received from other Shippers. Gatherer is not obligated to deliver to Shipper the identical Crude Oil Nominated and Tendered by Shipper; Gatherer will deliver the grade of Crude Oil it is regularly transporting as a common stream. B. Except as provided in Item 4(A), Gatherer shall have no responsibility in, or for, any revaluation or settlements which may be deemed appropriate by Shippers and/or Consignees because of mixing or commingling of Crude Oil shipments between the receipt and delivery of such shipments by Gatherer within the same common stream. C. Gatherer shall not be required to transport Crude Oil except with reasonable diligence, considering the quality of the Crude Oil, the distance of transportation and other material elements. Gatherer cannot commit to delivering Crude Oil to a particular destination, at a particular time. 5. MINIMUM TENDER Gatherer may impose minimum Tender requirements to the extent reasonably necessary for the efficient operation of the Gathering System. 6. NOMINATIONS REQUIRED A. Crude Oil for shipment through the Gathering System will be received only on a properly executed Nomination from Shipper identifying the month for which transportation is desired, the Receipt Point at which the Crude Oil is to be received by Gatherer, the Delivery Point of the shipment, Consignee (if any), and the amount of Crude Oil to be transported. Gatherer may refuse to accept Crude Oil for transportation unless satisfactory evidence is furnished that Shipper or Consignor has made adequate provisions for prompt receipt of all volumes at the Delivery Point. B. Any Shipper desiring to Nominate Crude Oil for transportation shall make such Nomination to Gatherer in writing on or before the twentieth (20th) day of the calendar month, before 12:00 a.m. Central Time, preceding the month during which the transportation of Crude Oil under the Nomination is to begin; provided, however, that if operating conditions permit, Gatherer, in its sole discretion, may consider and accept Nominations submitted after the date specified above. C. Gatherer may refuse to accept Crude Oil for transportation under this tariff (i) where Shipper, Consignor, or Consignee is (1) not in compliance with this tariff or (2) in breach of a COGA, as applicable, or (ii) where Shipper, Consignor, and/or Consignee is not in material compliance with all Applicable Law regulating shipments of Crude Oil. D. All Crude Oil accepted for transportation will be transported at such time and in such quantity as scheduled by Gatherer. 9

[COGA – EXECUTION] 7. PRORATIONING PROCEDURES A. When System Capacity will be prorated. When Gatherer receives more Nominations in a month for transportation of Crude Oil on the Gathering System than Gatherer is able to transport, Gatherer shall allocate the System Capacity under the provisions of this Item 7. B. Division of System Capacity between Shipper classes. System Capacity will be allocated among Priority Shippers as a class and Uncommitted Shippers as a class; any remaining System Capacity will be allocated in accordance with the provisions of Item 7(E). C. Allocation to Priority Shippers. (1) Except as provided in Item 7(C)(2), Gatherer shall allocate each Priority Shipper an amount of System Capacity equal to the lesser of the Priority Shipper’s Nomination for the Proration Month or its Monthly Committed Volume. If a Priority Shipper Nominates volumes in excess of its Monthly Committed Volume, then the excess incremental volumes shall be subject to prorationing under Item 7(E) below. (2) If an event of Force Majeure or other operational issue causes System Capacity to be reduced for the Proration Month, the allocation of System Capacity to each Priority Shipper under this Item 7(C) shall be reduced by the same percentage as the reduction in System Capacity that is caused by the Force Majeure event or operational issue. If an event of Force Majeure or other operational issue causes a service disruption on only a portion of the Gathering System or at a particular Receipt Point or Delivery Point, Gatherer shall continue to provide full operational service with respect to the unaffected portions of the Gathering System and to the unaffected Receipt Points and Delivery Points. Gatherer will reduce the allocations of System Capacity to each Priority Shipper affected by such Force Majeure event by the same percentage as the reduction in capacity of the affected portion of the Gathering System or the reduction in receipt or delivery capability of the affected Receipt Point or Delivery Point, respectively and as applicable. Pursuant to the terms of a Priority Shipper’s COGA, Gatherer may temporarily suspend such Shipper’s right to be treated as a Priority Shipper for purposes of this Item 7 during the occurrence of a default of the COGA by such Shipper. D. Allocation to Uncommitted Shippers. (1) Following the allocation of System Capacity set forth in Item 7(C) above, Gatherer shall next allocate the Non-Priority Capacity on the Gathering System among all Uncommitted Shippers in the following manner: i. Each Uncommitted Shipper shall be allocated an amount of System Capacity in the Proration Month that is equal to: 10

[COGA – EXECUTION] a. its Nomination, if the total volume Nominated by all Uncommitted Shippers is less than or equal to ten percent (10%) of System Capacity on the Gathering System; or b. its pro rata share, in accordance with its Nomination, of ten percent (10%) of the System Capacity on the Gathering System, if the total volume Nominated by all Uncommitted Shippers is greater than ten percent (10%) of such System Capacity. E. Remaining System Capacity. Any remaining System Capacity not allocated through the application of Items 7(C) or 7(D) shall be allocated first, pro rata, among all Priority Shippers having remaining unmet Nominations according to the level of each Priority Shipper’s Monthly Committed Volume. If allocation to any Shipper pursuant to this Item 7(E) exceeds such Shipper’s remaining Nomination or there remains unallocated System Capacity following this additional allocation to Priority Shippers, then the excess volume will be allocated among all other Shippers having unmet Nominations until the remaining System Capacity is fully allocated or all of the remaining Nominations have been fulfilled. F. Basis for Allocation; Notification. When prorationing of System Capacity is in effect: (1) Gatherer shall allocate System Capacity on a monthly basis; and (2) Gatherer will use reasonable efforts to notify each Shipper of its allocation not later than the first working day of the Proration Month. G. Reallocation of Unused Allocated System Capacity. If a Shipper does not use the portion of System Capacity allocated to it under this Item 7 at the times and in the amounts designated by Gatherer, Gatherer shall have the right to use Shipper’s unused portion of System Capacity to fulfill the unmet Nominations of other Shippers, but only to the extent and duration of Shipper’s under-utilization of its capacity, without impacting the payment obligations of Shipper or any other obligations of Shipper, or otherwise crediting or paying Shipper in any manner. Nothing in this Item 7(G) shall operate to reduce or otherwise alter Shipper’s Maximum Daily Quantity. H. Failure of Uncommitted Shipper to Use Allocated System Capacity. (1) Except as provided in Item 7(H)(2) below, an Uncommitted Shipper that fails to use all of its allocated System Capacity during a Proration Month shall have its allocation of System Capacity reduced in each subsequent Proration Month until the total reductions equal the amount of the deficiency. The amount of any such reduction shall be treated as unused allocated System Capacity and shall be reallocated among other Shippers in accordance with Item 7(G). 11

[COGA – EXECUTION] (2) Reduction of an Uncommitted Shipper’s allocation for failure to use its allocated System Capacity during a Proration Month may be waived, in whole or in part, if Gatherer determines that Shipper’s failure to use all or some of its allocated System Capacity was due to a Force Majeure. I. Transfer of Allocated System Capacity; Use of Affiliates. Except as provided in this Item 7(I), capacity allocated to a Shipper under this Item 7 may not be assigned, conveyed, loaned, transferred to, or used in any manner by another Shipper; provided, however, that a Shipper’s allocation of capacity may be transferred as an incident of the bona fide sale of the Shipper’s business or to a successor to the Shipper’s business by the operation of law, such as an executor or trustee in bankruptcy. 8. MEASUREMENT Crude Oil delivered hereunder shall be measured by in accordance with Gatherer’s [Measurement Policy], dated [ ], 2018. A copy of the [Measurement Policy] is available on Gatherer’s website at [ ]. 9. RECEIPT FACILITIES Gatherer will receive Crude Oil from Shippers at the Receipt Points on the Gathering System. Crude Oil will be received only from pipelines, tanks or other facilities that are provided by Shipper or Consignor, or a connecting carrier. Gatherer will not accept a Nomination unless such facilities have been provided and conform to the operating requirements of Gatherer, in Gatherer’s sole discretion. 10. STORAGE OF CRUDE OIL Gatherer does not provide storage for Crude Oil, except storage incidental to transportation on the Gathering System. Gatherer has the right to coordinate with downstream connecting facilities to ensure that Shipper has arranged for receipt of its Crude Oil at the Nominated Delivery Point; by Nominating Crude Oil for transportation on the Gathering System, Shipper agrees to permit such coordination. 11. DELIVERY FACILITIES Gatherer will accept Crude Oil for transportation only when Shipper or Consignee has provided the necessary facilities for taking delivery of the shipment as it arrives at the Delivery Point. Gatherer will not accept a Nomination unless such facilities have been provided and conform to the operating requirements of Gatherer, in Gatherer’s reasonable discretion. The cost of such facilities shall be provided at the sole cost of Shipper, except as otherwise provided for in a COGA. 12. NOTICE OF ARRIVAL, DELIVERY AT DESTINATION A. After a shipment of Crude Oil has had time to arrive at Shipper’s Nominated Delivery Point and on twenty-four (24) hours’ notice to Shipper or Consignee, 12

[COGA – EXECUTION] Gatherer may begin delivery of such Crude Oil to Shipper or Consignee at Gatherer’s current rate of pumping. Shipper shall timely remove its Crude Oil, or cause such Crude Oil to be removed, from the Gathering System following transportation to a Nominated Delivery Point. If Shipper or Consignee is unable or refuses to receive said shipment, Gatherer will assess a demurrage charge of 1.25 cents ($0.0125) per Barrel for each day (or fractional part thereof) commencing twenty-four (24) hours following Gatherer’s notification described above and Shipper’s failure to promptly accept such Crude Oil. In addition to such demurrage charge, Gatherer shall also have the right to curtail the amount of Crude Oil it will accept from Shipper until such Unremoved Crude Oil is removed. B. In addition to such demurrage charge, Gatherer also reserves the right if deemed necessary to clear the Gathering System, provided that the notices set out in Item 12(A) have been given, to make whatever arrangements for disposition of the Unremoved Crude Oil that are appropriate, which includes selling the Unremoved Crude Oil at a private sale for the best price reasonably obtainable. Gatherer may be a purchaser at such sale. The proceeds of any sale shall be applied in the following order: (i) to the reasonable expenses of holding, preparing for sale, selling, and transporting the Crude Oil, and to the extent allowed by Applicable Law reasonable attorneys’ fees and legal expenses incurred by Gatherer; and (ii) to the satisfaction of Shipper’s indebtedness including interest herein provided from the date payment is due. The balance of the proceeds of the sale remaining, if any, shall be paid to Shipper or, if there is a dispute or claim as to entitlement, held for whoever may be lawfully entitled thereto. Gatherer will have a claim for and against Shipper with respect to any deficiency arising from the debt due to Gatherer from Shipper and the proceeds of any sale after reduction as set forth above. Shipper shall indemnify Gatherer for all losses associated with Unremoved Crude Oil and Gatherer’s disposition of the Unremoved Crude Oil. Gatherer shall have no liability to Shipper associated with Shipper’s Unremoved Crude Oil or Gatherer’s disposition of Unremoved Crude Oil except as set forth herein. 13. LINE FILL REQUIREMENTS A. Gatherer shall require Shipper to supply, and Shipper shall supply, Crude Oil constituting its proportionate share of Crude Oil for line fill necessary for operation of the Gathering System (“Line Fill”). For purposes of clarity, a Priority Shipper’s proportionate share of Line Fill shall be the percentage equal to Priority Shipper’s Committed Volume divided by ninety percent (90%) of the total System Capacity at such time. B. In the event a Shipper’s Line Fill balance drops below its proportionate share of the volume of Crude Oil necessary for operation of the Gathering System, Gatherer will notify Shipper of the amount of Line Fill that Shipper owes and Shipper shall supply such Line Fill to Gatherer before Gatherer is obligated to accept Shipper’s Nominations or Tenders or make deliveries or shipments on 13

[COGA – EXECUTION] behalf of Shipper. Any notice to Shipper of additional Line Fill requirements under this Item 13(B) shall provide adequate time for Shipper to make the required Nominations under Item 6. Subject to the provisions of Item 17, in the event Shipper’s Line Fill balance is above its proportionate share of the volume of Crude Oil necessary for Line Fill (“Excess Line Fill”), then Gatherer shall notify Shipper of such Excess Line Fill amount and will return such Excess Line Fill to Shipper upon written request by Shipper to Gatherer and following a reasonable period of time to allow for administrative and operational requirements associated with the withdrawal of such Excess Line Fill. C. Subject to the provisions of Item 17, Line Fill furnished by Shipper may be withdrawn from the Gathering System under two circumstances (i) if Shipper intends to discontinue shipments on the Gathering System for the foreseeable future and/or, (ii) if Shipper is “no longer shipping” on the Gathering System, as described in Item 13(C)(2) below. Line Fill furnished by a Shipper may be withdrawn from the Gathering System only pursuant to the terms of this Item 13(C). (1) If Shipper intends to discontinue shipments on the Gathering System for the foreseeable future, Shipper shall provide written notification to Gatherer that it intends to discontinue shipments on the Gathering System. Gatherer will then provide written notice to Shipper as provided for in Item 13(C)(3). (2) A Shipper that makes no shipments on the Gathering System over a continuous six (6)-month period shall be deemed to be “no longer shipping.” When Gatherer identifies that a Shipper is “no longer shipping,” Gatherer will provide written notice to Shipper that it is considered to be “no longer shipping” on the Gathering System as provided for in Item 13(C)(3). (3) Gatherer will issue written notice (the “Notification”) to Shipper that according to the Gatherer’s books, Gatherer is holding a certain volume of Crude Oil on its books in Shipper’s name. Shipper will be advised in such letter that Shipper will have thirty (30) days effective with the date of the Notification to provide written direction regarding the disposal of Shipper’s Crude Oil. If at the end of this thirty (30)-day period, Gatherer has received no written direction, Gatherer will assume title to the Crude Oil being held on its books in Shipper’s name, free and clear of any and all liens, claims or encumbrances, and Shipper expressly agrees and consents to transfer title to Gatherer as set forth herein. (i) If Gatherer has been contacted by Shipper within thirty (30) days of the Notification described in Item 13(C)(3), Gatherer will grant Shipper an additional thirty (30) days without charge to facilitate the disposal of Shipper’s inventory Crude Oil. If at the end of this 60-day period, Shipper has not disposed of this Crude Oil, 14

[COGA – EXECUTION] Gatherer retains the right to charge a liquidated damage fee of $0.10 per Barrel, per month, retroactive to the date of the Notification, plus any other fees as allowed in accordance with this tariff; such fees will be required to be paid before the Crude Oil will be released. In addition, if Shipper has not disposed of such Crude Oil within sixty (60) days from the date of Notification, Gatherer will assume title to such Crude Oil free and clear of any and all liens, claims or encumbrances, and Shipper expressly agrees and consents to transfer title to Gatherer as set forth herein. If Shipper provides a written request to Gatherer after title to Crude Oil has been assumed by Gatherer but before Gatherer has otherwise disposed of Crude Oil, Gatherer agrees to transfer title back to Shipper for a fee of $5.00 per Barrel. Such fees will be required to be paid before the Crude Oil will be released. Upon transfer of title back to Shipper, Shipper will then be responsible for disposing of Crude Oil within thirty (30) days therefrom. Failure of Shipper to dispose of said Crude Oil within thirty (30) days of the transfer of title back to Shipper will result in title being vested back in Gatherer without recourse. (4) Gatherer’s return of Line Fill is contingent upon Shipper’s inventory balances and all outstanding amounts due having been reconciled between Shipper and Gatherer and Shipper having paid in full any amounts owed to Gatherer following such reconciliation. Gatherer shall have a reasonable period of time to complete administrative and operational requirements incident to Shipper’s withdrawal of Line Fill. (5) Subpart (C) of this Item 13 shall not apply to a Priority Shipper during the term of such Priority Shipper’s COGA. However, following the expiration of a Priority Shipper’s COGA, such Priority Shipper’s Line Fill shall be returned to Priority Shipper pursuant to the provisions set forth in subpart (C) of this Item 13. 14. TITLE A. Gatherer may require of Shipper satisfactory evidence of its perfected and unencumbered title (other than Shipper’s Permitted Liens) of any Crude Oil Tendered for shipment on the Gathering System. Gatherer shall have the right to reject any Crude Oil, when Tendered for transportation, that constitutes Encumbered Crude Oil (as defined below). B. At the time of Nomination, Shipper shall inform Gatherer if any Crude Oil Nominated and/or to be Tendered to Gatherer for transportation (i) may be involved in litigation, (ii) may be subject to a title dispute, or (iii) may be encumbered by a lien or charge of any kind at the time of delivery of such Crude Oil to Gatherer at a Receipt Point (other than any Shipper’s Permitted Liens and the lien created hereunder in favor of Gatherer) (“Encumbered Crude Oil”). In the event Gatherer receives such Shipper notice of Encumbered Crude Oil or 15

[COGA – EXECUTION] otherwise learns that Shipper has or will Nominate or Tender Encumbered Crude Oil, Gatherer, in its reasonable discretion, may require Shipper to provide one or more of the following: (i) satisfactory evidence of its perfected and unencumbered title, (ii) satisfactory indemnity bond to protect Gatherer against any and all loss, (iii) pre-payment of transportation charges, or (iv) subordination agreement from the applicable lienholder. Gatherer also has the right to refuse any shipment of Encumbered Crude Oil. C. By Nominating Crude Oil, Shipper warrants and guarantees that Shipper has good title (or right to ship or control) thereto and agrees to hold Gatherer harmless for any and all loss, cost, liability, damage and/or expense resulting from failure of title (or right to ship or control) thereto; provided that acceptance for transportation shall not be deemed a representation by Gatherer as to title (or right to ship or control). Shipper shall not cause or permit any lien, security interest or other form of burden to be filed or created with respect to Crude Oil in Gatherer’s possession, except for any Shipper’s Permitted Liens and the lien created hereunder in favor of Gatherer. 15. RATES APPLICABLE Crude Oil accepted for transportation shall be subject to the rates and charges in effect on the date of receipt by Gatherer that are applicable to Shipper’s shipments, irrespective of the date of the Nomination. The applicable rates are set forth in Section II herein. Transportation and all other lawful charges shall be collected on the basis of the quantities of Crude Oil delivered to Delivery Points, and said quantities will be determined in the manner provided in Item 8. The terms of a COGA shall govern the rights of a Priority Shipper and Gatherer with respect to the payment or nonpayment of any deficiency payments and/or other charges set forth in a COGA. In the event Gatherer refuses to accept Barrels of Crude Oil Tendered by a Priority Shipper for transportation under this tariff or a COGA because such Shipper has been (i) in violation of this tariff, or (ii) in material breach of a COGA at the time the Barrels are Tendered to Gatherer, then no reduction shall be made to a deficiency payment if, as a result of such refusal, such Priority Shipper fails to ship its Monthly Committed Volume for such month. 16. RATES APPLICABLE FROM INTERMEDIATE POINTS Shipments accepted for transportation from or to any point on the Gathering System not named in this tariff, but which is intermediate to a point where rates are published, will be assessed the rate in effect from or to the next more distant point published in this tariff. Continuous use of intermediate point rate application under this Item 16 for more than thirty (30) days requires establishment of a rate for the transportation service. 17. PAYMENT OF CHARGES A. Gatherer will invoice Shipper for transportation rates, fees, and charges, and any other amounts accruing on Crude Oil transported by Gatherer within twenty (20) days of the end of each month. Gatherer shall calculate and assess any payments 16

[COGA – EXECUTION] Shipper owes to Gatherer under a COGA, including but not limited to any deficiency payments, in accordance with the provisions of the COGA. B. All payments are due by the later of (i) the twenty-fifth (25th) day of the month in which the invoice is received or (ii) fifteen (15) days from the date of Shipper’s receipt of the invoice. Invoices falling due on a weekend or holiday need not be paid until the following regular workday and no interest shall accrue under Item 17(C) until after such regular workday. If Shipper, in good faith, disputes the amount of any such invoice or any part thereof, Shipper shall pay such amount as it concedes to be correct. If Shipper disputes the amount due, it must provide supporting documentation to support the amount disputed within ten (10) days of the date of Shipper’s receipt of such invoice. C. If any undisputed charge remains unpaid after the due date, then interest shall accrue at a per annum rate of interest equal to the lower of (i) the Prime Rate plus five percent (5%) or (ii) the maximum legal rate. “Prime Rate” means the prime rate on corporate loans at large U.S. money center commercial banks as set forth in the Wall Street Journal “Money Rates” table under the heading “Prime Rate,” or any successor thereto, on the first date of publication for the month in which payment is due. D. In addition, in the event Shipper fails to pay any undisputed charges owed to Gatherer, whether under this tariff, a COGA, or any other agreement, when due, Gatherer shall have the right, until such payments, including interest thereon, are paid in full, to: (i) refuse to provide Shipper access to the Gathering System or provide services pursuant to this tariff, including delivery of any of Shipper’s Crude Oil in Gatherer’s possession to Shipper, (ii) offset the current and future amounts owed by Shipper under this tariff or a COGA against any amounts Gatherer owes to Shipper or against any of Shipper’s Crude Oil in the Gathering System, and (iii) exercise any other rights and remedies granted under this tariff or existing under Applicable Law. E. Gatherer shall have a lien on all Crude Oil delivered to and in the possession of Gatherer to secure the payment of any and all charges and fees owed to Gatherer by Shipper, whether under this tariff, a COGA if applicable, or any other agreement, including but not limited to, transportation fees, deficiency payments, penalties, interest and late payment charges. Such lien shall extend to all Crude Oil in Gatherer’s possession beginning with Shipper’s first receipt of transportation or other services from Gatherer. Shipper agrees to execute such additional documents as may be reasonably necessary to perfect or evidence such lien. If a bill of lading is required under Applicable Law for such a lien to arise, acceptance of the Nomination will be deemed to be the bill of lading for all Crude Oil subject to such Nomination. The lien provided herein shall be in addition to any lien or security interest provided by this tariff or Applicable Law. F. If Shipper fails to pay any undisputed charges owed to Gatherer by the due date, Gatherer will notify Shipper of the failure, and if Shipper has not remedied the failure within ten (10) days following receipt of notice from Gatherer, in addition 17

[COGA – EXECUTION] to any other remedies under this tariff or under Applicable Law, Gatherer shall have the right, either directly or through an agent, to sell any Crude Oil of such Shipper in Gatherer’s custody, including Shipper’s Line Fill, at public auction, on any day not a legal holiday, not less than forty-eight (48) hours after publication of notice of such sale in a daily newspaper of general circulation published in the town, city, or general area where the sale is to be held, stating the time and place of sale and the quantity and location of the Crude Oil to be sold. At said sale, Gatherer shall have the right to bid, and, if it is the highest bidder, to become the purchaser. The proceeds of any sale shall be applied in the following order: (i) to the reasonable expenses of holding, preparing for sale, selling, and transporting the Crude Oil and to the extent allowed by Applicable Law reasonable attorneys’ fees and legal expenses incurred by Gatherer; and (ii) to the satisfaction of Shipper’s indebtedness including interest herein provided from the date payment is due. The balance of the proceeds of the sale remaining, if any, shall be paid to Shipper or, if there is a dispute or claim as to entitlement, held for whoever may be lawfully entitled thereto. Gatherer will have a claim for and against Shipper with respect to any deficiency arising from the debt due to Gatherer from Shipper and the proceeds of any sale after reduction as set forth above. 18. FINANCIAL ASSURANCES A. Thirty (30) days prior to making its first Nomination, each prospective Shipper shall provide information to Gatherer that will allow Gatherer to determine the prospective Shipper’s ability to pay any financial obligations that could arise from the transportation of the prospective Shipper’s Crude Oil under the terms of this tariff. The type of information Gatherer may request from a prospective Shipper includes, but is not limited to, most recent year-end financials, Form 10-K reports or other filings with regulatory agencies, and bank references. Except as otherwise provided for in a COGA, if, in the reasonable opinion of Gatherer, such prospective Shipper is not creditworthy, Gatherer shall require such Shipper to prepay all transportation and other fees and lawful charges accruing on Crude Oil delivered and accepted by Gatherer or supply an irrevocable letter of credit from a bank acceptable to Gatherer, with terms in a form acceptable to Gatherer and such prepayment must be received within five (5) days of Shipper’s first Nomination. B. In the event Gatherer determines, in a manner not unreasonably discriminatory, that a Shipper’s creditworthiness is at any time unsatisfactory to Gatherer, Gatherer may require, except as otherwise provided for in a COGA, Shipper to provide adequate assurance of performance. As adequate assurance, Gatherer may require Shipper to provide one of the following (at Gatherer’s election): (i) cash (in U.S. dollars), as collateral held for security, (ii) a Guarantee (as defined below), (iii) a prepayment, and/or (iv) an irrevocable standby letter of credit issued by a Qualified Institution, with the amount of such security to be the amount estimated in good faith for the next sixty (60) days of performance hereunder. For purposes of this Item 18(B), a “Guarantee” means a guarantee of the payment obligations of Shipper which is provided by Shipper’s credit support 18

[COGA – EXECUTION] provider in favor of Gatherer with such form of guarantee being acceptable to Gatherer in its reasonable discretion. C. In the event a prospective Shipper fails to comply with any obligation in Item 18(A) or a Shipper fails to comply with any obligation in Item 18(B), Gatherer shall not be obligated to provide such prospective Shipper with access to the Gathering System or to provide transportation services pursuant to this tariff or a COGA, as applicable, until such requirement is fully met. 19. CHARGE FOR FUND COMPENSATION In addition to all other charges to Shipper accruing on Crude Oil accepted for transportation and subject to any provision in a COGA, a per Barrel charge will be assessed and collected by Gatherer in the amount of any tax, fee, or other charge levied against Gatherer in connection with such Crude Oil by any Governmental Authority for the purpose of creating a fund for the prevention, containment, clean up, and/or removal of spills and/or the reimbursement of Persons sustaining a loss therefrom or any program where Gatherer is acting as a collecting agent. Such charge will be included in the appropriate tariff filed with the Federal Energy Regulatory Commission. 20. LIABILITY OF SHIPPER As a condition to Gatherer’s acceptance of Crude Oil for transportation on the Gathering System, each Shipper agrees to protect and indemnify Gatherer against claims or actions for injury and/or death of any and all Persons whomever and for damage to property of or any other loss sustained by Gatherer, Shipper, Consignor, Consignee and/or any third party, resulting from or arising out of (i) any breach of or failure to adhere to any provision of Gatherer’s tariff(s) or a COGA (if applicable) by such Shipper or any of its Consignors, Consignees, or any of their agents, employees or representatives and (ii) the negligent act(s) or failure(s) to act of such Shipper or any of its Consignors, Consignees or any of their agents, employees or representatives in connection with delivery or receipt of Crude Oil, except to the extent such claims or actions are due to the breach by Gatherer of this tariff or a COGA (if applicable), or negligence or willful misconduct of Gatherer. 21. LIABILITY OF GATHERER A. Gatherer, while in possession of Crude Oil herein described, shall not be liable for, and Shipper hereby waives any claims against Gatherer for, any loss thereof, damage thereto, or delay caused by Force Majeure, the act of Shipper itself, a Governmental Authority, the nature of the goods, or resulting from any other causes, unless such loss, damage, or delay is due to the breach by Gatherer of this tariff or a COGA (if applicable), or negligence or willful misconduct of Gatherer. Gatherer agrees to protect and indemnify Shipper against any claims, losses or damages arising from any breach, negligence or willful misconduct by Gatherer. Gatherer shall not be liable for, and Shipper hereby waives any claims against Gatherer for, any loss or damage to Crude Oil prior to the delivery of Crude Oil to Gatherer at the Receipt Points and after delivery of Crude Oil at the Delivery Points. 19

[COGA – EXECUTION] B. In case of loss or damage of any Crude Oil from any such causes that are not due to the breach, negligence or willful misconduct of Gatherer, after it has been received for transportation at the Receipt Point and before the same has been delivered to Shipper at the Delivery Point, such loss will be charged proportionately to each Shipper in the ratio that its Crude Oil, or portion thereof, received and undelivered at the time the loss occurs, bears to the total of all Crude Oil then in the custody of Gatherer for transportation via the lines or other facilities in which the loss occurs. Gatherer will be obligated to deliver only that portion of such Crude Oil remaining after deducting Shipper’s portion of such loss determined as aforesaid. In the aforementioned instance, transportation charges will be assessed only on the quantity delivered. C. Gatherer will not be liable for discoloration, contamination, or deterioration of the Crude Oil transported hereunder unless and to the extent such discoloration, contamination, or deterioration of Crude Oil transported results from the breach, negligence or willful misconduct of Gatherer. D. NOTWITHSTANDING ANYTHING TO THE CONTRARY IN THIS TARIFF, IN NO EVENT SHALL EITHER PARTY BE LIABLE TO THE OTHER PARTY OR ITS AFFILIATES, ANY SUCCESSORS IN INTEREST OR ANY BENEFICIARY OR ASSIGNEE OF A COGA FOR ANY CONSEQUENTIAL, INCIDENTAL, INDIRECT, SPECIAL, OR PUNITIVE DAMAGES, INCLUDING, WITHOUT LIMITATION, ANY LOST PROFITS OR REVENUES THAT CONSTITUTE SUCH DAMAGES, THAT ARISE OUT OF OR RELATE TO THIS TARIFF OR ANY BREACH HEREOF; PROVIDED, HOWEVER, THE FOREGOING SHALL NOT BE CONSTRUED AS LIMITING AN OBLIGATION OF A PARTY HEREUNDER TO INDEMNIFY, DEFEND AND HOLD HARMLESS PERSONS ENTITLED TO INDEMNIFICATION HEREUNDER AGAINST CLAIMS ASSERTED BY UNAFFILIATED THIRD PARTIES, INCLUDING, BUT NOT LIMITED TO, THIRD PARTY CLAIMS FOR SPECIAL, INDIRECT, CONSEQUENTIAL, PUNITIVE OR EXEMPLARY DAMAGES. E. Gatherer operates under this tariff solely as a common carrier and not as an owner, manufacturer, or seller of the Crude Oil transported or stored hereunder, and Gatherer expressly disclaims any liability for any express or implied warranty for Crude Oil transported hereunder including any warranties of merchantability or fitness for intended use. 22. CLAIMS, SUITS, AND TIME FOR FILING As a condition precedent to recovery by Shipper against Gatherer for loss, damage, or delay in receipt or delivery of Shipper’s Crude Oil for which Gatherer may be responsible, Shipper’s claim must be filed in writing with Gatherer within nine (9) months after delivery of the affected Crude Oil, or in case of Gatherer’s failure to make delivery of Shipper’s Crude Oil, then within nine (9) months after a reasonable time for delivery has elapsed; and suits shall be instituted against Gatherer only within two (2) years and one (1) day from the day when notice in writing is given by Gatherer to Shipper that Gatherer has disallowed the claim or any part or parts thereof 20

[COGA – EXECUTION] specified in the notice. Where claims are not filed or suits are not instituted by Shipper on such claims in accordance with the foregoing provisions, such claims will not be paid and Gatherer will not be liable. Nothing in this Item 22 shall limit Shipper’s right to receive indemnification with respect to any loss, claim or damage for which Gatherer is obligated to indemnify Shipper, other than claims by Shipper or its Affiliates for loss, damage or delay in receipt or delivery of Shipper’s Crude Oil by Gatherer, regardless of when such loss, claim or damage arose. 23. CONNECTIONS Subject to any provision contained in a Priority Shipper’s COGA, including any provision requiring the connection of Receipt Points, connections to the Gathering System will only be considered if made by formal written application to Gatherer in accordance with Gatherer’s connection policy. All connections will be subject to design requirements necessary to protect the safety, security, integrity and efficient operation of the Gathering System in accordance with generally accepted industry standards and Gatherer’s connection policies. Acceptance of any application for connection will be within the sole discretion of Gatherer and will be subject to compliance with Governmental Authorities and industry regulations. 24. GATHERER DISCRETION Gatherer will operate the Gathering System and implement the rules and regulations contained in this tariff, including those provisions providing for Gatherer’s discretion, in a manner that is not unduly discriminatory or unduly preferential 25. LOSS ALLOWANCE Except as otherwise set forth in Section II of this tariff, Gatherer shall deduct the actual losses of Crude Oil on a pro rata basis to cover losses inherent in the transportation of Crude Oil on the Gathering System, provided that such loss allowance shall not exceed (i) two-tenths of one percent (0.20%) of the volumes of Shipper’s Crude Oil received into the Gathering System, with respect to Shipper’s Crude Oil having an API Gravity of 49.9 degrees or less, or (ii) four-tenths of one percent (0.40%) of the volumes of Shipper’s Crude Oil received in the Gathering System, with respect to Shipper’s Crude Oil having an API Gravity of 49.9 degrees to 60 degrees (Gatherer will not accept for transportation Crude Oil with API Gravity above 60 degrees). The volumes delivered to Shipper or its designee from Gatherer’s facilities shall be net of such deduction. 21

[COGA – EXECUTION] SECTION II RATES TABLE 1 COMMITTED RATES APPLICABLE TO PRIORITY SHIPPERS1 AND UNCOMMITTED RATES Rates in Dollars per Barrel Volume 10 Year Term 12 Year Term Uncommitted Tier Origin Destination (Barrels/Day) Priority Rate2 Priority Rate3 Rate4 >25,000 1 Tank >20,000 and 2 Batteries <= 25,000 located in Winkler Interconnect at County, 10,000 and 3 Texas, Pipeline, <= 20,000 Loving [Winkler] County, County, Texas Texas and >=2,000 and 4 Lea County, <= 10,000 New Mexico 5 < 2,000 Truck Interconnect at Station(s) Pipeline, [Winkler] County, Texas 22

[COGA – EXECUTION] TABLE 2 COMMITTED RATES APPLICABLE TO PRIORITY SHIPPERS WITH ACREAGE DEDICATION OF AT LEAST 2,000 ACRES AND UNCOMMITTED RATES Rates in Dollars per Barrel 12 Year Term 5,9, Uncommitted Tier Origin Destination Priority Rate 6, 9, 10 10 Rate [ ] Tank Batteries located in Winkler Interconnect at County, 1 Texas, Pipeline, $0.75 $0.74 Loving [Winkler] County, County, Texas Texas and Lea County, New Mexico [ ] Interconnect at Truck 1 Station(s) Pipeline, [Winkler] County, Texas 23

[COGA – EXECUTION] TABLE 3 COMMITTED RATES APPLICABLE TO PRIORITY SHIPPERS WITH ACREAGE DEDICATION OF AT LEAST 2,000 ACRES AND UNCOMMITTED RATES Rates in Dollars per Barrel Volume 10 Year Term Uncommitted Tier Origin7 Destination (Barrels/Day) Priority Rate8 Rate6 1 [ ] Tank Interconnect at >20,000 $1.18 $1.17 Batteries >10,000 and $0.98 2 $0.97 located in <= 20,000 Pipeline, Eddy and Lea [Winkler] <=10,000 $0.78 3 Counties, $0.77 County, Texas New Mexico [ ] Interconnect at Truck Station(s) Pipeline, [Winkler] County, Texas Effective as of 9:00 a.m., Central Clock Time, on the first January 1st that occurs two years after the Commencement Date, and each January 1st occurring thereafter, the Priority Rates and Uncommitted Rates noted above shall be adjusted upwards or downwards following FERC’s indexing adjustment, as set out in 18 CFR § 342.3, including future amendments or modifications thereof, provided, however, that such indexing adjustment shall not result in an increase or decrease in the Priority Rates and/or Uncommitted Rates that exceeds two percent (2%) or a decrease in the Priority Rates and/or Uncommitted Rates that would result in a rate less than the rates set out in Gatherer’s initial FERC tariff, F.E.R.C. No. 1.0.0. In the event that Gatherer is unable to make a tariff filing pursuant to 18 CFR § 342.4(c) to adjust the Uncommitted Rates, then Gatherer will make a tariff filing to adjust the Uncommitted Rates effective as of the subsequent July 1 pursuant to 18 CFR § 342.3. However, if the FERC indexing adjustment is eliminated, Gatherer may increase or decrease the Priority Rates and Uncommitted Rates to reflect any positive changes or negative changes in the Producer Price Index for Finished Goods, on a year-over-year basis, subject to the above-noted increase and decrease limitations. TRUCK UNLOAD CHARGE Shipments unloaded from tank truck facilities into the Gathering System at Receipt Points are subject to a charge of 7.25 cents ($0.0725) per Barrel, except as otherwise provided in a COGA. 24

[COGA – EXECUTION] Notes Applicable to Tables 1, 2 and 3 1. Priority Shippers that have committed to deliver a specified volume of Crude Oil to the Gathering System. 2. In order to qualify for this 10 Year Term Committed Rate, a Priority Shipper must have entered into a COGA with a minimum term of 10 years and a commitment to deliver a specified volume of Crude Oil on the Gathering System of at least [2,000] Barrels per day. 3. In order to qualify for this 12 Year Term Committed Rate, a Priority Shipper must have entered into a COGA with a minimum term of 12 years and a commitment to deliver a specified volume of Crude Oil on the Gathering System of at least [2,000] Barrels per day. 4. An Uncommitted Shipper’s Uncommitted Rate will be based on the volume of Crude Oil it ships each month on the Gathering System, which shall then determine the volume tier applicable to such Uncommitted Shipper. 5. In order to qualify for this 12 Year Term Committed Rate, a Priority Shipper must have entered into a COGA with a minimum term of 12 years and made an acreage dedication covering at least [2,000] acres of lands located in Winkler County, Texas, Loving County, Texas and/or Lea County, New Mexico. 6. In order to qualify for the Uncommitted Rate based on an acreage dedication, an Uncommitted Shipper must have an effective dedication agreement with Gatherer pursuant to which such Uncommitted Shipper has agreed to deliver crude petroleum produced from the dedicated acreage for transportation on the Gathering System. 7. In lieu of the provisions stated in Item 25 of the tariff, the following will apply for Crude Oil Tendered at these Receipt Points: . The volumes delivered to Shipper from Gatherer’s facilities shall be net of such deduction. 8. In order to qualify for this 10 Year Term Committed Rate, a Priority Shipper must have entered into a COGA with a minimum term of 10 years and made an acreage dedication covering at least [2,000] acres of lands located in Winkler County, Texas, Loving County, Texas and/or Lea County, New Mexico. 9. If the Commencement Date does not occur by , 201 (the “Project Deadline”), then upon the Commencement Date, Gatherer shall temporarily reduce this Priority Rate to $0.375 per Barrel and this Uncommitted Rate to $0.370 per Barrel for only a period of time equal to the amount of days from the Project Deadline until the Commencement Date (“Delay Period”); provided, however, on the first day after the expiration of the period of time after the Commencement Date equal to the Delay Period, such Priority Rate and Uncommitted Rate will be increased to such rates, respectively, set out in Table 2. By way of example, if the Delay Period is equal to thirty (30) days, then such Priority Rate and Uncommitted Rate will be $0.375 per Barrel and $0.370 per Barrel, respectively, for only the first 30 days after the Commencement Date and on the 31st day after the Commencement Period, the Priority Rate and Uncommitted Rate shall be as set out in Table 2. Notwithstanding anything herein to the contrary, if the Project Deadline is delayed due to a properly noticed event of Force Majeure, then the Project Deadline shall be extended for each day of any such delay. 10. If Gatherer fails or is unable to connect an additional Receipt Point as requested by a Priority Shipper as provided for in the applicable COGA by the date that is thirty (30) days beyond the applicable Target RP In-Service Date (as such term is defined in the 25

[COGA – EXECUTION] applicable COGA) for any reason other than Force Majeure, then, for each day of unexcused delay until Gatherer connects such additional Receipt Point beyond the Target RP In-Service Date, Gatherer shall temporarily reduce this Priority Rate to $0.375 per Barrel and this Uncommitted Rate to $0.370 per Barrel for Shipper’s Crude Oil delivered to such additional Receipt Point for only a period of time equal to the amount of days from the deadline set forth in the COGA until the date such additional Receipt Point is connected; provided, however, on the first day after the expiration of such period of time, the Priority Rate and Uncommitted Rate will be increased to such rates, respectively, set out in Table 2. By means of example, if Gatherer connects a requested Receipt Point fifty (50) days after the Target In-Service Date for such additional Receipt Point, and such delay is not due to an event of Force Majeure, then the reduction in the Priority Rate and Uncommitted Rate described in the preceding sentence would apply to such Priority Shipper’s Crude Oil received at such additional Receipt Point for the first twenty (20) days after such additional Receipt Point is connected. 26

EXHIBIT G PRIOR DEDICATIONS NONE.

OPTION AGREEMENT This OPTION AGREEMENT (this “Agreement”) is entered into effective as of the 21st day of May, 2018 (the “Effective Date”), by and between SALT CREEK MIDSTREAM, LLC, a Delaware limited liability company (“SCM”), and LILIS ENERGY, INC., a Nevada corporation (“Lilis”). SCM and Lilis are sometimes referred to collectively as the “Parties” and individually as a “Party.” RECITALS WHEREAS, Lilis has or contemplates having a supply of owned or controlled Gas from present and future Interest(s) of Lilis and its Affiliates located within the lands being more particularly described on Exhibit A (the “AMI”); and WHEREAS, SCM owns and operates, or plans to own and operate, gathering and processing facilities capable of receiving deliveries of Gas within the AMI; WHEREAS, Lilis desires to grant to SCM a right of first refusal to provide midstream services with respect to certain owned or controlled Gas produced from the present and future Interest(s) of Lilis and its Affiliates within the AMI, on the terms and conditions set forth in this Agreement; WHEREAS, Lilis, as seller, and Lucid Energy Delaware LLC, a Delaware limited liability company currently (“Lucid”), as buyer, are parties to that certain Gas Gathering, Processing and Purchase Agreement dated August 10, 2017, as amended (the “Lucid Agreement”); and WHEREAS, Lilis desires to grant to SCM an option for SCM to cause Lilis to terminate the Lucid Agreement and enter into a new Gas Purchase Agreement covering the Interest(s) dedicated under the Lucid Agreement and certain other Interest(s) more particularly described therein upon the termination of such Lucid Agreement, on the terms and conditions set forth in this Agreement. AGREEMENT NOW THEREFORE, in consideration of the foregoing and Ten Dollars ($10.00) and other good and valuable consideration paid by SCM to Lilis on the Effective Date, the receipt and adequacy of which are hereby acknowledged, the Parties hereto agree as follows: 1. Defined Terms. Unless otherwise required by the content, the terms defined in this Section 1 shall have, for all purposes of this Agreement, the respective meanings set forth in this Section 1. (a) “Affiliate” shall mean any Person that directly or indirectly through one or more intermediaries, controls or is controlled by or is under common control with another Person. The term “control” (including its derivatives and similar terms) shall mean possessing the power to direct or cause the direction of the management and policies of a Person, whether through ownership, by contract, or 1 6645116v1

otherwise. Any Person shall be deemed to be an Affiliate of any specified Person if such Person owns fifty percent (50%) or more of the voting securities of the specified Person, or if the specified Person owns fifty percent (50%) or more of the voting securities of such Person, or if fifty percent (50%) or more of the voting securities of the specified Person and such Person are under common control. (b) “Business Day” shall mean any calendar day other than Saturdays and Sundays that commercial banks in Houston, Texas are open for business. (c) “Gas” means natural gas produced in its original state from a gas well and/or an oil well. (d) “Governmental Authority” shall mean (i) the United States of America, (ii) any state, county, parish, municipality or other governmental subdivision within the United States of America, and (iii) any court or any governmental department, commission, board, bureau, agency or other instrumentality of the United States of America or of any state, county, municipality or other governmental subdivision within the United States of America. (e) “Interests” shall mean any right, title, or interest in lands, Wells, or leases with the right to produce oil and/or gas therefrom whether arising from fee ownership, working interest ownership, mineral ownership, leasehold ownership, or arising from any pooling, unitization or communitization of any of the foregoing rights. (f) “Person” shall mean any individual, firm, corporation, trust, partnership, limited liability company, association, joint venture, other business enterprise or Governmental Authority. (g) “Third Party” shall mean means any Person other than a Party or an Affiliate of a Party. (h) “Well” shall mean a well for the production of gas and/or liquid hydrocarbons, including Gas. 2. Right of First Refusal for Midstream Services. Commencing on the Effective Date, in the event that Lilis receives an offer from a Third Party during the Term of this Agreement to provide Gas gathering, processing and/or related midstream services with respect to any Gas attributable to Lilis’ and its Affiliates’ non-dedicated Interest(s) within the AMI that Lilis intends to accept, including, without limitation, any Interests of Lilis and its Affiliates owned as of the Effective Date or subsequently acquired within the AMI, Lilis shall, prior to entering into any agreement for such Gas midstream services with the applicable Third Party, notify SCM in writing and offer the right to provide such Gas midstream services with respect to the applicable Gas on identical terms and conditions relating to rates, fees, deductions, cost recoveries and other economic terms, offered by the applicable Third Party. Such notice shall provide true and complete information about the proposed midstream services, including the 2 6645116v1

name and address of the Third Party (to the extent that Lilis is not prohibited from disclosing such name and address pursuant to any confidentiality agreement with such Third Party) and the terms and conditions of the relevant agreement. SCM shall have the right for fifteen (15) Business Days after receipt of Lilis’ notice to determine whether it will provide midstream services for such Gas on such identical terms and conditions contained in Lilis’ notice. Failure by SCM to respond within such fifteen (15) Business Day period shall be deemed a rejection of such offer without any further action by the Parties. If SCM elects to provide such midstream services, then the Parties shall either enter into a new agreement memorializing the terms contained in Lilis’ notice. 3. Option for GGPA Execution. The Parties acknowledge that, as of the Effective Date, Lilis is a party to the Lucid Agreement, pursuant to which Lilis has dedicated Gas from certain Interest(s) within the AMI for Gas gathering, processing and related midstream services by Lucid, which dedication Lilis shall have the opportunity to terminate effective August 10, 2027 (the “Lucid Agreement Termination Date”). On or before 5:00 p.m. central time on January 1, 2027 (the “Option Election Deadline”), SCM shall have a one-time option to give Lilis written notice of SCM’s election to have Lilis terminate the Lucid Agreement as of the Lucid Agreement Termination Date and enter into the Gas Purchase Agreement attached hereto as Exhibit B, to be effective as of August 11, 2027 (the “SCM Gas Purchase Agreement”), pursuant to which Lilis shall dedicate the Interest(s) dedicated under the Lucid Agreement and certain other Interest(s) described therein on the terms and conditions set forth therein; provided, however, SCM shall only have the right to exercise such option to the extent that SCM shall have installed all infrastructure necessary to receive, gather, process and provide all related midstream services under the Gas Purchase Agreement with respect to all Gas dedicated thereunder (including all Gas previously dedicated under the Lucid Agreement), and is ready and able to provide in full such services with respect to such Gas pursuant to the SCM Gas Purchase Agreement. To the extent that SCM fails to exercise in writing its option under this Section 3 on or before the Option Election Deadline, SCM’s right to exercise such option shall be deemed to have been waived without any further action by the Parties. 4. Term. This Agreement shall commence as of the Effective Date written above and shall terminate on the Option Election Deadline (the “Term”); provided, however, any obligations of the Parties arising under this Agreement prior to the Option Election Deadline, including any obligation to enter into any Gas midstream agreement or execute the SCM Gas Purchase Agreement, shall survive the termination of this Agreement. 5. Assignment. Neither Party may assign this Agreement without the prior written consent of the non-assigning Party, such consent not to be unreasonably withheld, conditioned or delayed; provided, however, and notwithstanding the foregoing, (A) Lilis may assign its rights and obligations under this Agreement to any Person to whom Lilis assigns or transfers an interest in any of the Interest(s), insofar and only insofar as, this Agreement relates to such Interest(s), without the consent of SCM; provided that (i) such Person assumes in writing the obligations of Lilis under this Agreement insofar as it relates to such Interest(s), and (ii) if such transfer or assignment is to a Person that is not an Affiliate of Lilis, Lilis shall be released from its obligations under this Agreement with respect to such Interest(s) so assigned or transferred, except for its obligations arising prior to the date of assignment, and (B) SCM may assign its rights and obligations under this Agreement to any Person to whom SCM assigns or transfers all 3 6645116v1

or substantially all of its Gas gathering and processing facilities within the AMI without the consent of Lilis; provided that (i) such Person assumes in writing the obligations of SCM under this Agreement, and (ii) if such transfer or assignment is to a Person that is not an Affiliate of SCM, SCM shall be released from its obligations under this Agreement, except for its obligations arising prior to the date of assignment. For the avoidance of doubt, no assignee or transferee of Lilis shall assume the AMI of this Agreement in its entirety, but shall only be subject to, and assume, such AMI insofar and only insofar as the Interest(s) assigned or transferred to such assignee or transferee. 6. Covenants Running with the Land; Successors and Assigns. The terms, covenants, and conditions of this Agreement shall be deemed to be covenants running with the Interest(s) of Lilis and its Affiliates and lands within the AMI and with each transfer of any interest affected thereby, such terms, covenants, and conditions shall extend to, bind, and inure to the benefit of the Parties and to their respective successors and assigns. 7. Third Party Beneficiaries. This Agreement is exclusively for the benefit of Parties named herein. No party other than the Parties shall be entitled to enforce any provision herein or to be substituted for either Party, except as explicitly provided herein. 8. No Partnership. No partnership, commercial partnership, joint venture or similar relationship is intended or shall result or be construed to exist as a result of the execution or performance of any of the obligations or exercise of any rights or remedies by the Parties of or pursuant to this Agreement, and no act by a Party shall create such a relationship, nor shall any of the provisions hereof be construed or implied as creating such a relationship for any purpose whatsoever. 9. Notices. All notices and communications required or permitted under this Agreement shall be in writing addressed as indicated below, and any communication or delivery hereunder shall be deemed to have been duly delivered upon the earliest of: (a) actual receipt by the Party to be notified; (b) if by facsimile or electronic mail, upon confirmation by the recipient of receipt, provided that a copy of such notice has also been sent by Federal Express overnight delivery (or other reputable overnight delivery service); or (c) if by Federal Express overnight delivery (or other reputable overnight delivery service), two (2) days after deposited with such service. Addresses for all such notices and communication shall be as follows: SCM: Salt Creek Midstream, LLC 200329 State Highway 249 Floor 4 Houston, TX 77070 Attn: Paul Williams Email: paul.williams@armenergy.com 4 6645116v1

With a copy to: Salt Creek Midstream, LLC 20329 State Highway 249 Floor 4 Houston, TX 77070 Attn: Contract Administration Email: contracts@armenergy.com Lilis: NOTICES AND CORRESPONDENCE: Lilis Energy, Inc. 300 E. Sonterra Blvd, Suite 1220 San Antonio, TX 78258 Attention: Accounting and Operations Telephone: 210-999-5400 Facsimile 210-999-5401 With a copy to: RDP Producer Services, LLC 10300n Town Park, Suite SE1000 Houston, TX 77072 Attn: David Lipp Fax: 281-849-8911 Email: dlipp@republicpartnersllc.com Any Party may, upon written notice to the other Parties, change the address and person to whom such communications are to be directed. 10. Waiver; Rights Cumulative. Any of the terms, covenants, or conditions hereof may be waived only by a written instrument executed by or on behalf of the Party waiving compliance. No course of dealing on the part of a Party, or their respective officers, employees, agents, or representatives, nor any failure by a Party to exercise any of its rights under this Agreement shall operate as a waiver thereof or affect in any way the right of such Party at a later time to enforce the performance of such provision. No waiver by any Party of any condition, or any breach of any term, covenant, representation, or warranty contained in this Agreement, in any one or more instances, shall be deemed to be or construed as a further or continuing waiver of any such condition or breach or a waiver of any other condition or of any breach of any other term, covenant, representation, or warranty. The rights of each Party under this Agreement shall be cumulative, and the exercise or partial exercise of any such right shall not preclude the exercise of any other right. 5 6645116v1

11. Amendments. This Agreement may be amended only by an instrument in writing executed by the Parties. 12. Severability. If any term or other provision of this Agreement is invalid, illegal, or incapable of being enforced by any rule of law or public policy, all other conditions and provisions of this Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated hereby is not affected in any adverse manner to any Party. Upon such determination that any term or other provision is invalid, illegal, or incapable of being enforced, the Parties shall negotiate in good faith to modify this Agreement so as to effect the original intent of the Parties as closely as possible in an acceptable manner to the end that the transactions contemplated hereby are fulfilled to the extent possible. 13. Governing Law. This Agreement will be interpreted, construed, and enforced in accordance with the laws of the State of Texas, without giving effect to any rules or principles of conflicts of law that might otherwise refer to the laws of another jurisdiction. The Parties hereby irrevocably consent to the exclusive jurisdiction of the state or federal courts located in Houston, Harris County, Texas and irrevocably and unconditionally waive, to the fullest extent they may legally and effectively do so, any objection which they may now or hereafter have to the laying of venue of any suit, action or proceeding arising out of or relating to this Agreement or the transactions contemplated hereby in any federal or state court located in Houston, Harris County, Texas. EACH PARTY HEREBY IRREVOCABLY AND UNCONDITIONALLY WAIVES ANY RIGHT SUCH PARTY MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY LITIGATION DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT. 14. Exhibits. The Exhibits referred to herein are attached hereto and incorporated herein by this reference, and unless the context expressly requires otherwise, the exhibits and schedules are incorporated in the definition of “Agreement.” 15. Interpretation. It is expressly agreed by the Parties that this Agreement shall not be construed against any Party, and no consideration shall be given or presumption made, on the basis of who drafted this Agreement or any provision hereof or who supplied the form of this Agreement. Each Party agrees that this Agreement has been purposefully drawn and correctly reflects its understanding of the transactions contemplated by this Agreement and, therefore, waives the application of any law or rule of construction providing that ambiguities in an agreement or other document will be construed against the Party drafting such agreement or document. 16. Entire Agreement. This Agreement and any other documents delivered in connection with this Agreement contain the entire agreement of the Parties with respect to the subject matter hereof and supersede all previous agreements or communications between the Parties, verbal or written, with respect to the subject matter hereof. Each Party agrees that no other Party (including its agents and representatives) has made any representation, warranty, covenant or agreement to or with such Party relating to this Agreement or the transactions contemplated hereby, other than those expressly set forth in this Agreement. 6 6645116v1

17. Further Assurances. The Parties shall provide to each other such information with respect to the transactions contemplated hereby as may be reasonably requested and shall execute and deliver to each other such further documents and take such further action as may be reasonably requested by any Party to document, complete or give full effect to the terms and provisions of this Agreement and the transactions contemplated herein. 18. Disclaimer of Certain Damages. NOTWITHSTANDING ANYTHING TO THE CONTRARY IN THIS AGREEMENT, IN NO EVENT SHALL EITHER PARTY BE LIABLE TO THE OTHER PARTY OR ITS AFFILIATES, ANY SUCCESSORS IN INTEREST OR ANY BENEFICIARY OR ASSIGNEE OF THIS AGREEMENT FOR ANY CONSEQUENTIAL, INCIDENTAL, INDIRECT, SPECIAL, OR PUNITIVE DAMAGES, INCLUDING, WITHOUT LIMITATION, ANY LOST PROFITS OR REVENUES THAT CONSTITUTE SUCH DAMAGES, THAT ARISE OUT OF OR RELATE TO THIS AGREEMENT OR ANY BREACH HEREOF. 19. Memorandum. As of the Effective Date, the Parties shall execute and deliver a mutually agreeable recordable form of memorandum of this Agreement in the form attached as Exhibit C. 20. Headings. All captions, numbering sequences, and headings used in this Agreement are inserted for convenience only and do not define, limit, or describe the scope or intent of this Agreement, nor do they have any legal effect other than to aid a reasonable interpretation of this Agreement. 21. Attorney’s Fees. If any Party institutes an action or proceeding against any other Party relating to the provisions of this Agreement, including arbitration, the Party to such action or proceeding which does not prevail will reimburse the prevailing Party therein (regardless of whether the prevailing Party is the plaintiff or the defendant in such action or proceeding) for the reasonable expenses of attorneys’ fees and disbursements incurred by the prevailing Party. 22. Counterparts. This Agreement may be executed in counterparts by facsimile, portable document format (PDF), and other electronic means, and when each Party has signed and delivered at least one such counterpart to each of the other Parties, each counterpart shall be deemed an original, and all counterparts taken together shall constitute one and the same Agreement, which shall be deemed binding and effective as to all Parties. [Signatures are on the following page.] 7 6645116v1

IN WITNESS WHEREOF, the Parties hereto have executed and delivered this Agreement as of the Effective Date. SCM: SALT CREEK MIDSTREAM, LLC By: /s/ Michael S. Christopher Name: Michael Christopher Title: Chief Financial Officer LILIS: LILIS ENERGY, INC. By: /s/ Joseph C. Daches Name: Joseph C. Daches Title: CFO [Signature Page to Option Agreement]

EXHIBIT A DESCRIPTION OF AMI [ATTACHED] EXHIBIT A 6645116v1

AX A24 G A I N E A25 2 A27 2 2 E 2 29E 2 3 E 2 31E 2 32E 2 33E 2 34E 2 35E 2 36E 2 37E 2 3 E A22 C45 39E A2 A23 A24 A26 A2 A26 A3 A31 A44 A34 21 27E 21 2 E 21 29E 21 3 E 21 31E 21 32E 21 33E 21 34E 21 35E 21 36E 21 37E 21 3 E A29 A33 A36 A32 A34 A43 A35 A37 A34 A3 A39 A36 22 27E 22 2 E 22 29E 22 3 E 22 31E 22 32E 22 33E 22 34E 22 35E 22 36E 22 37E 22 3 E A3 13 14 A45 A39 A4 A49 A4 L E A A46 23 27E A5 A N D R E W A44 23 2 E 23 29E 23 3 E 23 31E 23 32E 23 33E 23 34E 23 35E 23 36E 23 37E 23 3 E Y Y A47 D D D D A43 E E A51 A42 12 A41 24 2 E 24 29E 24 3 E 24 33E A53 24 27E 24 31E 24 32E 24 34E 24 35E 24 36E 24 37E 24 3 E A52 9 A54 1 11 25 2 E 25 29E 25 3 E 25 31E 25 32E 25 33E 25 34E 25 35E 25 36E 25 37E 25 27E 25 3 E A55 73 44 T2N A22 A41 A26 43 T1N A 54 45 T2N 44 T1N 26 27E 26 2 E 26 29E 26 3 E 26 31E 26 32E 26 33E 26 34E 26 35E 26 36E 26 37E 26 3 E A56 A57 A 57 A 46 46 43 N E W M E X I C O 45 TIN 45 T1N T1N 56T1 55T1 A 57 B57 44 T1N C22 T E X A S A57 46 C23 43 T1 C C24 77 C25 46 T1N 5 T1 57 T1 57 T1 56 T1 55 T1 54 T1 76 59 T1 B1 74 44 T1 B2 WF 1 46 TI B3 7 C26 75 B2 45 T1 46 T1 B7 E C T O R 29 26 W 4 46 TI L O V I N G WW I N K L E R B27 B6 27 5 T2 57 T2 57 T2 56 T2 55 T2 54 T2 53 T2 59 T2 5 T7 B4 B4 44 T2 2 45 T2 B5 B4 5 B 5 T6 29 C U L B E R O N B1 B9 2 112 56 T3 57 T3 56 T3 2 C27 C29 B15 1 B11 44 T3 113 B12 21 45/113 56 T3 C2 B14 57 T3 2 2 35 VV 19 B13 45 R E E V E \ LILIS_ACREAGE.mxdLilis B16 \ 1 A 111 33 46 T3 16 55 T3 2 AMI 3 15 C21 13 46 \ Energy Companies F B23 5 53 T4 3 B22 52 T4 B19 \ SALT_CREEK 55 T4 53 T4 1 17 R A N E 57 Projects R A N E \ 54 T4 52 T4 W A R D B1 B2 B17 C R A N E 52 53 56 \ GIS C19 34 N 63 ‘ B26 53 O 1 5 Miles 4 16 B21 54 T5 B2 Document Path: M: 55 T5 54 T4 34 34 B19

EXHIBIT B FORM OF SCM GAS PURCHASE AGREEMENT [ATTACHED] EXHIBIT B 6645116v1

Execution – Option Agreement GAS PURCHASE AGREEMENT BETWEEN Lilis Energy, Inc. (“Customer”) AND Salt Creek Midstream, LLC (“SCM”) Dated Effective as of August 11, 2027

Execution – Option Agreement TABLE OF CONTENTS ARTICLE I SCOPE OF THIS AGREEMENT .............................................................................. 1 1.1 Scope of this Agreement ....................................................................................................... 1 1.2 General Terms and Conditions and Exhibits Incorporated by Reference ............................. 2 ARTICLE II COMMITMENT AND QUANTITIES ..................................................................... 3 2.1 Dedication ............................................................................................................................. 3 2.2 Reservations of Customer ..................................................................................................... 3 2.3 Prior Dedications as of the Effective Date and Subsequently Acquired Leases ................... 4 2.4 Covenant Running With the Land ........................................................................................ 5 2.5 No Upstream Processing ....................................................................................................... 5 2.6 Receipt Points; Drilling Plans ............................................................................................... 6 2.7 Non-Dedicated Gas ............................................................................................................... 8 ARTICLE III FEES ........................................................................................................................ 8 3.1 Service Fees .......................................................................................................................... 8 3.2 Treating Fuel ......................................................................................................................... 9 3.3 Escalation .............................................................................................................................. 9 ARTICLE IV PROCESSING SETTLEMENT; ADDITIONAL CONSIDERATION .................. 9 4.1 Products Purchase ................................................................................................................. 9 4.2 Processing Mode Election .................................................................................................. 10 ARTICLE V NOTICES ................................................................................................................ 11 5.1 Addresses ............................................................................................................................ 11 ARTICLE VI TERM; TERMINATION .......................................................................................12 6.1 Term .................................................................................................................................... 12 6.2 Default; Termination for Cause .......................................................................................... 12 6.3 Bankruptcy Savings ............................................................................................................ 13 ARTICLE VII CONFIDENTIALITY .......................................................................................... 13 7.1 Confidential Information .................................................................................................... 14 GENERAL TERMS AND CONDITIONS EXHIBITS: Exhibit A-1 Dedicated Area Exhibit A-2 Map of Dedicated Area Exhibit B-1 Receipt Points Exhibit C Form of Memorandum of Agreement

Execution – Option Agreement Exhibit D-1 Residue Gas Delivery Points Exhibit D-2 Plant Products Delivery Points Exhibit E Prior Dedications Exhibit F Take In Kind Scheduling, Nomination and Balancing Procedures Exhibit G Form of New Receipt Point Notification

Execution – Option Agreement GAS PURCHASE AGREEMENT THIS GAS PURCHASE AGREEMENT (this “Agreement”) is made and entered into effective as of this 11th day of August, 2027 (the “Effective Date”) by and between Lilis Energy, Inc., a Nevada corporation (“Customer”), and Salt Creek Midstream, LLC, a Delaware limited liability company (“SCM”). Customer and SCM are sometimes referred to collectively as the “Parties” or singularly as a “Party.” W I T N E S S E T H: WHEREAS, Customer owns and/or controls Gas be produced, and Gas produced, from Wells operated by Customer or its Affiliates located in the Dedicated Area and desires SCM, subject to the terms and conditions hereof, to receive, gather and process Dedicated Gas, and to purchase Residue Gas and Plant Products from (or to deliver in-kind, at Customer’s direction, such Residue Gas to) Customer; NOW, THEREFORE, for and in consideration of the premises and the mutual benefits and covenants herein contained, the Parties hereby agree as follows: ARTICLE I SCOPE OF THIS AGREEMENT 1.1 Scope of this Agreement. Subject to the terms of this Agreement: (a) Customer agrees to: (i) make the Dedication, subject to Section 2.2 of this Agreement; and (ii) deliver, and shall cause its Affiliates to deliver to SCM, at the Receipt Points, the Dedicated Gas. (b) SCM agrees to provide the following (the “Services”), on a Level Two Service basis: (i) receive Dedicated Gas meeting the Specifications at the Receipt Points; (ii) gather, compress, dehydrate and treat such Dedicated Gas and deliver such Dedicated Gas to the Plant; (iii) process such Dedicated Gas for the recovery of Plant Products; (iv) purchase Residue Gas from Customer at the Receipt Point, subject to Customer’s option to take delivery of Residue Gas in-kind in accordance with Section 4.1(c), and deliver such Residue Gas for third party sales at the Residue Gas Delivery Points; 1

Execution – Option Agreement (v) to the extent that Customer has elected its option to take delivery of Residue Gas in-kind in accordance with Section 4.1(c), deliver such Residue Gas to Customer at the Residue Gas Delivery Points; and (vi) purchase Plant Products from Customer at the Receipt Point and deliver such Plant Products for third party sales at the Plant Products Delivery Points. 1.2 General Terms and Conditions and Exhibits Incorporated by Reference. (a) The General Terms and Conditions and the Exhibits attached to this Agreement are incorporated in and made a part of this Agreement for all purposes. Any reference in this Agreement to “this Agreement” shall include the General Terms and Conditions and the Exhibits attached hereto, and all amendments, restatements, supplements or other modifications thereto, as the same may be in effect at any and all times such reference becomes operative. In the event of any inconsistency the order of precedence shall be as follows: (i) the terms of the main body of this Agreement, (ii) the General Terms and Conditions, and (iii) the Exhibits. (b) All references to Sections or Articles of this Agreement shall refer to Sections and Articles in the main body of this Agreement, unless the context specifically reflects that the reference is to an Article or Section of the General Terms and Conditions of this Agreement. (c) As used in this Agreement, (i) any pronoun in masculine, feminine or neutral gender shall be construed to include all other genders, (ii) the term “including” shall be construed to be expansive rather than limiting in nature and to mean “including without limitation”, except where the context clearly otherwise requires, (iii) each term that is defined in this Agreement in the singular shall include the plural of such term, and each term that is defined in this Agreement in the plural shall include the singular of such term, and (iv) the words, phrases, and terms used herein shall have their ordinary meaning unless it is clearly indicated otherwise in this Agreement or unless such word, phrase or term is defined in this Agreement. (d) Both Parties participated in the drafting of this Agreement. If any ambiguity is contained herein, no weight shall be given in favor of or against a Party in resolving that ambiguity on account of that Party’s drafting of this Agreement. (e) Capitalized terms used in this Agreement and not otherwise defined in the main body of this Agreement shall have the meanings ascribed to them in the General Terms and Conditions. 2

Execution – Option Agreement ARTICLE II COMMITMENT AND QUANTITIES 2.1 Dedication. Subject to the other terms and conditions hereof, Customer hereby (i) dedicates for Services with respect to Dedicated Gas under this Agreement to SCM all Leases now owned or hereafter acquired by Customer and/or its Affiliates and their respective successors and assigns that cover lands located within the Dedicated Area, and (ii) dedicates for Services under this Agreement and shall deliver, or cause to be delivered, hereunder to SCM, at the Receipt Points, the following (the “Dedication,” and the Gas that is the subject of the Dedication being herein referred to as “Dedicated Gas”): (a) all Gas produced and saved on or after the Effective Date for the remainder of the Term from those Wells for which Customer and/or any of its Affiliates is the operator now or hereafter located within the Dedicated Area or on lands pooled or unitized therewith, to the extent such Gas is attributable to the Leases within the Dedicated Area now owned or hereafter acquired by Customer and/or its Affiliates and their respective successors and assigns; and (b) with respect to those Wells for which Customer and/or any of its Affiliates is the operator, Gas produced on or after the Effective Date for the remainder of the Term from such Wells which is attributable to the Leases in such Wells owned by other working interest owners and royalty owners which is not taken “in-kind” by such working interest owners and royalty owners and for which Customer and/or its Affiliates has the right or obligation to deliver such Gas and only for the period that Customer and/or its Affiliates has such right or obligation. For the avoidance of doubt, Customer shall not be required to deliver Gas from any well operated by an operator other than Customer or its Affiliates, including any well where Customer would be required to install split stream connection facilities or similar facilities to take such Gas in kind, and such Gas shall not be Dedicated Gas subject to the Dedication hereunder. 2.2 Reservations of Customer. Customer reserves the following rights under this Agreement: (a) to operate the Well(s) and Leases in its sole discretion, including, without limitation, the right, but never the obligation, to drill new Well(s), to repair and rework old Well(s), renew or extend, in whole or in part, any oil and gas lease covering any of lands within the Dedicated Area, and to cease production from or abandon any Well or surrender any such oil and gas lease, in whole or in part, in Customer’s discretion; (b) to use Dedicated Gas for operations (including, without limitation, for gas lift, cycling, and Well production enhancement) relating to the Leases and Wells, for fueling of any facilities upstream of the Receipt Point(s) installed for purposes of delivering Gas to SCM in accordance with this Agreement, and for any other 3

Execution – Option Agreement purposes reasonably necessary for the development of the lands within the Dedicated Area; (c) to deliver or furnish to Customer’s and its Affiliates’ lessors and holders of other existing burdens on production such Dedicated Gas as is required to satisfy the terms of the applicable oil and gas leases and other applicable instrument creating the burdens; (d) to flare or temporarily use or deliver Dedicated Gas to the facilities of third parties to gather, process and provide related services for Dedicated Gas from a Well prior to the time that the Facilities required to gather such Dedicated Gas have been completed and placed in-service; (e) to pool, communitize, or unitize the lands covered by the Leases of Customer and its Affiliates’, including with lands not covered by such Leases; provided that Customer’s and/or its Affiliates’ share of Gas produced from such pooled, communitized, or unitized interests shall be dedicated and committed to this Agreement to the extent that such Gas would constitute Dedicated Gas hereunder; (f) to construct, install, maintain, own and operate any treating and/or conditioning facilities upstream of the SCM GGP System as reasonably necessary to (i) comply with any environmental, legal, or Lease requirements, or (ii) meet the quality specifications of the SCM GGP System set forth in this Agreement and/or the quality specification of any downstream pipeline; (g) to deliver or furnish to Customer’s and its Affiliates’ non-operators or other Persons all Gas that such non-operators or Persons elect to separately take in kind and market; (h) to retain the condensate and other liquid hydrocarbons separated from Dedicated Gas prior to delivery to SCM hereunder by conventional mechanical wellhead separators at ambient temperature pursuant to Section 2.5; (i) to construct, install, maintain, own and operate compression facilities and other methods of uplift upstream of the SCM GGP System; and (j) to retain any and all Gas that is not Dedicated Gas. 2.3 Prior Dedications as of the Effective Date and Subsequently Acquired Leases. (a) Subsequently Acquired Leases. In the event that after the Effective Date hereof Customer and/or any of its Affiliates acquire Leases within the Dedicated Area, then the Dedicated Gas produced and saved from such Leases shall automatically be included within the Dedication; provided, however, if any of the Dedicated Gas produced from such Leases is subject to a Prior Dedication, then such Dedicated Gas shall be excluded from the Dedication, to the extent and only to the extent of such Prior Dedication, until such Prior Dedication expires or terminates. In the event that any such Prior Dedication expires or terminates, then 4

Execution – Option Agreement the Dedicated Gas subject to such Prior Dedication shall, to the extent not already subject to the Dedication, automatically be included within the Dedication and subject to this Agreement without any further actions by the Parties. (b) Existing Prior Dedications. Customer represents and warrants to SCM that, as of the Effective Date, except as set forth on Exhibit E attached hereto, none of the Leases owned by Customer and/or its Affiliates within the Dedicated Area are subject to a Prior Dedication. With respect to any such Leases which are subject to a Prior Dedication, Customer shall have the right to comply with such Prior Dedication and the Dedicated Gas produced from such Leases shall be excluded from the Dedication, to the extent and only to the extent of such Prior Dedication, until such Prior Dedication expires or terminates. In the event that any such Prior Dedication expires or terminates, then the Dedicated Gas subject to such Prior Dedication shall, to the extent not already subject to the Dedication, automatically be included within the Dedication and subject to this Agreement without any further actions by the Parties. 2.4 Covenant Running With the Land. So long as this Agreement is in effect, this Agreement shall (i) be a covenant running with the Leases now owned or hereafter acquired by Customer and/or its Affiliates within the Dedicated Area (including, without limitation, all Wells operated by Customer or its Affiliates) and (ii) be binding on and enforceable by SCM and its successors and assigns against Customer, its Affiliates and their respective successors and assigns. Notwithstanding this Section 2.4, to the extent all or a portion of such Leases within the Dedicated Area are sold to a non-Affiliated Person, such acquiring Person shall only be required to dedicate for delivery hereunder that Gas that is produced from such Leases within the Dedicated Area acquired by such non-Affiliated Person from Customer. The acquiring Person shall not be required to dedicate Gas produced from Leases already held by or acquired after such date by such acquiring Person. Notwithstanding the foregoing, with prior written notice to SCM, Customer and its Affiliates shall each be permitted to convey, sell, assign, or otherwise transfer its interest in the Leases that are not connected to or in the process of being connected to the SCM GGP System free of the Dedication hereunder in an “acreage swap” or exchange transaction in which such undeveloped Leases within the Dedicated Area are exchanged for other properties or Leases of approximately equal net acreage and projected production located in the Dedicated Area that are not subject to a Prior Dedication and would become subject to the Dedication hereunder. SCM and Customer shall prepare, execute, acknowledge, deliver, and record any such instruments and other documents reasonably necessary to effectuate such release and memorialize such acquired Leases subject to the Dedication. 2.5 No Upstream Processing. Customer shall not remove or permit to be removed any Plant Products from the Dedicated Gas prior to delivery to SCM; provided that Customer may cause or allow the Dedicated Gas to be separated by means of a conventional ambient mechanical wellhead gas-oil separator prior to its delivery to SCM and the liquid constituents separated from such Dedicated Gas therefrom shall not be subject to this Agreement. SCM has agreed to receive and gather 5

Execution – Option Agreement Dedicated Gas hereunder for the principal purpose of extracting from such Dedicated Gas Plant Products that may be extracted at the Plant, and accordingly, as part of the Dedication, Customer grants to SCM the exclusive right to process Customer’s Dedicated Gas received at the Receipt Points. 2.6 Receipt Points; Drilling Plans (a) In order to assist SCM in planning for future facilities which SCM may install under this Agreement following the Effective Date, every six (6) Months during the Term, Customer shall provide to SCM copies of its current drilling plan(s) with respect to the Dedicated Area. Customer shall provide SCM with an update to its drilling plan(s) promptly following any material change to a plan previously provided to SCM. Each drilling plan and any associated updates provided to SCM by Customer of the drilling plan(s) shall include (i) the name and location of any new potential Receipt Point, (ii) Customer’s estimate of the spud date, completion date and date of first production with respect to each new Well(s) associated with such new potential Receipt Point, and (iii) Customer’s good faith estimate of the average daily volume from such new potential Receipt Point. (b) If, at any time after the Effective Date, Customer desires that a new Receipt Point for any Well(s) located within the Dedicated Area be connected to the SCM GGP System, Customer shall provide written notice to SCM for new Receipt Points associated with Dedicated Gas setting forth the expected date of first flow to SCM (the “Notification Date”), location and volume profile for such Receipt Point in the form attached hereto as Exhibit G (a “New Receipt Point Notification”). Following SCM’s receipt of a New Receipt Point Notification, SCM shall promptly commence and diligently conduct all reasonable operations at SCM’s sole cost and expense necessary to extend the existing SCM GGP System to each such new Receipt Point described in such New Receipt Point Notification that Customer desires to be connected to the SCM GGP System by the later of (i)(A) for a new Receipt Point that is within two (2) miles of the existing SCM GGP System and does not require BLM approval to be connected to the SCM GGP System, one hundred twenty (120) Days after SCM’s receipt of the applicable New Receipt Point Notification, or (B) for a new Receipt Point that is either more than two (2) miles from the existing SCM GGP System and/or requires BLM approval to be connected to the SCM GGP System, one hundred eighty (180) Days after SCM’s receipt of the applicable New Receipt Point Notification, and (ii) the Notification Date (each such date, a “Target RP In-Service Date”). (c) If SCM fails or is unable to connect any such additional Receipt Point by the applicable Target RP In-Service Date for any reason, then the Dedicated Gas associated with such Receipt Point and the affected Well(s) and Lease(s) to which such Dedicated Gas is attributable shall be temporarily released from the Dedication until such time as such Receipt Point is connected. (d) In addition to Customer’s release rights set forth in Section 2.6(c) above, if SCM fails or is unable to connect any such additional Receipt Point by the date that is thirty (30) Days beyond the applicable Target RP In-Service Date for any reason other than Force Majeure, then, for each Day of unexcused delay until SCM connects such additional Receipt Point beyond the Target RP In-Service Date, SCM shall temporarily reduce the Service Fees payable in 6

Execution – Option Agreement Section 3.1 by fifty percent (50%) for Dedicated Gas delivered to such additional Receipt Point for only a period of time equal to the amount of Days from the deadline set forth in the first sentence of this Section 2.6(d) until the date such additional Receipt Point is connected; provided, however, on the first Day after the expiration of such period of time, Customer’s Service Fees will be increased to the Service Fees set forth in Section 3.1. By means of example, if SCM connects a requested Receipt Point fifty (50) Days after the Target In-Service Date for such additional Receipt Point, and such delay is not due to an event of Force Majeure, then the reduction in Customer’s Service Fees described in the preceding sentence would apply to Dedicated Gas received at such additional Receipt Point for the first twenty (20) Days after such additional Receipt Point is connected. (e) Notwithstanding anything in this Section 2.6 to the contrary, if SCM fails or is unable to connect any such additional Receipt Point by the date that is (i) ninety (180) Days beyond the applicable Target RP In-Service Date for any reason other than Force Majeure or (ii) two hundred seventy (270) Days beyond the applicable Target RP In-Service Date due to Force Majeure, then Customer shall have the right, immediately following such period, to request and receive a permanent release from SCM of the affected Lease(s) and Well(s) delivering to such additional Receipt Point (including the volumes of Gas associated therewith). Customer acknowledges that the rights and remedies set forth in this Section 2.6 shall be its sole and exclusive remedies in the event of SCM’s failure to timely connect a requested additional Receipt Point. (f) In the event that SCM completes an interconnection requested by Customer and paid for by SCM for any new Receipt Point, and after one hundred eighty (180) Days following the date of completion of any such Receipt Point, Customer has not used the additional Receipt Point for any reason other than Force Majeure, then Customer shall reimburse any and all reasonable and documented out-of-pocket costs, expenses or fees incurred by SCM related to the connection of such Receipt Point to the SCM GGP System (but excluding trunklines, compressors or other facilities located downstream of the lateral gathering lines constructed to connect such Receipt Point); provided that (i) Customer shall not be required to reimburse such costs, expenses or fees in the event SCM is otherwise utilizing the installed pipelines and related equipment in a manner that is not reasonably expected to result in lost profits or additional costs beyond the amounts anticipated for connecting the applicable additional Receipt Point to the SCM GGP System, (ii) SCM shall prepare and deliver to Customer an itemized invoice of such costs, fees and expenses, which total amount shall be reimbursed by Customer in equal Monthly installments over a five (5) year period, with the first such installment due within thirty (30) Days of receipt of SCM’s invoice, and (iii) in the event Customer reimburses SCM for all or a portion of such costs, fees and expenses and, subsequently, such additional Receipt Point is later used by Customer to deliver Dedicated Gas hereunder, then Customer shall receive a credit, equal to the total or partial amount of such costs, fees and expenses so reimbursed by Customer, towards the payment of the amounts that would be due from Customer to SCM hereunder for the delivery of such Dedicated Gas at such new Receipt Point. 7

Execution – Option Agreement 2.7 Non-Dedicated Gas. Subject to the terms and conditions of this Agreement, SCM shall provide Services for Customer’s Non-Dedicated Gas on an interruptible basis for the fees described in Article III of this Agreement. ARTICLE III FEES 3.1 Service Fees. Customer shall pay the following fees to SCM each Month (the fees set forth in this Section 3.1, collectively, as adjusted as provided herein, the “Service Fees”): (a) Low Pressure Gathering Fee: for all Gas delivered at the Low Pressure Receipt Points, a gathering fee of fifteen cents ($0.15) per MMbtu (the “Low Pressure Gathering Fee”). (b) Compression Fee: for all Gas delivered at the Low Pressure Receipt Points, a compression fee of seven cents ($0.07) per Mcf for each stage of compression (the “Compression Fee”). (c) High Pressure Gathering Fee: for all Gas delivered at the High Pressure Receipt Points, a gathering fee of ten cents ($0.10) per MMbtu (the “High Pressure Gathering Fee”). (d) Processing Fee: for all Gas delivered at the Receipt Points, a processing fee of twenty seven cents ($0.27) per MMbtu (the “Processing Fee”). (e) H2S Treating: Should Gas contain the levels of hydrogen sulfide (H2S) content set forth below, then Customer shall pay the following treating fee (the “H2S Treating Fee”: (i) If the H2S content of any Gas delivered at a Receipt Point contains in excess of 4 and up to 50 ppm of H2S, then the H2S Treating Fee for all Gas delivered to such Receipt Point during the applicable Month of measurement shall be five cents ($0.05) per Mcf. (ii) If the H2S content of any Gas delivered at a Receipt Point contains in excess of 50 and up to 250 ppm of H2S, then the H2S Treating Fee for all Gas delivered to such Receipt Point during the applicable Month of measurement shall be ten cents ($0.10) per Mcf. (iii) If the H2S content of any Gas delivered at a Receipt Point contains in excess of 250 and up to 1,000 ppm of H2S, then the H2S Treating Fee for all delivered to such Receipt Point during the 8

Execution – Option Agreement applicable Month of measurement shall be fifteen cents ($0.15) per Mcf. (iv) If the H2S content of any Gas delivered at a Receipt Point contains in excess of 1,000 ppm of H2S, then the H2S Treating Fee for all delivered to such Receipt Point during the applicable Month of measurement shall be seventeen cents ($0.17) per Mcf. (f) CO2 Treating: Should SCM accept Gas hereunder that exceeds the maximum carbon dioxide (CO2) content in the Specifications, then Customer shall pay a treating fee (the “CO2 Treating Fee”) equal $0.04 per Mcf for each one (1.00) mole % of CO2 that such Gas exceeds the CO2 specification; provided, however, the CO2 Treating Fee Customer will pay SCM in this Section 3.1(f) will not be less than $0.04 per Mcf and no greater than $0.14 per Mcf. For example, if Customer’s CO2 Mole % at the Receipt Point was 4.60% and the CO2 specification was 3.00 mole %, the Gas would exceed the specification by 1.60% and the fee would be $.064 per Mcf. 3.2 Treating Fuel. In the event SCM operates an amine treater or such other facilities as may be necessary or desirable for purposes of treating Customer’s Gas in accordance with Section 3.1(e) or 3.1(f), then any fuel utilized by SCM for such purposes shall be allocated to Customer based on actual usage (such quantity, the “Treating Fuel Amount”). 3.3 Escalation. Beginning on the first January 1st following two (2) years after the “Effective Date” as defined in the Option Agreement, each of the Service Fees and the T&F Deduction shall be adjusted upward or downward each year by the change in the PPI for the prior year. For purposes of this Section 3.3, the PPI shall be calculated as a fraction, the numerator of which is the PPI for the then current year, and the denominator of which is the PPI for the previous year. Notwithstanding the foregoing, in no event shall the foregoing PPI adjustment result in any of the Service Fees or the T&F Deduction being (i) increased or decreased more than two percent (2%) in any calendar year or (ii) reduced to an amount less than the original amount set forth in this Agreement as of the Effective Date. ARTICLE IV PROCESSING SETTLEMENT; ADDITIONAL CONSIDERATION 4.1 Products Purchase. (a) Subject to the exercise of the Residue Gas In-Kind Option under Section 4.1(c) and the other terms and conditions of this Agreement, SCM shall acquire and take title to the Residue Gas at the Receipt Point. As consideration for the acquisition of Residue Gas that is not taken in-kind pursuant to Section 4.1(c), SCM shall pay Customer an amount equal to the quantity of Customer’s Residue Gas, multiplied by the applicable Residue Gas Price. 9

Execution – Option Agreement (b) Subject to the terms and conditions of this Agreement, SCM shall acquire and take title to the Plant Products at the Receipt Point. As consideration for the acquisition of Plant Products, SCM shall pay Customer an amount equal to the Settled Gallons of each Plant Product, multiplied by the applicable Plant Products Index Price, less T&F Deduction. (c) Notwithstanding Section 4.1(a), Customer shall have the option, exercisable upon at least sixty (60) Days’ prior written notice, to take delivery of its Residue Gas in-kind at the Residue Gas Delivery Points (or at such other delivery point as may be mutually agreed by the Parties) for a six (6) Month period commencing on the earlier of April 1st or October 1st of any calendar year (the “Residue Gas In-Kind Option”). During any such six (6) Month period that the Residue Gas In-Kind Option is in effect, SCM shall deliver Residue Gas to Customer at the Residue Gas Delivery Points, and, in connection therewith: (i) Customer shall make (or cause to be made) all necessary arrangements for the transportation and marketing of such Residue Gas downstream of the Residue Gas Delivery Points, (ii) Customer shall take (or cause to be taken) Residue Gas ratably seven (7) Days a week by pipeline; (iii) SCM shall not be obligated to provide any storage to Customer or to construct or install any other facilities that Customer may require to take in-kind, (iv) title to such Residue Gas shall remain in Customer or its Affiliates, (v) SCM shall have no obligation other than supplying Residue Gas to the Residue Gas Delivery Points for delivery to Customer or for Customer’s account, (vii) Customer shall pay SCM for all actual applicable third-party transport tariffs incurred by SCM for Residue Gas taken in kind, and (v) Customer shall be subject to the nomination and balancing procedures pursuant to Article VII of the General Terms and Conditions. SCM shall continue to deliver such Residue Gas for each successive six (6) Month period thereafter, until such time as Customer elects for SCM to purchase such Residue Gas pursuant to Section 4.1(a) by providing written notice to SCM at least sixty (60) Days prior to the end of the then-current six (6) Month period that the Residue Gas In-Kind Option is in effect, provided that transportation is available at that time. Customer acknowledges that capacity may not be available based on market conditions. Customer acknowledges and agrees that it shall be solely responsible for all royalty payments, Taxes, severance payments, and production payments and any other payments due or owing on Residue Gas taken in-kind. 4.2 Processing Mode Election. At least thirty (30) Days’ prior to (i) the first Month in which Customer’s Dedicated Gas is to be delivered hereunder, and (ii) the first Day of each successive six (6) consecutive Month period, Customer shall notify SCM in writing of Customer’s election to have Customer’s Settled Gallons determined using either Full Recovery Mode or Ethane Rejection Mode. Such election shall remain in effect for a period of six (6) Months. Should Customer fail to make a timely election, Customer shall be deemed to have elected to continue the mode that is in place for the immediately preceding six (6) Month period. Notwithstanding Customer’s election pursuant to this Section 4.2, SCM shall not be required to operate its facilities in any particular recovery mode; however, if SCM operates in a recovery mode other than the mode elected by Customer, 10

Execution – Option Agreement Customer shall be paid based on the recovery mode elected or deemed elected by Customer for the applicable six (6) Month period. ARTICLE V NOTICES 5.1 Addresses. All notices provided for herein shall be in writing at the addresses listed below or to such other address either Party shall designate by written notice. Such notices shall be sent by certified U.S. mail, return receipt requested, postage prepaid, by electronic mail, or by courier. Notices sent by certified mail or courier shall be deemed provided upon delivery as evidenced by the receipt of delivery. Notices sent by electronic mail shall be deemed to have been provided upon the sending Party’s receipt of a non-automated response from the recipient or automatic read receipt generated from the recipient’s electronic mail provider. To Customer: Notices and Correspondence: Lilis Energy, Inc. 300 E. Sonterra Blvd, Suite 1220 San Antonio, TX 78258 Attention: Accounting and Operations Telephone: 210-999-5400 Facsimile 210-999-5401 With a copy to: RDP Producer Services, LLC 10300n Town Park, Suite SE1000 Houston, TX 77072 Attn: David Lipp Fax: 281-849-8911 Email: dlipp@republicpartnersllc.com Billing: Lilis Energy, Inc. 300 E. Sonterra Blvd, Suite 1220 San Antonio, TX 78258 Attention: Patrick Tumer Telephone: 817-502-1635 Facsimile: 210-999-5401 Email: AP@Lilisenergy.com 11

Execution – Option Agreement For Payments: Bank Name: Wells Fargo Bank Account Name: Lilis Energy, Inc. Account Number: 3932368149 ABA: 121000248 To SCM: Salt Creek Midstream, LLC 20329 State Highway 249 Floor 4 Houston, TX 77070 Attn: Paul Williams Email: paul.williams@armenergy.com With a copy to: Salt Creek Midstream, LLC 20329 State Highway 249 Floor 4 Houston, TX 77070 Attn: Contract Administration Email: contracts@armenergy.com For Payments: Bank Name: Iberia Bank ABA No.: 265270413 Account No.: 20001242180 ARTICLE VI TERM; TERMINATION 6.1 Term. Subject to the terms and conditions contained herein, this Agreement shall be in full force and effect as of the Effective Date and shall continue in full force and effect for a period of twelve (12) years thereafter (the “Primary Term”), unless terminated in accordance with Section 6.2 of the Agreement or as otherwise provided herein, and for successive one (1) year periods thereafter until terminated by either Party as of the end of the Primary Term or any subsequent renewal by giving the other Party at least sixty (60) Days’ prior written notice (the Primary Term, including any such extension, the “Term”). However, such termination shall not extinguish any obligations incurred prior to the effective date of termination, including payment for services rendered or for Gas and/or Plant Products purchased hereunder. Notwithstanding anything in this Agreement to the contrary, the obligations of Customer hereunder, including, without limitation, the obligation to deliver Dedicated Gas, shall be subject to the satisfaction, or waiver by Customer, of the following condition precedent: SCM shall have as of the Effective Date installed all infrastructure necessary to receive and provide Services with 12

Execution – Option Agreement respect to all Dedicated Gas (including the connection of all necessary Receipt Point(s)) being produced from Well(s) existing as of the Effective Date, and is ready and able to provide in full such Services with respect to such Dedicated Gas. To the extent that such condition precedent is not satisfied as of the Effective Date, Customer shall have the right, without any liability to Customer, to terminate this Agreement. 6.2 Default; Termination for Cause. Subject to the terms and conditions contained herein, if either Party shall (a) make an assignment or any general arrangement for the benefit of creditors; (b) fail to make, when due, any payment required herein (which failure is not cured within five (5) Days after the defaulting Party’s receipt of written notice thereof); (c) otherwise fail to perform any material covenant herein when such performance is due (which failure is not excused by Force Majeure or remedied within sixty (60) Days after the defaulting Party’s receipt of written notice thereof); (d) file a petition or otherwise commence, authorize, or acquiesce in the commencement of a proceeding or cause under any bankruptcy or similar Law for the protection of creditors or have such petition filed or proceeding commenced against it; (e) otherwise become bankrupt or insolvent (however evidenced); or (f) be unable to pay its debts as they fall due, then in addition to any and all other remedies available hereunder, at law, and in equity, the non-defaulting Party shall have the right to suspend performance and/or terminate this Agreement, (1) immediately and without notice in the case of a default described in clause (a), clause (d), clause (e), or clause (f), or (2) upon the expiration of the applicable cure period in the case of a default described in clause (b), clause (c), or clause (g), and pursue such other remedy or remedies as may be available to it under this Agreement (including, without limitation, exercising the rights of recoupment, setoff, offset, deduction, liquidation, and/or enforcement or realization of any security held pursuant to this Agreement, or the drawing on of any letter of credit held pursuant to this Agreement), at Law or in equity. 6.3 Bankruptcy Savings. Without limiting the applicability of any other provision of the Bankruptcy Code (including without limitation Sections 362, 546, 553, 556, 560, 561 and 562 thereof and the applicable definitions in Section 101 thereof), the Parties acknowledge and agree that: (i) this Agreement and all transactions entered into hereunder constitute “forward contracts” and/or “swap agreements” and this Agreement constitutes a “master netting agreement” as defined in Section 101 of the Bankruptcy Code; (ii) each Party is a “master netting agreement participant,” a “forward contract merchant” and/or a “swap participant” as defined in the Bankruptcy Code; (iii) the rights of the Parties under Section 6.2 of this Agreement constitute “contractual rights” to liquidate, terminate or accelerate, as applicable, this Agreement and the transactions entered into hereunder; (iv) any margin or collateral provided hereunder, or under any margin, collateral, security, or similar agreement related hereto and all payment obligations of any Party to the other hereunder constitute a “margin payment” or a “settlement payment” as defined in Section 101 of the Bankruptcy Code; and (v) the Parties are entitled to the rights under, and protections afforded by, Sections 362, 546, 553, 556, 560, 561 and 562 of the Bankruptcy Code. 13

Execution – Option Agreement ARTICLE VII CONFIDENTIALITY 7.1 Confidential Information. (a) From and after the Effective Date, each Party shall hold, and shall cause its Representatives to hold all Confidential Information of the other Party in strict confidence, with at least the same degree of care that it applies to such Party’s confidential and proprietary information and shall not use such Confidential Information except in connection with its performance or acceptance of services hereunder and shall not release or disclose such Confidential Information to any other Person, except its Representatives. Each Party shall be responsible for any breach of this Section 7.1 by any of its Representatives. For purposes of this Agreement, “Representatives” means each Party’s Affiliates and its and their respective directors, managers, officers, employees, agents, consultants, legal advisors and accountants who (i) need to know such information, (ii) are informed of the existence of this Agreement and its restrictions on the disclosure and use of Confidential Information, and (iii) are bound by employment, consulting or similar agreements restricting the disclosure and use of such information comparable to and no less restrictive than those set forth herein or otherwise agree to be bound by the confidentiality terms of this Agreement to the same extent as if they were parties hereto. (b) If a Party receives a subpoena or other demand for disclosure of Confidential Information received from any other Party or must disclose to a governmental authority any Confidential Information received from such other Party in order to obtain or maintain any required governmental approval, the receiving Party shall, to the extent legally permissible, provide notice to the providing Party before disclosing such Confidential Information. Upon receipt of such notice, the providing Party shall promptly either seek an appropriate protective order, waive the receiving Party’s confidentiality obligations hereunder to the extent necessary to permit the receiving Party to respond to the demand, or otherwise fully satisfy the subpoena or demand or the requirements of the applicable governmental authority. If the receiving Party is legally compelled to disclose such Confidential Information or if the providing Party does not promptly respond as contemplated by this Section 7.1, the receiving Party may disclose that portion of Confidential Information covered by the notice or demand. (c) Notwithstanding anything in this Section 7.1 to the contrary, either Party may disclose Confidential Information to any bona fide potential purchaser, investor, partner, lender or source of financing and their directors, managers, officers, employees, agents, consultants, legal advisors and accountants; provided that they: (i) need to know such information, (ii) are informed of the existence of this Agreement and its restrictions on the disclosure and use of Confidential Information, and (iii) are bound by an agreement restricting the disclosure and use of such information comparable to and no less restrictive than those set forth 14

Execution – Option Agreement herein or otherwise agree to be bound by the confidentiality terms of this Agreement to the same extent as if they were parties hereto. [Signature page follows] 15

Execution – Option Agreement IN WITNESS WHEREOF, this Agreement is executed by the duly authorized representatives of the Parties as of the Effective Date. Lilis Energy, Inc. By: Name: Title: Salt Creek Midstream, LLC By: Name: Title: [Signature Page to Gas Purchase Agreement]

Execution – Option Agreement GENERAL TERMS AND CONDITIONS TO THE GAS PURCHASE AGREEMENT BETWEEN Lilis Energy, Inc. (“Customer”) AND Salt Creek Midstream, LLC (“SCM”) Dated Effective as of August 11, 2027

Execution – Option Agreement TABLE OF CONTENTS ARTICLE I DEFINITIONS .......................................................................................................... 1 1.1 Defined Words and Terms ........................................................................................... 1 1.2 Other Definitional Provisions ...................................................................................... 8 ARTICLE II OPERATION OF THE SYSTEM ............................................................................ 9 2.1 Curtailment .................................................................................................................. 9 2.2 Identity of Gas ............................................................................................................ 11 2.3 Operation of Facilities. ................................................................................................ 11 2.4 Rights of Way .............................................................................................................12 ARTICLE III TAXES .................................................................................................................. 12 3.1 General ....................................................................................................................... 12 3.2 Royalties and Taxes ....................................................................................................13 ARTICLE IV TITLE AND CUSTODY TRANSFER AND RESPONSIBILITY ...................... 13 4.1 Title, Custody and Risk of Loss ..................................................................................13 4.2 Indemnity ................................................................................................................... 13 ARTICLE V MEASUREMENT ................................................................................................. 14 5.1 Unit of Volume .......................................................................................................... 14 5.2 Adjustment for Supercompressibility ........................................................................ 14 5.3 Determination of Heating Value, Gas Composition and GPM ...................................14 ARTICLE VI MEASURING EQUIPMENT AND TESTING ....................................................15 6.1 Equipment .................................................................................................................. 15 6.2 Calibration and Tests of Meters ..................................................................................15 6.3 Access to Meters and Records ....................................................................................15 6.4 Correction of Metering Errors .................................................................................... 16 6.5 Low Volume Meter Fee ............................................................................................. 16 6.6 Failure of Meters ........................................................................................................ 16 6.7 Modifications to Measurement Procedures ................................................................. 17 6.8 Measurement Disputes ............................................................................................... 17 ARTICLE VII TAKE-IN-KIND SCHEDULING; NOMINATION; IMBALANCES ................17 ARTICLE VIII GAS QUALITY ................................................................................................. 17 8.1 Specifications ............................................................................................................. 17 8.2 Failure to Meet Specifications; Blending and Conditioning ...................................... 18 ARTICLE IX PRESSURE ........................................................................................................... 20 ARTICLE X ACCOUNTING ..................................................................................................... 20 10.1 Payment.................................................................................................................... 20 10.2 Information .............................................................................................................. 21 i

Execution – Option Agreement 10.3 Audits ........................................................................................................................21 10.4 Certain Pricing ......................................................................................................... 21 10.5 Setoff ........................................................................................................................ 21 10.6 Adequate Assurances ................................................................................................22 ARTICLE XI WARRANTY AND INDEMNIFICATION ......................................................... 22 11.1 Warranty of Title; Indemnity ................................................................................... 22 11.2 Limitation of Liability ............................................................................................. 23 ARTICLE XII FORCE MAJEURE ............................................................................................. 23 12.1 Definition ................................................................................................................. 23 12.2 Strikes and Lockouts .................................................................................................24 ARTICLE XIII SUCCESSORS AND ASSIGNS ....................................................................... 24 13.1 Successors and Assigns .............................................................................................24 13.2 Assignments ..............................................................................................................24 ARTICLE XIV MISCELLANEOUS .......................................................................................... 25 14.1 Federal Jurisdiction ...................................................................................................25 14.2 No Waiver of Defaults ..............................................................................................26 14.3 Joint Preparation of This Agreement ....................................................................... 26 14.4 Headings .................................................................................................................. 26 14.5 Governing Law; Venue; Waiver of Jury Trial ......................................................... 26 14.6 Use of Third Party Processing Facilities ...................................................................26 14.7 Survival .....................................................................................................................26 14.8 Counterparts ............................................................................................................. 27 14.9 Entire Agreement ..................................................................................................... 27 14.10 Modifications in Writing .........................................................................................27 14.11 No Third Party Beneficiaries ................................................................................. 27 14.12 Liquidated Damages .............................................................................................. 27 ii

Execution – Option Agreement GENERAL TERMS AND CONDITIONS ARTICLE I DEFINITIONS All references to Sections or Articles of this Agreement shall refer to Sections and Articles in the main body of the Agreement unless the context specifically reflects that the reference is to an Article or Section of these General Terms and Conditions. 1.1 Defined Words and Terms. Except where the context otherwise indicates another or different meaning or intent, the following words and terms as used herein shall be construed to have the meaning indicated: “Affiliate” means, with respect to a specified Person, another Person that directly, or indirectly through one or more intermediaries, Controls or is Controlled by or is under common Control with the Person specified. “Agreement” means that certain Gas Purchase Agreement dated effective as of August 11, 2027, by and between Customer and SCM. “Bankruptcy Code” means title 11 of the United States Code, 11 U.S.C. §§ 101, et seq., as amended. “Base Conditions” shall mean a standard pressure of 14.73 psia and a standard temperature of 60° F. “BLM” shall mean the Bureau of Land Management and any lawful successor agency thereto. “Btu” means British thermal unit. “Business Day” means any Day other than Saturday, Sunday, or legal holiday for commercial banks under the Laws applicable to national banking associations. “Central Time” means Central Standard Time as adjusted for daylight savings time. “CO2 Treating Fee” has the meaning set forth in Section 3.1(f) of the Agreement. “Compression Fee” has the meaning set forth in Section 3.1(b) of the Agreement. “Confidential Information” means all terms and conditions of this Agreement, and all information disclosed to it by the other Party or obtained by it in the performance of this Agreement and relating to the other Party’s business. Confidential Information shall not, however, include any information which: (a) was publicly known and made generally available in the public domain prior to the time of disclosure by the disclosing Party; (b) becomes publicly known and made generally available after disclosure by the disclosing Party through no action or inaction of the receiving Party; (c) is already in the possession of the receiving Party at the time of disclosure by the disclosing Party; (d) is obtained by 1

Execution – Option Agreement the receiving Party from a third party without a breach of such third party’s obligations of confidentiality; (e) the receiving Party can demonstrate was independently developed by the receiving Party without use of or reference to the disclosing Party’s Confidential Information. “Confirmed Nominations” has the meaning set forth in Exhibit F. “Control” means the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of a Person, whether through the ability to exercise voting power, by contract (or otherwise). “Controlling” or “Controlled” have meanings correlative thereto. “Cubic Foot of Gas” means the volume of Gas contained in one cubic foot of space at Base Conditions. “Customer” has the meaning set forth in the preamble of the Agreement. “Customer Indemnified Parties” means Customer, its successors and assigns, and their respective Affiliates, subsidiaries, shareholders, members, partners, officers, directors, employees, and agents. “Day” or “Daily” means a 24-hour period beginning at 9:00 a.m. Central Time on a calendar day and ending at 9:00 a.m. Central Time on the next succeeding calendar day. “Dedicated Area” means the dedicated area depicted as the “AMI” on the map attached hereto as Exhibit A-1, excluding any interests expressly excluded or released from this Agreement. “Dedicated Gas” has the meaning set forth in Section 2.1 of the Agreement. “Dedication” has the meaning set forth in Section 2.1 of the Agreement. “Effective Date” has the meaning set forth in the preamble of the Agreement. “Ethane Rejection Fixed Recovery Percentages” means the contractual fixed recovery percentage for Plant Product components during Ethane Rejection Mode set forth as follows: Ethane: 20% Propane: 88% Iso-Butane: 98% Normal Butane: 99% Iso Pentane: 99% 2

Execution – Option Agreement “Ethane Rejection Mode” means the operation of the Plant in a mode, whether actual or deemed, that minimizes the recovery of ethane as a component of Plant Products. “Facilities” means the Plant and the SCM GGP System collectively. “FERC” means the Federal Energy Regulatory Commission, and any successor agency having jurisdiction over the services provided by SCM hereunder. “Field FL&U” means the quantity of field fuel utilized for Services plus lost and unaccounted for Gas upstream of the Plant and shall be fixed at five and one-half percent (5.50%) of the quantity, in MMbtu, of Customer’s Gas received and accepted at the Receipt Points. “Fixed Recovery Percentages” means, as applicable, the Full Recovery Fixed Recovery Percentages and the Ethane Rejection Fixed Recovery Percentages. “Force Majeure” is defined in Section 12.1 of these General Terms and Conditions. “Full Recovery Fixed Recovery Percentages” means the contractual fixed recovery percentage for Plant Product components during Full Recovery Mode set forth as follows: Ethane: 90% Propane: 92% Iso-Butane: 98% Normal Butane: 98% Iso Pentane: 99% “Full Recovery Mode” means the operation of the Plant for the maximum recovery of Plant Products. “Gallon” means one (1) U.S. gallon. “Gas” means natural gas produced in its original state from a gas well and/or an oil well. “General Terms and Conditions” has the meaning set forth in Section 1.2 of the Agreement. “GPM” means the quantity of Gallons of theoretically recoverable Plant Products contained in one Mcf of Gas, as calculated from chromatographic analysis and as measured at the Receipt Points. “Gross Heating Value” means the gross number of Btus that would be contained in a volume of one Cubic Foot of Gas as further defined by GPA standard 2172 dry basis at Base Conditions. 3

Execution – Option Agreement “High Pressure Gathering Fee” has the meaning set forth in Section 3.1(c) of the Agreement. “High Pressure Receipt Point” means those Receipt Point(s) delivering into the high pressure portion of the SCM GGP System. “H2S Treating Fee” has the meaning set forth in Section 3.1(e) of the Agreement. “Impaired Party” has the meaning set forth in Section 10.6 of the General Terms and Conditions. “Inferior Liquids” means mixed crude oil, slop oil, salt water, nuisance liquids, and other liquids recovered by SCM in the SCM GGP System. “Insecure Party” has the meaning set forth in Section 10.6 of the General Terms and Conditions. “Inert Constituents” means non-hydrocarbon constituents contained in Gas, including carbon dioxide, oxygen, nitrogen, hydrogen sulfide, water vapor, ozone, nitrous oxide, and mercury. “Law” shall mean any and all constitutional provisions, rules, codes, regulations, statutes, ordinances, enactments, judicial and administrative orders, decrees, standards, decisions and rulings that are adopted, enacted, promulgated or issued by any federal, state, municipal, parish or tribal governmental authority, including the common law. “Leases” means any lease, mineral interest, working interest, net profit interest, royalty or overriding royalty, fee right, mineral servitude, license, concession or other right covering Gas and related hydrocarbons or an undivided interest therein or portion thereof within the Dedication Area, along with rights to drill for, produce and dispose of Gas and liquid hydrocarbons or other substances, in and under the lands covered thereby. “Level One Service” has the meaning set forth in Section 2.1(b) of the General Terms and Conditions. “Level Two Service” has the meaning set forth in Section 2.1(b) of the General Terms and Conditions. “Losses” means any actual losses, costs, expenses, liabilities, damages, demands, suits, sanctions, causes of action, claims, judgments, liens, fines or penalties, including court costs and reasonable attorneys’ fees. “Low Pressure Gathering Fee” has the meaning set forth in Section 3.1(a) of the Agreement. “Low Pressure Receipt Point” means those Receipt Point(s) delivering into the high pressure portion of the SCM GGP System, where SCM is providing compression services. 4

Execution – Option Agreement “Low Volume Meter Fee” has the meaning set forth in Section 6.5 of the General Terms and Conditions. “MAOP” means the maximum allowable operating pressure in psig at the Receipt Points in effect from time to time, as set forth in notices from SCM to Customer, which shall be 1440 psig initially. “Mcf” means one thousand cubic feet of Gas at Base Conditions. “Measurement Expert” has the meaning set forth in Section 6.8 of the General Terms and Conditions. “MMBtu” means one million British thermal units. “Mont Belvieu OPIS Index” means for each Plant Product the Monthly average of the daily average of the high and low prices per gallon for such Plant Product, for such Month, as quoted by the Oil Price Information Service in the OPIS-North America LPG Report for “Any Current Month” under “OPIS Mont Belvieu Spot Gas Liquids Prices” using (i) the Non-TET prices for propane, iso-butane, normal butane, and natural gasoline; and (ii) the purity ethane price for ethane. “Month” means a period beginning at 9:00 a.m. Central Time on the first Day of a calendar month and ending at 9:00 a.m. Central Time on the first Day of the next succeeding calendar month. “New Receipt Point Notification” has the meaning set forth in Section 2.6(b) of the Agreement. “Non-Dedicated Gas” means Gas that is not subject to the Dedication. “Notification Date” has the meaning set forth in Section 2.6(b) of the Agreement. “OBA” has the meaning set forth in Exhibit F. “Option Agreement” means that certain Option Agreement by and between SCM, as “SCM,” and Customer, as “Lilis,” dated as of May 21, 2018. “Parties” or “Party” has the meaning set forth in the preamble of the Agreement. “Permitted Curtailment” has the meaning set forth in Section 2.1(a) of the General Terms and Conditions. “Person” means any individual, corporation, partnership, limited liability company, joint venture, association, joint-stock company, trust, enterprise, unincorporated organization, governmental entity or other entity having legal capacity. “Plant” means any Gas processing plant currently owned or subsequently installed by SCM, Plant Products interconnection, any Residue Gas interconnection that is 5

Execution – Option Agreement subsequently installed, and all related storage facilities, owned and operated by SCM, for the Services hereunder. “Plant FL&U” means the quantity of Gas in Mcf utilized as fuel in the operation of the Plant and shall include any lost and unaccounted for and flared gas, and shall be fixed at two and one-quarter percent (2.25%) of the quantity, in MMbtu, of Customer’s Gas received and accepted at the Receipt Points. “Plant Inlet Volume” means the volume in Mcf of Customer’s Gas received and accepted at the Receipt Points less Field FL&U, Treating Shrinkage and any Treating Fuel Amount. “Plant Products” means the liquefiable hydrocarbons that SCM removes and recovers from Gas, including ethane, propane, normal butane, iso-butane and natural gasoline, and/or any mixture thereof. “Plant Products Delivery Points” means those points of delivery for third party sales of Plant Products set forth on Exhibit D-2, as the Parties may mutually agree to modify from time to time. “Plant Products Index Price” means one hundred percent (100%) of the Monthly average of the applicable Mont Belvieu OPIS Index price(s) received by SCM for each component of Plant Product. “Plant Shrinkage” means the decrease in Customer’s Gas volume as adjusted for heating content that results from the conversion of liquefiable hydrocarbons in the Gas into Plant Products utilizing the standards set forth in Article V of the General Terms and Conditions, and shall be based on the applicable Fixed Recovery Percentages. “PPI” means the Producer Price Index by Commodity for Final Demand: Finished Goods, Seasonally Adjusted (Series Id: WPSFD49207), as published by the United States Department of Labor, Bureau of Labor Statistics; provided, however, (i) if the Bureau of Labor Statistics ceases to publish such index, the PPI shall mean a comparable index selected by SCM and reasonably acceptable to Customer, and (ii) if the applicable governmental agency or other entity that publishes or issues such index changes the base year for such index or the manner in which such index is calculated, then determination of adjustments pursuant to this Agreement that are based on comparative values of such index shall be made using values for such index that are calculated using the same base year and the same methodology for each index value used in such comparison. “Primary Term” has the meaning set forth in Section 6.1 of the Agreement. “Prior Dedication” means any gathering or processing agreement or any commitment or arrangement (including any volume commitment) that would require or necessitate Dedicated Gas to be gathered on any gathering system or similar system other than the SCM GGP System or for Dedicated Gas to be processed anywhere other than at the Plant. “Processing Fee” has the meaning set forth in Section 3.1(d) of the Agreement. 6

Execution – Option Agreement “psia” means pounds per square inch absolute. “psig” means pounds per square inch gauge. “Qualified Institution” means the domestic office of a commercial bank or trust company that is not an Affiliate of either Party and that has assets of at least $10 billion and an investment-grade credit rating as established by Standard and Poor’s and Moody’s. “Receipt Points” means the furthest upstream flange on the SCM GGP System where Customer delivers Dedicated Gas to SCM and where SCM receives Customer’s Gas in accordance with the terms of this Agreement, which shall be described on Exhibit B following such agreement. The Parties shall update Exhibit B from time to time to reflect the addition of new Receipt Points. “Representatives” has the meaning set forth in Section 7.1(a) of the Agreement. “Residue Gas” means the total quantity of Customer’s Gas measured, received and accepted each Month at the Receipt Point, less Plant Shrinkage, Field FL&U and Plant FL&U. “Residue Gas Delivery Points” means those points of delivery for third party sales of Residue Gas set forth on Exhibit D-1, as the Parties may mutually agree to modify from time to time. “Residue Gas Price” means, with respect to any Month, the Monthly average of applicable “Midpoint” price of Gas, for such Day, in dollars per MMBtu, as reported in the applicable issue of Gas Daily (an S&P Global Platts publication), in the table entitled “Daily Price Survey ($/MMBtu),” in the section entitled “Southwest,” on the row entitled “Waha” (IGBAD21), less Customer’s pro-rata share of any transportation fees, retention of fuel or other fees incurred by SCM under arms-length transactions with un-Affiliated third parties to deliver Customer’s Residue Gas to its ultimate sales point at or near the Waha hub. “Residue Gas In-Kind Option” has the meaning set forth in Section 4.1(c) of the Agreement. “SCM” has the meaning set forth in the preamble of the Agreement. “SCM GGP System” means the pipelines, compressor stations, gas processing plant and related facilities owned by SCM, or any other pipelines and facilities that SCM uses in performing SCM’s gathering and processing obligations hereunder, including any expansions to those systems during the term of this Agreement. “SCM Indemnified Parties” means SCM, its successors and permitted assigns, and their respective Affiliates, subsidiaries, shareholders, managers, members, partners, officers, directors, employees, representatives, and agents. 7

Execution – Option Agreement “Services” has the meaning set forth in Section 1.1(b) of the Agreement. “Service Fees” has the meaning set forth in Section 3.1 of the Agreement. “Settled Gallons” means the quantity of Plant Products in Gallons recovered in Full Recovery Mode or Ethane Rejection Mode, as applicable, which shall be determined for each Plant Product component by multiplying (x) the Plant Inlet Volume, by (y) the GPM of such Plant Product component contained in the quantities of Customer’s Gas processed hereunder; by (z) the corresponding Fixed Recovery Percentage of such Plant Product. “Specifications” has the meaning set forth in Section 8.1 of the General Terms and Conditions. “Target RP In-Service Date” has the meaning set forth in Section 2.6(b) of the Agreement. “Taxes” means all gross production, severance, conservation, ad valorem and similar or other taxes measured by or based upon production, together with all taxes on the right or privilege of ownership of Gas, or upon the services rendered herein, including gathering, transportation, handling, transmission, dehydration, compression, processing, treating, conditioning, distribution, sale, use, receipt, delivery or redelivery of Gas, including all of the foregoing now existing or in the future imposed or promulgated. “Term” has the meaning set forth in Section 6.1 of the Agreement. “T&F Deduction” means the amount Customer is charged for transportation, fractionation, and marketing deduction, which amount shall be twelve and one-half cents ($0.125) per Gallon of Plant Products, as adjusted as provided herein. “Treating Fuel Amount” has the meaning set forth in Section 3.2 of the Agreement. “Treating Shrinkage” means the decrease in Customer’s Gas volume attributable to the removal of CO2 and H2S in the treating of Customer’s Gas by SCM after the Receipt Points. “Wells” means any well operated by Customer or its Affiliates in which Gas produced therefrom has been dedicated to SCM under this Agreement, whether such well now exists or is hereafter drilled. 1.2 Other Definitional Provisions. In construing this Agreement, the following principles shall be followed: (a) Words that have a well-known technical, trade or industry meaning shall be given that meaning, unless it would conflict with an express provision of this Agreement, in which case the express provision of this Agreement shall control. The section headings in this Agreement have been inserted for the convenience of 8

Execution – Option Agreement the Parties and shall not define, limit or extend interpretation of the corresponding Section, Exhibit or this Agreement. (b) All references to a given agreement, instrument or other document shall be a reference to that agreement, instrument or other document as modified, amended, supplemented and restated through the date as of which such reference is made. (c) All references to any law include any amendment or modification thereof. (d) A reference to a Person includes its successors and permitted assigns. The singular shall include the plural and the masculine shall include the feminine, and vice versa. (e) No consideration shall be given to the fact or presumption that one Party had a greater or lesser hand in drafting this Agreement, and interpretation of this Agreement shall not be construed against either Party. (f) Examples shall not be construed to limit, expressly or by implication, the matter they illustrate. The plural shall be deemed to include the singular and vice versa, as applicable. ARTICLE II OPERATION OF THE SYSTEM 2.1 Curtailment. (a) SCM may, without liability for damages to Customer (but subject to Customer’s release rights hereunder and remedies under this Section 2.1), curtail or interrupt deliveries of Customer’s Dedicated Gas from time to time for (i) safe operation of the Facilities, (ii) events of Force Majeure, (iii) the inability of one or more non- Affiliated downstream carriers to receive Plant Products or Residue Gas, (iv) maintenance or repair to the Facilities with reasonable prior written notice delivered to Customer in accordance with Section 5.1 of the Agreement, or (v) the issuance of an order by a government authority. SCM shall have no liability of any kind to Customer or its Affiliates (but subject to Customer’s release rights hereunder and remedies under this Section 2.1) for any curtailment or interruption of service as provided in this Section 2.1 (each, a “Permitted Curtailment”). SCM shall give Customer at least thirty (30) Days’ advance written notice, except in case of emergency, of its intention to interrupt operations and of the estimated time thereof. (b) For the purposes of services provided by SCM under this Agreement and the curtailment thereof by and on the Facilities, SCM shall offer only two levels of service with dedicated capacity: (1) that level of service that has the highest priority call on capacity of all or any relevant portion of the Facilities (“Level Two Service”), and (2) the service level curtailed prior to Level Two Service (“Level One Service”). The Parties acknowledge that (i) Customer’s volumes of 9

Execution – Option Agreement Dedicated Gas delivered to the Receipt Points are subject to Level Two Service and Customer’s volumes of Non-Dedicated Gas delivered to the Receipt Points are subject to interruptible service, and (ii) all Gas delivered on an interruptible basis is subject to interruption or curtailment at any time, and SCM is contractually entitled to interrupt its performance with respect to any such Gas for any reason and in SCM’s sole discretion. In the event of a Permitted Curtailment or any other curtailment that occurs on the Facilities, SCM shall curtail capacity on the Facilities in accordance with the following: (i) interruptible capacity shall be curtailed in its entirety prior to Level One Service and Level Two Service; (ii) after curtailing interruptible volumes in their entirety, Level One Service shall be curtailed in its entirety prior to curtailing Level Two Service and all capacity at Level One Service shall be curtailed pro rata in accordance with the average, actual quantities of Gas delivered to the Facilities subject to such curtailment during the thirty (30) Days immediately prior to such curtailment; and (iii) all capacity at Level Two Service shall be curtailed pro rata in accordance with the average, actual quantities of Gas delivered to the Facilities subject to such curtailment during the thirty (30) Days immediately prior to such curtailment. To protect Customer’s Level Two Service rights hereunder, SCM agrees that SCM’s total Level Two Service commitments under all contracts with all producers and customers shall not exceed the total capacity of the Facilities. SCM warrants and represents to Customer that Customer’s Priority Two Service is the highest level of service on the Facilities. SCM agrees that during the term of this Agreement, SCM shall neither create a higher level than Priority Two Service nor contract for Priority Two Service gathering and processing in excess of the total capacity of the Facilities during the term of this Agreement. (c) Notwithstanding anything to the contrary set forth herein, if at any time during the Term, SCM suspends, curtails, is unable or fails to receive all volumes of Dedicated Gas hereunder, for more than twenty-four (24) consecutive hours for any reason, including an event of Force Majeure, the affected Well(s) (including the volumes of Gas associated therewith) delivering to the affected Receipt Point(s) where all such volumes of Dedicated Gas are not received shall automatically be temporarily released from this Agreement. This temporary release shall cease, and Customer shall resume deliveries of such temporarily released Dedicated Gas, as soon as Customer, exercising commercially reasonable efforts, can terminate all alternative gathering and/or marketing arrangements without penalty, but in no event later than the first Day of the Month commencing after the passage of ninety (90) Days after SCM has provided Customer written notice that SCM is ready, willing and able to resume receiving the affected volumes of Dedicated Gas. (d) Notwithstanding anything to the contrary set forth herein, if at any time during the Term, SCM suspends, curtails, is unable or fails to receive all volumes of Dedicated Gas (i) for any reason other than an event of Force Majeure, for one hundred twenty (120) consecutive Days or one hundred twenty (120) or more cumulative Days during any consecutive one hundred eighty (180) Day period following the Commencement Date, or (ii) as a result of an event of Force 10

Execution – Option Agreement Majeure, for two hundred seventy (270) consecutive Days or two hundred seventy (270) Days or more cumulative Days during any consecutive three hundred sixty- five (365) Day period following the Effective Date, then Customer shall have the right, immediately following such period, to request and receive a permanent release from SCM of the affected Well(s) and Lease(s) delivering to the affected Receipt Point(s) where all such volumes of Dedicated Gas are not received (including the volumes of Gas associated therewith). (e) Notwithstanding anything to the contrary set forth herein, without limiting any other remedies available to Customer, including temporary or permanent releases, in the event that receipts of Dedicated Gas are curtailed in whole or part or Services hereunder are curtailed for any reason other than a Permitted Curtailment (including as a result of SCM’s failure to maintain pressures pursuant to Article IX), for a period of at least sixty (60) consecutive Days or for sixty (60) Days out of a consecutive one hundred twenty (120) Day period, then for a period equal to one times the number of Days of curtailment, the Service Fee(s) payable by Customer shall be reduced by 50% at the affected Receipt Point(s). (f) Notwithstanding anything to the contrary set forth herein, without limiting any other remedies available to Customer, including temporary or permanent releases, commencing on the first Day of the first Month after Effective Date, in the event that during any six (6) Month period, the downtime period (excluding any downtime attributable to Force Majeure or emergency conditions existing on the Facilities) for all or any portion of Facilities when receipts of Dedicated Gas are curtailed in whole or part or Services hereunder are curtailed during such six (6) Month period is in excess of six and one-half percent (6.5%), then the Service Fee(s) payable by Customer shall be reduced by 50% for the three (3) Month period immediately following such six (6) Month period. 2.2 Identity of Gas. Customer recognizes Customer’s Gas in SCM’s custody may be commingled with third party Gas and that no segregated services are provided, hereunder provided, however, any such commingling of the Customer’s Gas shall not adversely affect the quality of such Customer’s Gas or merchantability of such Customer’s Gas, or limit or reduce SCM’s redelivery obligations hereunder with respect to such Customer’s Gas. 2.3 Operation of Facilities. (a) Except as otherwise expressly provided in this Agreement, SCM shall, at its sole risk, cost and expense, design, construct, maintain and operate SCM’s Facilities, including any and all facilities required to connect each Well to SCM’s Facilities at the Receipt Point(s), as necessary to perform the Services and all its obligations under this Agreement in a good and workmanlike manner in accordance with standards customary in the industry. SCM will design and shall expand, and may add or remove components of SCM’s Facilities, as it determines to be best in its 11

Execution – Option Agreement capacity as a prudent operator, provided that such design and structure are consistent with the full performance of SCM’s obligations and Services hereunder (b) SCM shall at all times be entitled to full and complete operational control of the Facilities, to the extent consistent with SCM’s obligations under this Agreement. SCM shall at all times be entitled to manage, operate and reconfigure the Facilities in its commercially reasonable discretion, to the extent consistent with SCM’s obligations under this Agreement. (c) SCM reserves the right to own, retain, and have the sole right to the proceeds from any sale of all Inferior Liquids and Inert Constituents collected in the Facilities downstream of any Receipt Points, and shall be responsible for paying all costs and expenses with respect to handling and disposing of the same. 2.4 Rights of Way. (a) SCM is responsible, at its sole cost, for the acquisition of rights-of-way, crossing permits, use agreements, licenses, access agreements, leases, fee parcels, and other rights in land necessary to construct, install, own, and operate the Facilities and perform the services contemplated hereunder. (b) Notwithstanding the foregoing, upon SCM’s written request, to the extent that Customer is legally and contractually entitled to do so without the incurrence of cost or expense, Customer shall grant to SCM for purposes of constructing, owning, operating, repairing, replacing and maintaining any portion of the SCM GGP System, a non-exclusive license and right-of-use (including, without limitation, such license or right-of-use encompassed in Customer’s or its Affiliates’ oil and gas leases or other agreements with third parties) over, across and under Customer’s or its Affiliates, Leases as are reasonably necessary for such purposes. Customer shall have no obligation to execute any easements, rights-of-way, and/or other conveyances of real property in connection with the foregoing license and right-of-use. All facilities and other equipment acquired, placed, or installed by SCM for the purposes of this Agreement pursuant to the provisions of this Section 2.4(b), will remain the property of SCM. In the event Customer identifies any issue with such SCM’s facilities on Customer’s or its Affiliates’ Leases, Customer will notify SCM of such issue and SCM and Customer will work collaboratively to remedy the same. SCM shall be responsible for and release, defend, indemnify, and hold the Customer Indemnified Parties harmless from and against any and all Claims and Losses, arising from or relating to SCM’s use of, or operations on, any such non-exclusive license and right-of-use granted by Customer, except to the extent such Claims or Losses are caused by or attributable to the negligence, gross negligence or willful misconduct of any of the Customer Indemnified Parties. Customer shall be responsible for and release, defend, indemnify, and hold the SCM Indemnified Parties harmless from and against any and all Claims and Losses, arising from or relating to Customer’s use of, or operations on, any fee lands, easements, right-of- way, or similar surface access rights owned or maintained by SCM, except to the 12

Execution – Option Agreement extent such Claims or Losses are caused by or attributable to the negligence, gross negligence or willful misconduct of any of the SCM Indemnified Parties. ARTICLE III TAXES 3.1 General. Except with respect to any Taxes assessed against SCM based on the services provided by SCM under this Agreement or SCM’s income, revenues, gross receipts or net worth (including any gas utility Taxes), Customer shall pay and be responsible for all Taxes levied against or with respect to the Customer’s Gas (including all constituents and products thereof) delivered or services provided under this Agreement (excluding all income taxes, franchise Taxes, ad valorem Taxes, and property Taxes of SCM, or other similar Taxes, fees, or assessments imposed by any governmental authority with respect to the Facilities and ownership and operation thereof, the payment of such Taxes being the sole responsibility of SCM). SCM shall not become liable for such Taxes, unless designated to remit those Taxes on behalf of Customer by any duly constituted jurisdictional agency having authority to impose such obligations on SCM, including the Texas Comptroller, in which event the amount of such Taxes remitted on Customer’s behalf shall be (i) reimbursed by Customer upon receipt of invoice, with corresponding documentation from SCM setting forth such payments, or (ii) deducted from amounts otherwise due Customer under this Agreement. 3.2 Royalties and Taxes. As between SCM and Customer, Customer shall at all times have the obligation to account for and pay or cause to be paid all royalties, overriding royalties, Taxes levied against or with respect to Customer’s Gas and other sums due on production and to make settlement with all other Persons having an interest in Customer’s Gas delivered to SCM hereunder. CUSTOMER SHALL INDEMNIFY, DEFEND AND HOLD SCM INDEMNIFIED PARTIES HARMLESS FROM AND AGAINST ALL LOSSES INCURRED BY THE SCM INDEMNIFIED PARTIES ARISING OUT OF OR RELATED TO ANY ROYALTIES, TAXES, PAYMENTS, OR OTHER CHARGES ATTRIBUTABLE TO GAS DELIVERED TO SCM HEREUNDER. ARTICLE IV TITLE AND CUSTODY TRANSFER AND RESPONSIBILITY 4.1 Title, Custody and Risk of Loss. (a) Customer shall have and retain title, custody and risk of loss to all Customer’s Gas and any hydrocarbons attributable thereto, including Plant Products and Residue Gas, upstream of the Receipt Points. SCM shall take title, custody and risk of loss to all such Customer’s Gas and any hydrocarbons attributable thereto, including Plant Products and Residue Gas, at and downstream of the applicable Receipt Points, subject to Customer’s Residue Gas In-Kind Option. To the extent that Customer elects its Residue Gas In-Kind Option, Customer shall retain title to Customer’s Residue Gas and be deemed to be in care, custody and control of 13

Execution – Option Agreement Residue Gas from and after SCM’s redelivery of such Residue Gas at the Residue Gas Delivery Points. 4.2 Indemnity. AS BETWEEN CUSTOMER AND SCM, CUSTOMER SHALL RELEASE, INDEMNIFY, DEFEND AND HOLD HARMLESS THE SCM INDEMNIFIED PARTIES FROM AND AGAINST ALL LOSSES RELATING TO OR ARISING OUT OF (I) THE OPERATIONS OF CUSTOMER, AND (II) THE HANDLING OR DELIVERY OF GAS, RESIDUE GAS AND PLANT PRODUCTS WHILE SUCH GAS IS IN THE CUSTODY AND CONTROL OF CUSTOMER. SUBJECT TO THE TERMS OF THIS AGREEMENT, SCM SHALL RELEASE, INDEMNIFY, DEFEND AND HOLD HARMLESS THE CUSTOMER INDEMNIFIED PARTIES FROM AND AGAINST ALL LOSSES RELATING TO OR ARISING OUT OF (I) THE OPERATIONS OF SCM, AND (II) THE HANDLING OR DELIVERY OF GAS, RESIDUE GAS AND PLANT PRODUCTS WHILE SAME IS IN THE CUSTODY AND CONTROL OF SCM. NOTWITHSTANDING THE FOREGOING, NO PARTY SHALL BE OBLIGATED TO RELEASE, INDEMNIFY, DEFEND OR HOLD THE OTHER PARTY HARMLESS FROM AND AGAINST LOSSES TO THE EXTENT SUCH LOSSES RESULT FROM THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF THE OTHER PARTY. ARTICLE V MEASUREMENT 5.1 Unit of Volume. The unit of volume for measurement of Gas for all purposes shall be one Cubic Foot of Gas at Base Conditions. Where measurement is by orifice meter, all fundamental constants, observations, records and procedures involved in the determination and/or verification of the quantity and other characteristics of Gas delivered hereunder shall be made according to the latest revision of ANSI/API 2530-92 Chapter 14.3, Part 1-4 (AGA Report No. 3), with any revisions, amendments or supplements as may be acceptable to SCM, unless otherwise specified herein. Measurement by ultrasonic meter shall be in accordance with the latest edition of A.G.A. Report No. 9. Where measurement is by other than orifice or ultrasonic meters, standards commonly acceptable in the natural gas industry shall be used in the determination of all factors involved in the computation of Gas volumes. 5.2 Adjustment for Supercompressibility. Adjustment to measured Gas volumes for the effects of supercompressibility shall be made according to accepted AGA standards. Equations for the calculation of supercompressibility will be taken from the latest revision of AGA Report No. 8, Compressibility for Natural Gas and Other Hydrocarbon Gases. 5.3 Determination of Heating Value, Gas Composition and GPM. The Gross Heating Value and Gas composition of the Gas and the GPM of the liquefiable hydrocarbon components shall be determined by the use of a chromatograph or a continuous Gas sampler. The arithmetical average of the hourly Gross Heating Value, Gas composition and GPM, if applicable, recorded by a recording instrument during periods of flow each Day shall be considered as the Gross Heating Value, Gas composition and GPM of the Gas delivered 14

Execution – Option Agreement hereunder during such Day. In the event Gas samples are taken or a continuous Gas sampler is installed, the samples shall be run on a chromatograph at another location. The result of a sample shall be applied to Gas deliveries on the first Day of the Month the sample is removed and for all succeeding Months until a new sample is taken. All Gross Heating Value determinations made with a chromatograph shall use physical Gas constants for Gas compounds as outlined in the latest revision of GPA 2145 or revisions to related reports to which the Parties may mutually agree. Gross Heating Value shall be determined to the nearest whole Btu dry basis at Base Conditions according to GPA Standard 2172. ARTICLE VI MEASURING EQUIPMENT AND TESTING 6.1 Equipment. (a) SCM shall, at its expense, operate, and maintain, or cause to be operated and maintained, in accurate working order, the meters, instruments and equipment of standard type necessary to measure the Gas to be delivered and redelivered hereunder. The metering and other equipment installed, together with any buildings erected for such equipment, shall be and remain the property of SCM. (b) As specified by SCM, all measuring stations provided hereunder shall be equipped with orifice meter runs, orifice meter gauges, recording gauges or other types of meter or meters of standard make and design commonly accepted in the natural gas industry in order to accurately measure the Gas delivered hereunder. A computer, transducers and other associated sensing devices may be installed to accurately measure the Gas delivered hereunder in accordance with A.G.A. Report Nos. 3, 5, 6, 7 and 9, as appropriate, in lieu of mechanical devices with charts. If a computer and associated devices are installed, the values for Gross Heating Value and, specific gravity may be entered either manually (but not more frequently than once per Month) or as real time data if such data is available. Values for the Gas composition, including carbon dioxide and nitrogen used in supercompressibility correction determinations shall be entered as real time data if such data is available or shall be entered manually at intervals mutually agreed upon, but at least once each Month. (c) Gas quality samples shall be taken as may be reasonably required by SCM in its sole discretion. 6.2 Calibration and Tests of Meters. SCM shall calibrate chromatographs, if used, at least once each Month against a standard Gas sample. All meters and other measuring equipment shall be calibrated and adjusted by SCM as deemed necessary. Customer may, at its option, be present for such calibration and adjustment. SCM shall give Customer notice of the time of all tests sufficiently in advance of conducting same so that the Parties may conveniently have their representatives present. Following any test, any measuring equipment found to be inaccurate to any degree shall be adjusted immediately to measure accurately. Each Party shall have the right, at any time, to 15

Execution – Option Agreement challenge the accuracy of any measuring equipment used hereunder and may request additional tests. If, upon testing, the challenged equipment is found to be in error, then it shall be repaired and calibrated. The cost of any such special testing, repair and calibration shall be borne by the requesting Party if the percentage of inaccuracy is found to be two percent (2%) or less. Otherwise, the cost shall be borne by SCM. 6.3 Access to Meters and Records. Customer shall have access at all reasonable times to the measuring equipment and all other instruments used by SCM in determining the measurement and quality of the Gas delivered hereunder, but the reading, calibrating, and adjusting thereof shall be done only by employees, agents or representatives of SCM. SCM shall keep on file copies of original records for a period of two (2) years for mutual use of SCM and Customer and for such longer period as any dispute may be pending between the Parties. Upon request, SCM shall submit to Customer copies of original records from such equipment, subject to return by the Party within sixty (60) Days after receipt thereof. 6.4 Correction of Metering Errors. If, upon any test, the measuring equipment, in the aggregate for any measurement facility, is found to be inaccurate by more than two percent (2%), registration thereof and any payments based upon such registration shall be corrected at the rate of such inaccuracy for any period of inaccuracy that is definitely known or agreed upon; provided, however, if such period is not definitely known or agreed upon, then such registration and payment shall be corrected for a period extending back one-half (1/2) of the time elapsed since the last Day of calibration. 6.5 Low Volume Meter Fee. A fee every Month of two hundred fifty dollars ($250.00) will be assessed by SCM for each Receipt Point meter that flows, on average, less than 2500 Mcf per Day for the prior Month, unless otherwise agreed by the Parties in writing (“Low Volume Meter Fee”). 6.6 Failure of Meters. If, for any reason, the measuring equipment is out of service or out of repair so that the quantity of Gas delivered hereunder through such measuring equipment cannot be ascertained or computed from the readings thereof, the quantity of Gas so delivered during the period such equipment is out of service or out of repair shall be estimated and agreed upon by SCM and Customer upon the basis of the best available data, using the first of the following methods that is feasible: (a) By using the registration of any duplicate measuring equipment installed by SCM, if installed and registering correctly; (b) By using the registration of any check measuring equipment of Customer, if installed and registering accurately; 16

Execution – Option Agreement (c) By correcting the error if the percentage of error is ascertainable by calibration, test or mathematical calculation; or (d) By estimating the quantity of deliveries by using the volumes delivered under similar conditions during preceding periods when the measuring equipment was registering accurately. Customer may install, maintain, and operate at their own expense, at or near the Receipt Points or Residue Gas Delivery Points, such check measuring equipment as desired; provided, however, that such equipment shall be installed so as not to interfere with the operation of any other measuring equipment. SCM shall have access to such check measuring equipment at all reasonable times, but the reading, calibration and adjusting thereof and the changing of charts shall be done only by Customer. 6.7 Modifications to Measurement Procedures. SCM reserves the right to modify the measurement procedures from time to time in order to conform with the general measurement procedures prevailing for the SCM GGP System and/or to remove any inequities which may be found to exist, and it is agreed that any such other method adopted will be applicable to this Agreement; provided, however: (a) SCM shall give Customer at least thirty (30) Days written notice prior to any change or modification to such measurement procedures; and (b) Any change or modification to such measurement procedures shall be consistently applied to all customers. 6.8 Measurement Disputes. Any measurement dispute, controversy, or claim arising out of or in connection with this Article VI, which the Parties are unable to resolve within 90-Days following the resolution methods in this Article VI, shall be referred to and determined by a mutually agreeable measurement expert (the “Measurement Expert”), as the sole and exclusive remedy of the Parties as to the measurement dispute. The decision of the Measurement Expert shall be final and binding upon the Parties. The cost of any such Measurement Expert shall be borne by the Party against whom such dispute is decided by the Measurement Expert. ARTICLE VII TAKE-IN-KIND SCHEDULING; NOMINATION; IMBALANCES In the event Customer elects to take its Residue Gas, Customer will be responsible for nominations (including nomination adjustments) required each Month to the applicable Residue Gas Delivery Point(s). The scheduling, nomination and imbalance procedures applicable if Customer elects to take its Residue Gas in kind are set forth in Exhibit F. ARTICLE VIII GAS QUALITY 17

Execution – Option Agreement 8.1 Specifications. Customer shall cause to be delivered at the Receipt Points merchantable pipeline quality Gas that conforms to the more stringent of (a) the following quality specifications, subject to modification by SCM in its sole discretion or (b) the downstream pipeline specifications as modified from time to time (the “Specifications”). (a) The Gas shall not contain any oxygen (O2); (b) The Gas shall not contain in excess of two percent (2.0%) by volume of carbon dioxide (CO2); (c) The Gas shall not contain in excess of two percent (2.0%) by volume of nitrogen (N2); (d) The Gas shall not contain in excess of three percent (3.0%) by volume of total inerts; (e) The Gas shall not exceed one-quarter (1/4) grain of hydrogen sulfide per 100 Cubic Feet of Gas; (f) The Gas shall not exceed one-quarter (1/4) grain of mercaptan sulfur per 100 Cubic Feet of Gas; (g) The Dedicated Gas shall not exceed five (5) grains of total sulfur per 100 Cubic Feet of Gas; (h) The Gas shall be free of condensed water and other objectionable liquids at the temperature and pressure at which the Dedicated Gas is delivered to SCM at the Receipt Points; (i) The Gas shall have a Gross Heating Value that is no less than one thousand two hundred (1200) Btu per Cubic Foot of Gas; and (j) The Gas shall have a maximum temperature of one hundred twenty degrees Fahrenheit (120° F). 8.2 Failure to Meet Specifications; Blending and Conditioning. (a) If any of Customer’s Gas fails to meet any of the Specifications, SCM shall have the right to refuse to receive such Gas or waive such failure and to continue to receive such Gas. If SCM refuses to receive such Gas and if Customer does not elect to treat the Gas so as to cause the same to meet the Specifications, or if SCM is unable to blend the Gas pursuant to Section 8.2(b) hereunder, then Customer shall stop the delivery of the Gas that fails to meet the Specifications. Customer’s failure to conform to such Gas qualities (and SCM’s refusal to take Gas that does not meet any of the Specifications) does not relieve Customer of any obligations hereunder. Acceptance by SCM of Customer’s Gas that does not conform to 18

Execution – Option Agreement applicable quality specifications shall not constitute a waiver thereof by SCM in regard to such Gas delivered under this Agreement in the future. To the extent that SCM refuses to accept non-conforming Gas that fails to meet the Specifications set forth above in Sections 8.1(b) and/or 8.1(e), but otherwise meets all other Specifications, such non-conforming Gas shall be temporarily released from the Dedication of this Agreement until received by SCM hereunder. (b) If Customer’s Gas delivered at the Receipt Points should fail to meet any one or more of the Specifications set forth in Section 8.1 above, then SCM shall use commercially reasonable efforts to blend and commingle Customer’s Gas with other Gas delivered to the Plant for processing to the extent reasonably practicable, and without any additional payment from Customer, so that the average Gas composition at the Plant meets the applicable Specification(s), provided that SCM shall not be required to blend or commingle such Gas to the extent that SCM determines, in SCM’s sole but good faith discretion, that the blending or commingling of such Gas is reasonably likely to (i) adversely affect (x) the safety, integrity or operation of the gathering system, any trunk line(s) connecting to the Plant for purposes of transporting Customer’s Gas, or the Plant itself, (y) the delivery of Residue Gas to the Residue Gas Delivery Point(s) or Plant Products to the Plant Products Delivery Point(s), or (z) the Gas of one or more third parties; or (ii) otherwise result in economic harm to one or more third parties using the gathering system, any trunk lines or the Plant itself. (c) Customer shall defend, indemnify and hold the SCM Indemnified Parties harmless from and against all Losses arising out of, resulting from or caused by the delivery of Gas which does not conform to the Specifications unless SCM has agreed in writing to accept Customer’s Gas that fails to meet any of the Specifications and expressly waives its claims for damages resulting therefrom. The provisions of this Section 8.2(c) will not apply if SCM knowingly accepts Customer’s non-conforming Gas, or if SCM continues to accept such non- conforming Gas after a thirty (30) Day period following the commencement of deliveries of such non-conforming gas. Notwithstanding anything to the contrary set forth herein, in the event that SCM either knowingly accepts such non- conforming Gas or continues to accept such non-conforming gas for thirty (30) Days following the commencement of deliveries of such non-conforming gas, Customer shall not be liable for any Losses or other damages caused by or resulting from such non-conforming Gas, and SCM hereby waives its claims against Customer with respect to any such Losses or damages. (d) If Customer delivers Gas to SCM at the Receipt Points that meets the Specifications of this Agreement, or with respect to non-conforming Gas that SCM accepts for which it has waived Claims pursuant to Section 8.2(c), then SCM shall redeliver Gas and Plant Products that meets the most restrictive quality specifications required from time to time at the Residue Gas Delivery Points or Plant Product Delivery Points by SCM’s downstream transporters. 8.3 Hazardous Substances. 19

Execution – Option Agreement Customer’s Gas shall not contain any substance that is determined to be a contaminant or a hazardous waste or substance under the Resource Conservation and Recovery Act, 42 U.S.C. Section 1857, et seq., as amended from time to time, the Comprehensive Environmental Response, Compensation and Liability Act, 42 U.S.C. Section 9601, et seq., as amended from time to time, and the regulations issued thereunder, including 40 C.F.R. Parts 302 and 355, together with any other applicable environmental, health, or safety statutes (other than hydrocarbons and/or the natural constituent elements thereof). ARTICLE IX PRESSURE Customer shall deliver, or cause to be delivered, to SCM the Gas to be gathered and/or processed at the line pressures existing in the SCM GGP System as such pressure may exist from time to time at the Receipt Point(s), but not in excess of the MAOP. Customer shall install, operate, and maintain, at their sole expense, such pressure regulating devices as may be necessary to regulate the pressure of gas prior to delivery to SCM so as not to exceed the MAOP upstream of the Receipt Point. If a Customer fails to regulate such pressure at any time during the term of this Agreement, then SCM may install shut-in or other pressure relieving devices at the Receipt Point(s) upstream of the measurement device. SCM shall maintain, under normal operating conditions, all Low Pressure Receipt Point pressures at approximately 100 psig, and all High Pressure Receipt Points pressures at approximately 1100 psig. Notwithstanding anything to the contrary set forth in this Article IX, other than in the event of a Permitted Curtailment, (i) in no event shall Customer be required to deliver Gas hereunder at a pressure exceeding 100 psig at the Low Pressure Receipt Points and 1100 psig at the High Pressure Receipt Points, and (ii) if the average operating pressure of the SCM GGP System for any Month at any Low Pressure Receipt Point exceeds 100 psig or at High Pressure Receipt Point exceeds 1100 psig, then those volumes of the affected Customer’s Gas shall be subject to Customer’s rights under Section 2.1(c). Additionally, if, other than in the event of a Permitted Curtailment, the average operating pressure of the SCM GGP System at any Low Pressure Receipt Point exceeds 100 psig or at High Pressure Receipt Point exceeds 1100 psig for a period of at least sixty (60) consecutive Days or for sixty (60) Days out of a consecutive one hundred twenty (120) Day period, then at Customer’s option and upon written notice to SCM, Customer shall be granted a permanent release from Dedication to this Agreement of such Receipt Point(s), the affected Leases and all existing and future wells behind such Receipt Point(s), and all of such Customer’s Gas produced or producible therefrom. For purposes of this Article IX, the Parties acknowledge and agree that any deviation in pressure levels that are of no fault of Customer and that average in excess of the levels prescribed in the foregoing sentence over a measurement Day shall be deemed to be a deviation lasting for a period of one (1) Day. ARTICLE X ACCOUNTING 10.1 Payment. 20

Execution – Option Agreement SCM shall render to Customer, on or before the last Business Day of each Month, a statement setting forth the amount due hereunder, the total quantity in Mcf and Btu content of Gas received during the preceding Month at the Receipt Points, the net value for Plant Products and Residue Gas attributable to Customer’s Gas and the amount of Service Fees and other charges payable to SCM for the preceding Month. SCM shall pay Customer in accordance with such statement on or before the first (1st) Business Day of the next Month. If the net amount is due SCM, Customer shall pay SCM within thirty (30) Days after Customer’s receipt of such statement. SCM shall preserve all original data in possession utilized by SCM in preparing the statement for a period of two (2) years from the date of such statement. SCM shall render to Customer a statement for any other fees or amounts payable by Customer that are not Monthly fees within sixty (60) Days after such fees or amounts are incurred by SCM and Customer shall pay SCM in accordance with such statement on or before thirty (30) Days after Customer’s receipt of such statement. Either Party shall be entitled to withhold any amounts otherwise payable to the other Party under any statement (and either Party shall not exercise any right of set off with respect thereto) which the Party disputes in good faith upon written notice to the other Party detailing the nature of the dispute. Any withheld amounts shall be promptly paid by the Party to the other Party upon any substantiation or other determination that such amounts are properly payable to the other Party. 10.2 Information. Upon receipt of a written request by SCM, Customer will furnish to SCM copies of any and all forms filed by Customer and/or its operators with any state or federal regulatory agency covering Gas subject to this Agreement. Additionally, SCM and Customer shall each preserve all records applicable to this Agreement, including all test and measurement data and charts, for a period of at least twenty four (24) Months following the end of each calendar year, or such longer periods as shall be required under law or regulation or during the pendency of any dispute. 10.3 Audits. Either Party, upon notice in writing to the other Party, may during normal business hours audit the accounts and records relating to any invoice under this Agreement within the twenty four (24) Month period following the end of the calendar year in which an invoice was rendered; provided, however, that the auditing Party must make a claim in writing upon the other Party for all discrepancies disclosed by said audit within said twenty four (24) Months. Any audit shall be conducted by the auditing Party or its Representative at the auditing Party’s expense. Any invoices or settlement statements shall be final as to all Parties unless questioned within said twenty four (24) Months. 10.4 Certain Pricing. If any periodical or publication used to determine any payment under this Agreement does not report a price under the relevant subheading for the relevant Day or Month or such periodical or the reporting of any such index is discontinued, the Parties will immediately and in good faith enter into negotiations to select a replacement index or other pricing methodology 21

Execution – Option Agreement reflecting equivalent market prices, such replacement index or other pricing methodology to be effective as of the date the prior index or trade publication ceased. 10.5 Setoff. Each Party reserves to itself all rights, setoffs, counterclaims, and other remedies and defenses that such Party has or may be entitled to arising from or out of this Agreement. Upon the occurrence of an uncured material default by a Party under this Agreement following written notice of such default to the defaulting Party and the expiration of the cure period under this Agreement applicable thereto, all outstanding transactions between the Parties and the obligations to make payment in connection therewith, whether arising under this Agreement or any other agreement between the Parties, may be offset against each other, set off, or recouped therefrom upon notice to the defaulting Party detailing the amounts set off and the obligations for which such setoff has occurred. 10.6 Adequate Assurances. When reasonable grounds for insecurity of payment or performance arise with respect to a Party (the “Impaired Party”), including, without limitation, as a result of the occurrence of a material change in the creditworthiness of the Impaired Party or the Impaired Party’s failure to timely pay any amounts due hereunder other than amounts subject to a good-faith dispute, the other Party (the “Insecure Party”) may demand adequate assurance of performance, and in the absence of the provision of such assurance from the Impaired Party within three (3) Business Days of request, suspend further performance and/or exercise its rights under Section 6.2 of this Agreement, including the right to terminate this Agreement. Adequate assurance shall mean security in the form, amount and for the term reasonably specified by the Insecure Party, including, but not limited to, a standby irrevocable letter of credit issued by a Qualified Institution, a prepayment or a guarantee by an entity deemed creditworthy at the sole discretion of the Insecure Party, advance cash payment or other satisfactory security reasonably acceptable to the Insecure Party. ARTICLE XI WARRANTY AND INDEMNIFICATION 11.1 Warranty of Title; Indemnity. (a) Customer warrants that it will have, at the time of its delivery of Gas at the Receipt Points, control of and good title to and/or the full right and authority to deliver such Gas and any liquefiable hydrocarbons therein to SCM for gathering and processing hereunder. Customer warrants that the Gas delivered to SCM hereunder shall be free and clear of all liens, encumbrances, and claims whatsoever (other than with respect to any lien held by any lender under any credit facility for borrowed money of Customer or its Affiliates), and that it will have at such time of delivery good right and title to the Gas or the right to gather such Gas hereunder. If any claim is made challenging a Customer’s right to deliver such Gas to SCM, SCM has the right to suspend receipt or deliveries of 22

Execution – Option Agreement such challenged Gas hereunder until such issue is finally resolved to the reasonable satisfaction of SCM. (b) Customer shall indemnify, defend and hold the SCM Indemnified Parties harmless from and against all Losses incurred by the SCM Indemnified Parties arising out of or related to any breach of the foregoing title warranty, including any adverse claims pertaining to Gas delivered hereunder. (c) SCM represents and warrants that Customer’s Gas from the time of receipt hereunder at the Receipts Point(s) until the time of redelivery of Customer’s Residue Gas at the Residue Gas Delivery Point(s) (to the extent that Customer has elected to take in-kind) or the time of purchase by SCM of Customer’s Residue Gas and Plant Products, shall be free and clear of all liens, encumbrances and claims arising by, through or under SCM, and SCM agrees to indemnify, defend and hold the Customer Indemnified Parties harmless from and against any and all Losses to the extent incurred by Customer on account of any such liens, encumbrances and claims arising by, through or under SCM. 11.2 Limitation of Liability. NOTWITHSTANDING ANYTHING TO THE CONTRARY IN THIS AGREEMENT, IN NO EVENT SHALL EITHER PARTY (OR ANY CUSTOMER INDEMNIFIED PARTY OR SCM INDEMNIFIED PARTY) BE LIABLE TO THE OTHER PARTY (OR ANY CUSTOMER INDEMNIFIED PARTY OR SCM INDEMNIFIED PARTY, AS THE CASE MAY BE), ANY SUCCESSORS IN INTEREST OR ANY BENEFICIARY OR ASSIGNEE OF THIS AGREEMENT FOR ANY EXEMPLARY OR PUNITIVE DAMAGES OR ANY SPECIAL, INDIRECT, INCIDENTAL, OR CONSEQUENTIAL DAMAGES OF ANY CHARACTER, INCLUDING LOSS OF USE, LOST PROFITS OR REVENUES, OR COST OF CAPITAL, ARISING OUT OF OR IN CONNECTION WITH THIS AGREEMENT OR ANY BREACH THEREOF, IRRESPECTIVE OF WHETHER CLAIMS FOR SUCH DAMAGES ARE BASED UPON CONTRACT, WARRANTY, NEGLIGENCE, STRICT LIABILITY OR OTHERWISE; PROVIDED, HOWEVER, THE FOREGOING SHALL NOT BE CONSTRUED AS LIMITING AN OBLIGATION OF A PARTY HEREUNDER TO INDEMNIFY, DEFEND AND HOLD HARMLESS THE OTHER PARTY AGAINST CLAIMS ASSERTED BY UNAFFILIATED THIRD PARTIES, INCLUDING BUT NOT LIMITED TO THIRD PARTY CLAIMS FOR EXEMPLARY, PUNITIVE, SPECIAL, INDIRECT, INCIDENTAL OR CONSEQUENTIAL DAMAGES. . ARTICLE XII FORCE MAJEURE 12.1 Definition. Subject to the other provisions of this Agreement, if either Party is rendered unable, wholly or in part, by Force Majeure to carry out its obligations under this Agreement, other than to make payments when due hereunder, it is agreed that, on such Party’s giving notice of such Force Majeure to the other Party within a reasonable time after the occurrence of the cause relied on, the obligations of the Party giving such notice, so far as they are affected by Force Majeure, shall be suspended during the continuance of any inability so caused, but for no longer period, and such cause shall so far as possible be remedied with all reasonable dispatch, if economically 23

Execution – Option Agreement justifiable. The term “Force Majeure” shall mean any cause or causes not reasonably within the control of the Party claiming suspension and which, by the exercise of reasonable diligence, such Party is unable to prevent or overcome, including acts of God, acts of Governmental Authorities, compliance with rules, regulations or orders of any governmental authority, strikes, lockouts or other industrial disturbances, acts of the public enemy, acts of terrorism, wars, blockades, insurrections, riots, epidemics, landslides, lightning, earthquakes, fires, extreme cold, storms, hurricanes, floods, or other adverse weather conditions, washouts, arrests and restraint of rulers and people, civil disturbances, explosions, breakage or accident to machinery, equipment or pipelines, freezing of wells, pipelines or equipment, requisitions, directives, diversions, embargoes, priorities or expropriations of government or Governmental Authorities, legal or de facto, whether purporting to act under some constitution, decree, law or otherwise, failure of pipelines or other gatherers to gather or furnish facilities for transportation, failures, disruptions, or breakdowns of machinery or of facilities for production, manufacture, transportation, distribution, processing or consumption (including, but not by way of limitation, the SCM GGP System), allocation or curtailment by third parties of downstream capacity, inability to secure or delays in securing permits from Governmental Authorities, transportation embargoes or failures or delays in transportation or poor road conditions, partial or entire failure of Gas supply and downstream pipeline market constraints. “Force Majeure” shall expressly exclude (i) delays in permitting that are not extraordinary or unusual for the Dedicated Area and the development of the Permian Basin and other relevant basins, or (ii) any matters within the reasonable control of SCM (such as easement, right-of-way, fee land and surface right acquisition, the availability of labor, materials and supplies, and other similar matters). Further, notwithstanding anything to the contrary set forth in this Agreement, none of the following shall, under any circumstance, constitute a Force Majeure event: (i) the lack of financial resources, or the inability of a Party to secure funds or make payments as required by this Agreement absent the other Party’s breach of this Agreement which has a material adverse effect on such Party; (ii) adverse market, financial or other economic conditions including changes in market conditions that either directly or indirectly affect the demand for or price of Gas or Plant Products; or (iii) availability of more attractive markets or gathering, transportation or processing services for Gas or Plant Products. 12.2 Strikes and Lockouts. The settlement of strikes or lockouts shall be entirely within the discretion of the Party having the difficulty, and that the above requirement that any Force Majeure shall be remedied with all reasonable dispatch shall not require the settlement of strikes or lockouts by acceding to the demands of an opposing Party when such course is inadvisable in the discretion of the Party having the difficulty. ARTICLE XIII SUCCESSORS AND ASSIGNS 13.1 Successors and Assigns. All the terms and conditions of this Agreement shall extend to and be binding upon the respective successors and assigns of the Parties. 13.2 Assignments. 24

Execution – Option Agreement The Parties have entered into this Agreement in anticipation of continued performance hereunder, and, accordingly, the rights and obligations of a Party hereunder shall not be assigned without the prior written consent of SCM or Customer, as applicable, which shall not be unreasonably withheld, conditioned, denied or delayed. Notwithstanding the above, (i) the Parties shall have the right to assign this Agreement to a purchaser or other successor of substantially all of the assets involved provided that the purchaser or other successor assumes in writing the obligations of the assigning Party, and (ii) Customer may only assign its rights and obligations hereunder to a Person acquiring all or any of the Leases, Wells, and Dedicated Gas that Customer or its Affiliates own in the Dedicated Area. Without the consent of the other Party hereto, either Party hereto may assign its rights hereunder to its Affiliate, provided that the assigning party shall remain liable for its obligations hereunder. Nothing in this Section 13.2 shall in any way prevent either Party from pledging or mortgaging its rights hereunder as security for indebtedness. Further and notwithstanding anything in this Section 13.2 to the contrary, Customer may assign its rights and obligations under this Agreement to any Person to whom Customer assigns or transfers an interest in any of the Lease(s) or Well(s), insofar and only insofar as, this Agreement relates to such Lease(s) or Well(s), without the consent of SCM; provided that (i) such Person is at least as creditworthy as Customer is as of the Effective Date and at the time of such assignment, (ii) such Person assumes in writing the obligations of Customer under this Agreement insofar as it relates to such Lease(s) or Well(s), and (ii) if such transfer or assignment is to a Person that is not an Affiliate of Customer, Customer shall be released from its obligations under this Agreement with respect to such Lease(s) or Well(s) so assigned or transferred, except for its obligations arising prior to the date of assignment. For the avoidance of doubt, (i) no assignee or transferee of Customer shall assume the Dedication of this Agreement in its entirety, but shall only be subject to, and assume, such Dedication insofar and only insofar as the Lease(s) or Well(s) assigned or transferred to such assignee or transferee and (ii) SCM shall not be required to install supplemental meters or other facilities at existing Receipt Points, or undertake additional obligations or incur additional expenses as a result of such assignment (provided the Parties shall reasonably cooperate to establish a procedure for the allocation of Gas delivered at existing Receipt Points between Customer and such transferee or assignee, if applicable). ARTICLE XIV MISCELLANEOUS 14.1 Federal Jurisdiction. This Agreement is subject to all valid present and future laws, regulations, rules, and orders of governmental authorities now or hereafter having jurisdiction over the Parties, this Agreement, or the Services performed or the Facilities utilized under this Agreement. It is the intent of the Parties that SCM provide Services to Customer on a negotiated-contract basis only, and the Parties hereby agree that, in the event that (i) SCM’s Facilities, or any part thereof, become subject to regulation by FERC, or any other governmental body or agency of the rates, terms, and conditions for service, (ii) SCM becomes obligated by FERC or any other governmental body or agency to provide Services or any portion thereof on an open access, nondiscriminatory basis as a result of SCM’s execution, performance, or continued performance of this Agreement, or (iii) FERC or any other governmental body or agency seeks to modify any rates under, or terms or conditions of, this Agreement, then: 25

Execution – Option Agreement (a) to the maximum extent permitted by law, it is the intent of the Parties that the rates and terms and conditions established by the FERC or governmental body or agency having jurisdiction will not alter the rates or terms and conditions set forth in this Agreement, and the Parties shall vigorously defend and support in good faith the enforceability of the rates and terms and conditions of this Agreement; or (b) if FERC or the governmental body or agency having jurisdiction modifies the rates or terms and conditions set forth in this Agreement, then the Parties hereby agree to negotiate in good faith to enter into such amendments to this Agreement and or enter into a separate arrangement in order to give effect, to the greatest extent permitted by law, to the rates and other provisions of this Agreement; provided however if SCM and Customer cannot arrive at such agreement following such negotiations, either Party may terminate this Agreement by delivering written notice thereof to the other Party, with such termination to be effective 90 Days after the delivery of such notice. 14.2 No Waiver of Defaults. No waiver by either Party of any default of the other Party under this Agreement shall operate as a waiver of any subsequent default, whether of a like or a different character. 14.3 Joint Preparation of This Agreement. This Agreement will be deemed and considered for all purposes as prepared through the joint effort of the Parties and will not be construed against one Party or the other as a result of the preparation, submittal or other event of negotiation, drafting or execution hereof. 14.4 Headings. The headings contained in this Agreement are used solely for convenience and do not constitute part of the agreement between the Parties, and they should not be used to aid in any manner in construing this Agreement. 14.5 Governing Law; Venue; Waiver of Jury Trial. THIS AGREEMENT WILL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS, WITHOUT REGARD ITS CONFLICT OF LAWS PRINCIPLES. SUBJECT TO SECTION 6.8 OF THESE GENERAL TERMS AND CONDITIONS, THE PARTIES IRREVOCABLY SUBMIT TO THE EXCLUSIVE JURISDICTION OF THE STATE OR FEDERAL COURTS LOCATED IN HOUSTON, HARRIS COUNTY, TEXAS IN RESPECT OF ANY DISPUTE ARISING PURSUANT TO OR IN CONNECTION WITH THIS AGREEMENT, AND EACH PARTY WAIVES ANY OBJECTION THAT SUCH PARTY MAY NOW OR HEREAFTER HAVE TO THE LAYING OF THE VENUE OF ANY SUCH ACTION, SUIT OR PROCEEDING. EACH PARTY WAIVES ITS RIGHTS TO A TRIAL BY JURY IN RESPECT OF ANY CLAIM RELATING TO THIS AGREEMENT. 14.6 Use of Third Party Processing Facilities. 26

Execution – Option Agreement SCM shall have the right to use the processing facilities of a third party in lieu of a Plant owned or operated by SCM; provided that any Gas processed at such third party facility would be processed in accordance with the terms and conditions of this Agreement. 14.7 Survival. The provisions of Article VIII, Sections 10.3, 11.2, and Article XIV of these General Terms and Conditions shall survive the expiration or termination of this Agreement. In addition, the Parties payment and indemnification obligations shall likewise survive the expiration or termination of this Agreement. 14.8 Counterparts. This Agreement may be executed in any number of counterparts, each of which shall be considered an original, and all of which shall be considered one instrument. 14.9 Entire Agreement. This Agreement constitutes the entire agreement between the Parties covering the subject matter hereof, and there are no agreements, modifications, conditions, or understandings, written or oral, expressed or implied, pertaining to the subject matter hereof that are not contained herein. This Agreement supersedes and replaces all prior agreements pertaining to the subject matter of this Agreement. The Parties hereto have voluntarily agreed to define their rights, liabilities and obligations relative to subject matter of this Agreement exclusively in contract pursuant to the express terms and provisions of this Agreement. Neither Party hereto shall have any remedies or cause of action (whether in contract or tort) for any statements, communications, disclosures, failures to disclose, or representations or warranties not expressly set forth in this Agreement. 14.10 Modifications in Writing. Modifications of this Agreement will be or become effective only upon the due and mutual execution of appropriate supplemental agreements or amendments hereto by duly authorized representatives of the respective Parties. 14.11 No Third Party Beneficiaries. Except as expressly set forth herein, the provisions of this Agreement will not impart rights enforceable by any Person that is not a Party. 14.12 Liquidated Damages. The circumstances of this Agreement are such that a Party will be exposed to substantial injury if the other Party does not timely perform under this Agreement, and the injuries that may occur to such Party could take a variety of forms. Where this Agreement imposes on a Party an obligation to pay to the other Party certain monetary sums, or provide other value to the other Party, as a result of certain non-performance or delayed performance under this Agreement, such sums or other value are intended to serve as liquidated damages for certain of the injuries to such 27

Execution – Option Agreement other Party. The Parties stipulate and agree that (a) the injury that would be caused to a Party as a result of the other Party’s non-performance or delayed performance would be difficult to estimate accurately, (b) the sums or other value to be provided to such Party under this Agreement in such circumstances are intended to serve as a liquidated damages and not as a penalty, and (c) such sums or other value represent the Parties’ reasonable estimate at this time of the probable damages that would be suffered by a Party in the various scenarios addressed in this Agreement. 28

Execution – Option Agreement EXHIBIT A-1 Dedicated Area [ATTACHED]

AX A24 G A I N E A25 2 A27 2 2 E 2 29E 2 3 E 2 31E 2 32E 2 33E 2 34E 2 35E 2 36E 2 37E 2 3 E A22 C45 39E A2 A23 A24 A26 A2 A26 A3 A31 A44 A34 21 27E 21 2 E 21 29E 21 3 E 21 31E 21 32E 21 33E 21 34E 21 35E 21 36E 21 37E 21 3 E A29 A33 A36 A32 A34 A43 A35 A37 A34 A3 A39 A36 22 27E 22 2 E 22 29E 22 3 E 22 31E 22 32E 22 33E 22 34E 22 35E 22 36E 22 37E 22 3 E A3 13 14 A45 A39 A4 A49 A4 L E A A46 23 27E A5 A N D R E W A44 23 2 E 23 29E 23 3 E 23 31E 23 32E 23 33E 23 34E 23 35E 23 36E 23 37E 23 3 E Y Y A47 D D D D A43 E E A51 A42 12 A41 24 2 E 24 29E 24 3 E 24 31E 24 32E 24 33E 24 34E 24 35E 24 36E A53 24 27E 24 37E 24 3 E A52 9 A54 1 11 25 2 E 25 29E 25 3 E 25 31E 25 32E 25 33E 25 34E 25 35E 25 36E 25 37E 25 27E 25 3 E A55 73 44 T2N A22 A41 A26 43 T1N A 54 45 T2N 44 T1N 26 27E 26 2 E 26 29E 26 3 E 26 31E 26 32E 26 33E 26 34E 26 35E 26 36E 26 37E 26 3 E A56 A57 A 57 A 46 46 43 N E W M E X I C O 45 TIN 45 T1N T1N 56T1 55T1 A 57 B57 44 T1N C22 T E X A S A57 46 C23 43 T1 C C24 77 C25 46 T1N 5 T1 57 T1 57 T1 56 T1 55 T1 54 T1 76 59 T1 B1 74 44 T1 B2 WF 1 46 TI B3 7 C26 75 B2 45 T1 46 T1 B7 E C T O R 29 26 W 4 46 TI L O V I N G WW I N K L E R B27 B6 27 5 T2 57 T2 57 T2 56 T2 55 T2 54 T2 53 T2 59 T2 5 T7 B4 B4 44 T2 2 45 T2 B5 B4 5 B 5 T6 29 C U L B E R O N B1 B9 2 112 56 T3 57 T3 56 T3 2 C27 C29 B15 1 B11 44 T3 113 B12 21 45/113 56 T3 C2 B14 57 T3 2 2 VV B13 35 45 R E E V E 19 \ LILIS_ACREAGE.mxdLilis B16 \ 1 A 111 33 46 T3 16 55 T3 2 AMI 3 15 C21 13 46 \ Energy Companies F B23 5 53 T4 3 B22 52 T4 \ SALT_CREEK B19 55 T4 53 T4 1 17 R A N E 57 R A N E Projects 54 T4 52 T4 W A R D B1 B2 B17 C R A N E \ 52 53 56 \ GIS C19 34 N 63 ‘ B26 53 O 1 5 Miles 4 16 B21 54 T5 B2 Document Path: M: 55 T5 54 T4 34 34 B19

Execution – Option Agreement EXHIBIT B-1 Receipt Points The Receipt Points are to be agreed upon and updated in writing from time to time. [The initial Receipt Points (if any) are described below]: Well Name Surface Location [NOTE: Describe Receipt Point(s) as of the Effective Date.]

Execution – Option Agreement EXHIBIT C Form of Memorandum of Agreement STATE OF [ ] § § COUNTIES OF [ ] § This Memorandum of Gas Purchase Agreement (this "Memorandum") is made and entered into this [ ] day of [ ], 20 , by and between Lilis Energy, Inc., a Nevada corporation (“Customer”), located at [_ ], Attn: [ ], and Salt Creek Midstream LLC, a Delaware limited liability company located at 20329 State Highway 249, Suite 450, Houston, TX 77070, Attn: Paul Williams (“SCM”). WHEREAS, Customer and SCM have entered into a Gas Purchase Agreement (the “Agreement”) dated effective August 11, 2027 (the “Effective Date”); and WHEREAS, Customer and SCM desire to file this Memorandum to provide record notice of the Agreement. 1. Dedication. Subject to the other terms and conditions of the Agreement, Customer hereby (i) dedicates for Services with respect to Dedicated Gas under the Agreement to SCM all Leases now owned or hereafter acquired by Customer and/or its Affiliates and their respective successors and assigns that cover lands located within the Dedicated Area, and (ii) dedicates for Services under the Agreement and shall deliver, or cause to be delivered, hereunder to SCM, at the Receipt Points, the following (the “Dedication,” and the Gas that is the subject of the Dedication being herein referred to as “Dedicated Gas”): (a) all Gas produced and saved on or after the Effective Date for the remainder of the Term from those Wells for which Customer and/or any of its Affiliates is the operator now or hereafter located within the Dedicated Area or on lands pooled or unitized therewith, to the extent such Gas is attributable to the Leases within the Dedicated Area now owned or hereafter acquired by Customer and/or its Affiliates and their respective successors and assigns; and (b) with respect to those Wells for which Customer and/or any of its Affiliates is the operator, Gas produced on or after the Effective Date for the remainder of the Term from such Wells which is attributable to the Leases in such Wells owned by other working interest owners and royalty owners which is not taken “in-kind” by such working interest owners and royalty owners and for which Customer and/or its Affiliates has the right or obligation to deliver such Gas and only for the period that Customer and/or its Affiliates has such right or obligation. For the avoidance of doubt, Customer shall not be required to deliver Gas from any well operated by an operator other than Customer or its Affiliates, including any well where Customer

Execution – Option Agreement would be required to install split stream connection facilities or similar facilities to take such Gas in kind, and such Gas shall not be Dedicated Gas subject to the Dedication hereunder. 2. Term. Subject to the terms and conditions contained in the Agreement, the Agreement shall be in full force and effect as of the Effective Date and shall continue in full force and effect for a period of twelve (12) years thereafter (the “Primary Term”), unless terminated in accordance with Section 6.2 of the Agreement or as otherwise provided in the Agreement, and for successive one (1) year periods thereafter until terminated by either Party as of the end of the Primary Term or any subsequent renewal by giving the other Party at least sixty (60) Days’ prior written notice (the Primary Term, including any such extension, the “Term”). However, such termination shall not extinguish any obligations incurred prior to the effective date of termination, including payment for services rendered or Gas and/or Plant Products purchased hereunder. 3. Covenant Running With the Land. So long as the Agreement is in effect, the Agreement shall (i) be a covenant running with the Leases now owned or hereafter acquired by Customer and/or its Affiliates within the Dedicated Area (including, without limitation, all Wells operated by Customer or its Affiliates) and (ii) be binding on and enforceable by SCM and its successors and assigns against Customer, its Affiliates and their respective successors and assigns. Notwithstanding Section 2.4 of the Agreement, to the extent all or a portion of such Leases within the Dedicated Area are sold to a non-Affiliated Person, such acquiring Person shall only be required to dedicate for delivery hereunder that Gas that is produced from such Leases within the Dedicated Area acquired by such non-Affiliated Person from Customer. The acquiring Person shall not be required to dedicate Gas produced from Leases already held by or acquired after such date by such acquiring Person. Notwithstanding the foregoing, with prior written notice to SCM, Customer and its Affiliates shall each be permitted to convey, sell, assign, or otherwise transfer its interest in the Leases that are not connected to or in the process of being connected to the SCM GGP System free of the Dedication hereunder in an “acreage swap” or exchange transaction in which such undeveloped Leases within the Dedicated Area are exchanged for other properties or Leases of approximately equal net acreage and projected production located in the Dedicated Area that are not subject to a Prior Dedication and would become subject to the Dedication hereunder. SCM and Customer shall prepare, execute, acknowledge, deliver, and record any such instruments and other documents reasonably necessary to effectuate such release and memorialize such acquired Leases subject to the Dedication. 4. Incorporation of Agreement and Effect of Memorandum. The sole purpose of this Memorandum is to give notice of the existence of the Agreement. This Memorandum shall not modify in any manner any of the terms and conditions of the Agreement, and nothing in this Memorandum is intended to and shall not be used to interpret the Agreement. The provisions of the Agreement are hereby incorporated into this Memorandum as if set out fully herein. In the event of any conflict between the terms of this Memorandum and the terms of the Agreement, the terms of the Agreement shall govern and control for all purposes. 5. Defined Terms. All capitalized terms not defined herein shall have the same meaning assigned such terms in the Agreement.

Execution – Option Agreement [Signature pages follow]

Execution – Option Agreement IN WITNESS WHEREOF, this Memorandum is executed by Customer and SCM as of the date of acknowledgement of their signatures, but is effective for all purposes as of the Effective Date stated above. CUSTOMER: LILIS ENERGY, INC. By: Name: Title: STATE OF TEXAS § § COUNTY OF - § This instrument was acknowledged before me this day of , 20 by , the of Lilis Energy, Inc., a Nevada corporation, on behalf of said corporation. In witness whereof I hereunto set my hand and official seal. NOTARIAL SEAL: Notary Public in and for the State of Texas My Commission Expires: Commission No.:

Execution – Option Agreement SCM: SALT CREEK MIDSTREAM, LLC By: Name: Title: STATE OF TEXAS § § COUNTY OF HARRIS § This instrument was acknowledged before me this day of , 20 by , the of Salt Creek Midstream, LLC, a Delaware limited liability company, on behalf of said limited liability company. In witness whereof I hereunto set my hand and official seal. NOTARIAL SEAL: Notary Public in and for the State of Texas My Commission Expires: Commission No.:

Execution – Option Agreement SCHEDULE 1 TO MEMORANDUM OF GAS PURCHASE AGREEMENT [To Be Attached]

Execution – Option Agreement EXHIBIT D-1 Residue Gas Delivery Points SCM interconnect of El Paso 1600 Pipeline (EP 1600) SCM interconnect of Roadrunner Gas Transmission Pipeline (upon the applicable in-service date) SCM interconnect of Comanche Trail Pipeline (upon the applicable in-service date)

Execution – Option Agreement EXHIBIT D-2 Plant Products Delivery Points Salt Creek Midstream Plant interconnect of the Epic NGL Pipeline

Execution – Option Agreement EXHIBIT E Prior Dedications [NOTE: Customer to list all Prior Dedications as of the Effective Date]

EXHIBIT F Take In Kind Scheduling, Nomination and Balancing Procedures Article A Nominations 1. Nominations. For each Month when Customer takes Residue Gas in kind, Customer shall nominate to SCM the quantity of Residue Gas per Day, as applicable, that Customer will receive at the Residue Gas Delivery Points for that Month. Such nomination shall be made no later than 11:30 a.m. Central Time three (3) Business Days prior to the beginning of such Month, and in any event no later than the nomination deadline for such Month for the applicable downstream pipeline receiving such Residue Gas, in accordance with SCM’s nomination procedures (which procedures have been provided to Customer prior to the first delivery of Residue Gas to Customer hereunder) and shall be subject to confirmation by SCM and such downstream pipeline (“Confirmed Nomination”). When Customer has submitted its nomination consistent with the requirements herein, SCM shall coordinate with the downstream pipeline so that Customer’s nomination becomes a Confirmed Nomination (except when capacity or other issues on the downstream pipeline prevents such confirmation). SCM, in its reasonable discretion, may accept nominations at such later time as operating conditions permit, and may waive any nomination requirement. Customer may change its nominations by providing intra-day or intra- Month nominations made in accordance with SCM’s nomination procedures. SCM reserves the right, from time to time and following written notice to Customer, to revise its nomination procedures; provided that SCM’s nomination procedures shall not be more stringent than the nomination procedures of the applicable downstream pipeline. If Customer fails to provide SCM with a timely nomination, SCM shall use Customer’s most recent nomination as a default nomination which shall be subject to confirmation by SCM and such downstream pipeline Confirmed Nomination process. Customer shall make all necessary arrangements with downstream pipelines or other applicable third persons downstream of the Residue Gas Delivery Points to receive Customer’s Residue Gas, and such arrangements shall be coordinated with SCM and such downstream pipelines or other applicable third persons. SCM and Customer agree that scheduling and commencement of service shall be consistent with the applicable downstream pipeline’s nomination requirements. Whenever Customer’s Residue Gas are to be scheduled or nominated hereunder, each Party shall provide to the other Party all information required for such nominations and confirmations with upstream and downstream pipelines or transporters. Customer shall use reasonable efforts to make nomination changes as necessary at the applicable Residue Gas Delivery Points to minimize imbalances. 2. Right to Balance; Nomination Adjustments. The Parties agree that SCM shall operate SCM’s Facilities so as to accept and deliver Gas hereunder in such a manner as to balance, as closely as possible, receipts of Customer’s Gas and deliveries of Customer’s Residue Gas owed to Customer under this Agreement. SCM may provide notice to Customer requiring Customer to adjust Customer’s nominations if Customer’s Residue Gas delivery nominations at the Residue Gas Delivery Point exceed or are less than the quantity of Customer’s Residue Gas available at the Residue Gas Delivery Points; provided, however, that SCM shall provide Customer reasonable flexibility in adjusting its nominations if such flexibility exists under SCM’s operational balancing agreement (“OBA”) with the applicable downstream pipeline. 3

3. Unanticipated Changes in Deliveries. SCM and Customer shall inform each other of any discovered unanticipated changes in deliveries at a Receipt Point or Residue Gas Delivery Point. SCM shall use reasonable efforts to provide timely notification to Customer by telephone, with subsequent e-mail notification, of the potential size and duration of any unscheduled capacity disruption. Subject to Article A, paragraph 1 of this Exhibit F above, if Customer does not adjust its nomination within two (2) hours after receiving notification from SCM, then SCM may adjust Customer’s nomination and/or not confirm the nominations requested by Customer in the next nomination cycle, and notify Customer of such nomination changes. 4. Requirements of Interconnecting Pipeline. All provisions contained in this Article A of this Exhibit F shall be subject to the requirements of the applicable downstream pipeline(s). ARTICLE B TAKE IN KIND TERMS; IMBALANCES 1. Designated Redelivery Points. When Customer takes its Residue Gas in kind, Customer may designate the Residue Gas Delivery Point(s) at which such Residue Gas will be delivered to Customer or for Customer’s account. SCM will use commercially reasonable efforts to deliver Customer’s Residue Gas at the delivery point(s) designated by Customer, in the percentages designated by Customer, subject to (i) available capacity at such designated delivery point(s), (ii) the availability of Residue Gas, as applicable, at such designated delivery point(s), and (iii) confirmation by SCM and the downstream pipelines at such designated delivery point(s). Customer acknowledges and agrees that SCM does not guaranty that Customer’s Gas will be processed at any specific Plant and although Customer may designate the delivery point(s) at which Customer’s Residue Gas will be delivered to Customer or for Customer’s account, SCM’s ability to deliver a specified volume of Customer’s Residue Gas to a designated delivery point at the tailgate of a Plant will be contingent upon a corresponding volume of Customer’s Gas being processed at such Plant. If SCM cannot for any reason deliver Customer’s Residue Gas during a Month to a designated delivery point in the designated percentage, SCM will give notice of such inability as soon as commercially reasonable so that Customer can adjust its pipeline nominations. If it becomes necessary to limit the Residue Gas delivered at any delivery point, SCM will make such delivery point available to Customer and all third persons ratably in accordance with all Confirmed Nominations of Residue Gas (including Customer’s Residue Gas), as applicable for delivery at such delivery point. 2. Disposition. Customer shall use commercially reasonable efforts to secure adequate transportation capacity or make appropriate arrangements to market downstream of the designated delivery points all Customer’s Residue Gas that it takes in kind. If during any Month SCM delivers Residue Gas for Customer’s account at Customer’s designated delivery point(s), but Customer fails to provide for the disposition of any such Residue Gas for any reason other than the unavailability of or a disruption in (x) downstream facilities to further deliver such Residue Gas downstream of the Plant or (y) the markets for such Residue Gas, then for such Residue Gas not taken by Customer, if SCM can arrange for the disposition thereof under its downstream transportation and marketing arrangements, SCM will do so and pay Customer for such Residue Gas at the actual price SCM can dispose of such Residue Gas, plus a marketing fee of $0.015/MMBtu for Residue Gas. 4

3. Reporting to Downstream Pipelines. SCM will, as soon as possible each Month, provide to each applicable downstream pipeline, with copies to Customer, the actual MMBtus of Residue Gas components delivered during the previous Month to the downstream pipeline for Customer’s account. 4. Imbalances. Each Month that Customer takes its Residue Gas in kind, SCM will deliver to Customer or for Customer’s account at the designated Residue Gas Delivery Point(s) an aggregate quantity of Residue Gas that is equal to Customer’s allocated share of Residue Gas for such Month. In the event imbalances accrue to either Party on a downstream pipeline, each Party will use commercially reasonable efforts to coordinate with the other Party when scheduling Gas volumes as imbalance payback on the downstream pipeline. (a) OBA in Effect. When SCM has an OBA in place with the applicable downstream pipeline and Customer is kept whole on its nominations with the downstream pipeline, Customer shall reimburse SCM for any costs incurred by SCM under such OBA associated with Residue Gas imbalances resulting from Customer’s failure to adjust its nomination as required under this Agreement. Customer shall use commercially reasonable efforts to adjust its nomination in order to minimize any imbalance Customer may incur with SCM and/or which SCM may incur for the account of Customer with the downstream pipeline. Additionally, (i) SCM and the downstream pipeline shall administer any imbalances and cash-outs pursuant to the terms of the OBA, (ii) SCM shall provide Customer a copy of the cash-out mechanism under the OBA, which shall be the same cash-out mechanism as imposed by the downstream pipeline at the applicable delivery point, and (iii) SCM shall invoice Customer and provide supporting documentation for Customer’s share of any charges incurred under such OBA. (b) No OBA in Effect. In the event SCM and a downstream pipeline do not have an OBA in place, Customer and such downstream pipeline shall administer any imbalances and cash-out obligations that accrue to Customer on the downstream pipeline, and SCM and such downstream pipeline shall administer any imbalances and cash-out obligations that accrue to SCM on the downstream pipeline. Each Party, to the extent its actions or inactions cause the other Party to accrue an imbalance on a downstream pipeline, shall reimburse the other Party for any costs incurred by the other Party as a result of such imbalance. (c) Residue Gas Imbalance Cash-Out. Any Residue Gas imbalance remaining at the end of a Month shall be reflected on the Monthly statement provided by SCM to Customer and shall be eliminated by cashing out the entire amount of the Residue Gas imbalance at the Residue Gas Cash-Out Price, in accordance with the following: (i) over- deliveries of Residue Gas by SCM to Customer (or for Customer’s account) at a designated Residue Gas Delivery Point will be purchased by Customer from SCM at the relevant Residue Gas Cash-Out Price, and (ii) under-deliveries of Residue Gas by SCM to Customer (or for Customer’s account) at a designated Residue Gas Delivery Point will be purchased by SCM from Customer at the relevant Residue Gas Cash-Out Price. SCM shall account for, and settle, Residue Gas imbalances for a Month on the same payment date that other payments are owed for such Month pursuant to the Agreement. 5

Residue Gas Cash-Out Price means, for any Month, (A) for over-deliveries of Residue Gas, the applicable cash out percentage set forth below multiplied by the weighted average price received by SCM for Residue Gas sold during such Month from the Plant: Imbalance Percentage Cash Out Percentage >0% but <= 10% 100% >10% but <=15% 105% >15% 110% and (B) for under-deliveries of Residue Gas, the applicable cash out percentage set forth below multiplied by the weighted average price received by SCM for Residue Gas sold during such Month from the Plant: Imbalance Percentage Cash Out Percentage >0% but <= 10% 100% >10% but <=15% 95% >15% 90% (e) CUSTOMER SHALL RELEASE, PROTECT, DEFEND, INDEMNIFY AND HOLD SCM HARMLESS FROM AND AGAINST ANY PENALTIES, FINES, FEES, LOSSES, CLAIMS, CAUSES OF ACTION (WHETHER IN TORT, CONTRACT OR OTHERWISE), OR JUDGMENTS OBTAINED (INCLUDING THE PAYMENT OF REASONABLE ATTORNEYS’ FEES AND COURT COSTS) AGAINST SCM BY ANY PERSON ARISING OUT OF OR CAUSED BY CUSTOMER’S FAILURE TO TIMELY BALANCE RECEIPTS AND DELIVERIES OF CUSTOMER’S RESIDUE GAS ON SCM’S FACILITIES. 5. Other Imbalance Issues. In the event an imbalance issue arises that is not otherwise addressed in this Article B of this Exhibit F, the administration and resolution of such imbalance issue shall be handled reasonably and consistent with generally accepted industry methodology. 6. No Intentional Imbalances. Each Party agrees, subject to its other rights and obligations set forth in this Agreement, that in no event shall such Party intentionally create an imbalance. 6

EXHIBIT G New Receipt Point Notification 1. Operator Contact Name 2. Phone Numbers 3. E-Mail 4. Notification Date 5. Receipt Point/New Well 6. County/Township/Range/Section 7. Expected Date of First Flow 8. Projected Volume (Mcfd) Receipt Point (circle) ’ ” -_ ’ ” 9. Surface site provided by Customer⁰ or SCM ⁰ 10. Expected gas composition Attach sample analysis 11. H2S Expected (Y / N) and quantity in ppm 12. Gas lift Meter Requested (Y / N) [Customer] By: Name: Title: Date: 7

SCM Acknowledgement By: Name: Title: Date: 8

EXHIBIT C FORM OF MEMORANDUM [ATTACHED] EXHIBIT C 6645116v1

MEMORANDUM OF OPTION AGREEMENT STATE OF NEW MEXICO § § COUNTY OF LEA § STATE OF TEXAS § § COUNTIES OF LOVING AND WINKLER § KNOW ALL MEN BY THESE PRESENTS, that Salt Creek Midstream, LLC, a Delaware limited liability company (“SCM”), whose address is 200329 State Highway 249, Floor 4, Houston, Texas 77070, and Lilis Energy, Inc., a Nevada corporation (“Lilis” and, collectively with SCM, the “Parties” and individually, each a “Party”), whose address is 300 E. Sonterra Boulevard, Suite 1220, San Antonio, Texas 78258, hereby acknowledge and give notice that the Parties have executed and delivered to each other, effective as of the 21st day of May, 2018 (the “Effective Date”), that certain Option Agreement (the “Agreement”) covering lands located in Lea County, New Mexico and Loving and Winkler Counties, Texas, as more particularly described on Exhibit A attached hereto and made a part hereof for all purposes (the “AMI”), which sets forth certain rights and obligations of the Parties with respect to certain interests located within the AMI, including, without limitation, (i) an ongoing right of first refusal in favor of SCM to match offers made by Third Parties to provide certain Gas midstream services to Lilis, and (ii) an option in favor of SCM to enter into a certain agreement with Lilis to provide certain Gas midstream services as of a date set forth therein. Capitalized terms used herein but not defined herein shall have the meanings given them in the Agreement. The Agreement shall be effective until August 11, 2027 unless sooner terminated by earlier agreement; provided, however, any obligations of the Parties arising under this Agreement prior to such date shall survive the termination of the Agreement. The purpose of this Memorandum of Option Agreement (this “Memorandum”) is to evidence the existence of the Agreement, and nothing herein is intended to limit, or may be construed to limit, the terms and provisions of the Agreement or the rights and obligations of the parties thereunder. This Memorandum shall be recorded in lieu of filing the Agreement of record in the official public records of Lea County, New Mexico and Loving and Winkler Counties, Texas. A full and complete copy of the Agreement, including any amendments thereto, is available for inspection in the offices of the Parties during normal business hours at the address given above. America:0028724/00008:68904660v2

This Memorandum may be executed in any number of counterparts, each of which shall be considered an original for all purposes. [THE REMAINDER OF THIS PAGE IS INTENTIONALLY LEFT BLANK] America:0028724/00008:68904660v2

IN WITNESS WHEREOF, this Memorandum has been executed to be effective as of the Effective Date. Lilis Energy, Inc. By: Name: Title: Salt Creek Midstream, LLC By: Name: Title: [Signature Page to Memorandum of Option Agreement] America:0028724/00008:68904660v2

STATE OF TEXAS § § COUNTY OF § This instrument was acknowledged before me on the day of May, 2018, by , of Lilis Energy, Inc., a Nevada corporation, on behalf of said corporation. Notary Public, State of Texas My Commission Expires: STATE OF TEXAS § § COUNTY OF § This instrument was acknowledged before me on the day of May, 2018, by , of Salt Creek Midstream, LLC, a Delaware limited liability company, on behalf of said limited liability company. Notary Public, State of Texas My Commission Expires: [Acknowledgement Page to Memorandum of Option Agreement] America:0028724/00008:68904660v2

Exhibit A To Memorandum of Option Agreement AMI [See Attached] America:0028724/00008:68904660v2

AX A24 G A I N E A25 2 A27 2 2 E 2 29E 2 3 E 2 31E 2 32E 2 33E 2 34E 2 35E 2 36E 2 37E 2 3 E A22 C45 39E A2 A23 A24 A26 A2 A26 A3 A31 A44 A34 21 27E 21 2 E 21 29E 21 3 E 21 31E 21 32E 21 33E 21 34E 21 35E 21 36E 21 37E 21 3 E A29 A33 A36 A32 A34 A43 A35 A37 A34 A3 A39 A36 22 27E 22 2 E 22 29E 22 3 E 22 31E 22 32E 22 33E 22 34E 22 35E 22 36E 22 37E 22 3 E A3 13 14 A45 A39 A4 A49 A4 L E A A46 23 27E A5 A N D R E W A44 23 2 E 23 29E 23 3 E 23 31E 23 32E 23 33E 23 34E 23 35E 23 36E 23 37E 23 3 E Y Y A47 D D D D A43 E E A51 A42 12 A41 24 2 E 24 29E 24 3 E 24 31E 24 32E 24 33E 24 34E 24 35E 24 36E A53 24 27E 24 37E 24 3 E A52 9 A54 1 11 25 2 E 25 29E 25 3 E 25 31E 25 32E 25 33E 25 34E 25 35E 25 36E 25 37E 25 27E 25 3 E A55 73 44 T2N A22 A41 A26 43 T1N A 54 45 T2N 44 T1N 26 27E 26 2 E 26 29E 26 3 E 26 31E 26 32E 26 33E 26 34E 26 35E 26 36E 26 37E 26 3 E A56 A57 A 57 A 46 46 43 N E W M E X I C O 45 TIN 45 T1N T1N 56T1 55T1 A 57 B57 44 T1N C22 T E X A S A57 46 C23 43 T1 C C24 77 C25 46 T1N 5 T1 57 T1 57 T1 56 T1 55 T1 54 T1 76 59 T1 B1 74 44 T1 B2 WF 1 46 TI B3 7 C26 75 B2 45 T1 46 T1 B7 E C T O R 29 26 W 4 46 TI L O V I N G WW I N K L E R B27 B6 27 5 T2 57 T2 57 T2 56 T2 55 T2 54 T2 53 T2 59 T2 5 T7 B4 B4 44 T2 2 45 T2 B5 B4 5 B 5 T6 29 C U L B E R O N B1 B9 2 112 56 T3 57 T3 56 T3 2 C27 C29 B15 1 B11 44 T3 113 B12 21 45/113 56 T3 C2 B14 57 T3 2 2 VV B13 35 45 R E E V E 19 \ LILIS_ACREAGE.mxdLilis B16 \ 1 A 111 33 46 T3 16 55 T3 2 AMI 3 15 C21 13 46 \ Energy Companies F B23 5 53 T4 3 B22 52 T4 \ SALT_CREEK B19 55 T4 53 T4 1 17 R A N E 57 R A N E Projects 54 T4 52 T4 W A R D B1 B2 B17 C R A N E \ 52 53 56 \ GIS C19 34 N 63 ‘ B26 53 O 1 5 Miles 4 16 B21 54 T5 B2 Document Path: M: 55 T5 54 T4 34 34 B19

Exhibit 21.1

Subsidiaries of the Registrant

Name of Subsidiary Jurisdiction of Incorporation

Brushy Resources, Inc. Delaware

Lilis Operating Company, LLC Texas

ImPetro Resources, LLC Delaware

ImPetro Operating, LLC Delaware

Hurricane Resources, LLC Texas

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

Lilis Energy, Inc.

Fort Worth, Texas

We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (Nos. 333-212285, 333-214822, 333-220188, and 333-226742) of Lilis Energy, Inc. of our report dated April 30, 2020, relating to the consolidated financial statements, which appears in this Form 10-K. Our report contains an explanatory paragraph regarding Lilis Energy, Inc.’s ability to continue as a going concern.

/s/ BDO USA, LLP

Dallas, Texas

April 30, 2020

Exhibit 23.2

Petroleum Engineer Consent and Report Certificate of Qualification

LaRoche Petroleum Consultants, Ltd. hereby consents to the use of the name and to references to our firm in the form and context in which they appear in the Annual Report on Form 10-K of Lilis Energy, Inc. for the year ended December 31, 2019 (the “Annual Report”). We hereby further consent to the inclusion in the Annual Report of estimates of oil and natural gas reserves contained in our report dated March 12, 2020, and to the inclusion of our report as an exhibit to the Annual Report and in all current and future registration statements of the Company that incorporate by reference such Annual Report.



/s/ LaRoche Petroleum Consultants, Ltd.
LaRoche Petroleum Consultants, Ltd.
Texas Registered Engineering Firm F-1360

April 30, 2020

Exhibit 23.3

Petroleum Engineer Consent and Report Certificate of Qualification

Cawley, Gillespie & Associates, Inc. hereby consents to the use of the name, to references to our firm in the form and context in which they appear in the Annual Report on Form 10-K of Lilis Energy, Inc. for the year ended December 31, 2019 (the “Annual Report”), and to the use of and incorporation by reference in such Annual Report of our estimates of reserves, value of reserves, and our reports on reserves of estimates of oil and natural gas reserves for the years ended December 31, 2018 and December 31, 2017.



/s/ Cawley, Gillespie & Associates, Inc.
Cawley, Gillespie & Associates, Inc.
Texas Registered Engineering Firm F-693

April 30, 2020

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 302 OF THE

SARBANES-OXLEY ACT OF 2002

I, Joseph C. Daches, certify that:



	1.	I have reviewed this Annual Report on Form 10-K of Lilis Energy, Inc. (“Registrant”);



	2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;



	3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this report;



	4.	I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and have:



	a.	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to me by others within those entities, particularly during the period in which this report is being prepared;



	b.	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under my supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;



	c.	Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this report my conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and



	d.	Disclosed in this report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter (the Registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting; and



	5.	I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the audit committee of Registrant’s board of directors (or persons performing the equivalent functions):



	a.	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and



	b.	Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting.



/s/ Joseph C. Daches
Joseph C. Daches
Chief Executive Officer, President and Chief Financial Officer

April 30, 2020

Exhibit 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Lilis Energy, Inc. (the “Company”) on Form 10-K for the year ended December 31, 2019, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that


1.	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and


2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.



/s/ Joseph C. Daches
Joseph C. Daches
Chief Executive Officer, President and Chief Financial Officer

April 30, 2020

ESTIMATE OF RESERVES AND FUTURE NET CASH FLOW to the LILIS ENERGY, INC. INTEREST in Certain Properties Located in NEW MEXICO and TEXAS as of DECEMBER 31, 2019 BASED ON CONSTANT PRICES AND COSTS in Accordance with SECURITIES AND EXCHANGE COMMISSION GUIDELINES LaRoche Petroleum Consultants, Ltd.

March 12, 2020 Mr. Indranil (Neil) Barman, P.E. Vice President Lilis Energy, Inc. 201 Main Street, Suite 700 Fort Worth, TX 76102 Dear Mr. Barman: At your request, LaRoche Petroleum Consultants, Ltd. (LPC) has estimated the proved developed producing reserves and future net cash flow, as of December 31, 2019, to the Lillis Energy, Inc. (Lilis) interest in certain properties located in New Mexico and Texas. This letter replaces and supersedes our letter dated February 28, 2020, for this same property set and interests and reflects a removal of the proved developed non-producing and proved undeveloped properties. It also reflects changes of capital costs for the Grizzly 1H, Grizzly 2H, and Grizzly A 2H 2.0m cases. No reserves are assigned in the non-producing and undeveloped categories due to the impact of the going concern disclosure considerations Lilis made us aware of, whereby there is substantial doubt as to whether Lilis will be able to execute a capital program to develop such resources within the guidelines set out by the SEC. The work for this report was completed as of the date of this letter. This report was prepared to provide Lilis with U.S. Securities and Exchange Commission (SEC) compliant reserve estimates. It is our understanding that the properties evaluated by LPC comprise 100 percent (100%) of Lilis’ proved reserves. We believe the assumptions, data, methods, and procedures used in preparing this report, as set out below, are appropriate for the purpose of this report. This report has been prepared using constant prices and costs and conforms to our understanding of the SEC guidelines, reserves definitions, and applicable financial accounting rules. Summarized below are LPC’s estimates of net reserves and future net cash flow. Future net cash flow is after deducting estimated production and ad valorem taxes, operating expenses, and future capital expenditures but before consideration of federal income taxes. The discounted cash flow values included in this report are intended to represent the time value of money and should not be construed to represent an estimate of fair market value. We estimate the net reserves and future net cash flow to the Lilis interest, as of December 31, 2019, to be: Net Reserves Future Net Cash Flow ($) Oil Gas NGL Present Worth Category (Barrels) (Mcf) (Barrels) Total at 10% Proved Developed Producing 5,334,904 29,444,503 2,278,223 $174,346,304 $120,174,423 The oil reserves include crude oil, condensate, and natural gas liquids (NGL). Oil and NGL reserves are expressed in barrels which are equivalent to 42 U.S. gallons. Gas reserves are expressed in thousands of standard cubic feet (Mcf) at the contract temperature and pressure bases. 2435 N Central Expressway, Suite 1500 ● Richardson, TX 75080 ● Phone (214) 363-3337 ● Fax (214) 363-1608

The estimated reserves and future net cash flow shown in this report are for proved developed producing reserves. This report does not include any value that could be attributed to interests in undeveloped acreage. Estimates of reserves were prepared using standard geological and engineering methods generally accepted by the petroleum industry. The reserves in this report have been estimated using deterministic methods. The method or combination of methods utilized in the evaluation of each reservoir included consideration of the stage of development of the reservoir, quality and completeness of basic data, and production history. Recovery from various reservoirs and leases was estimated after consideration of the type of energy inherent in the reservoirs, the structural positions of the properties, and reservoir and well performance. In some instances, comparisons were made to similar properties where more complete data were available. We have used all methods and procedures that we considered necessary under the circumstances to prepare this report. We have excluded from our consideration all matters to which the controlling interpretation may be legal or accounting rather than engineering or geoscience. The estimated reserves and future cash flow amounts in this report are related to hydrocarbon prices. Historical prices through December 2019 were used in the preparation of this report as required by SEC guidelines; however, actual future prices may vary significantly from the SEC prices. In addition, future changes in environmental and administrative regulations may significantly affect the ability of Lilis to produce oil and gas at the projected levels. Therefore, volumes of reserves actually recovered and amounts of cash flow actually received may differ significantly from the estimated quantities presented in this report. Benchmark prices used in this report are based on the twelve-month, unweighted arithmetic average of the first day of the month price for the period January through December 2019. Gas prices are referenced to a Henry Hub price of $2.58 per MMBtu, as posted by Platts Gas Daily, and are adjusted for energy content, transportation fees, and regional price differentials. Oil and NGL prices are referenced to a West Texas Intermediate crude oil price of $55.69 per barrel at Cushing, Oklahoma, as published in Platts Oilgram, and are adjusted for gravity, crude quality, transportation fees, contractual fees, and regional price differentials. These reference prices are held constant in accordance with SEC guidelines. The weighted average prices after adjustments over the life of the properties are $53.40 per barrel for oil, $1.34 per Mcf for gas, and $14.83 per barrel for NGL. Lease and well operating expenses are based on data obtained from Lilis. Expenses for the properties operated by Lilis include direct lease and field level costs as well as compression costs, and marketing expenses. Leases and wells operated by others include all direct expenses as well as general and administrative overhead costs allowed under the specific joint operating agreements. Costs have been divided into fixed operating costs per well and variable costs per barrel of oil. Lease and well operating costs are held constant in accordance with SEC guidelines. Capital costs and timing of all investments have been provided by Lilis and are included as required for workovers, facilities and production equipment. Lilis has represented to us that they have the ability and intent to implement their capital expenditure program as scheduled. Lilis’ estimates of the cost to plug and abandon the wells net of salvage value are included and scheduled at the end of the economic life of individual properties. These abandonment costs are included for economic wells; these costs are not included for wells that are currently producing below their economic limit. These costs are also held constant. LPC has made no investigation of possible gas volume and value imbalances that may have resulted from the overdelivery or underdelivery to the Lilis interest. Our projections are based on the LaRoche Petroleum Consultants, Ltd.

Lilis interest receiving its net revenue interest share of estimated future gross oil, gas, and NGL production. Technical information necessary for the preparation of the reserve estimates herein was furnished by Lilis or was obtained from state regulatory agencies and commercially available data sources. No special tests were obtained to assist in the preparation of this report. For the purpose of this report, the individual well test and production data as reported by the above sources were accepted as represented together with all other factual data presented by Lilis including the extent and character of the interest evaluated. An on-site inspection of the properties has not been performed nor has the mechanical operation or condition of the wells and their related facilities been examined by LPC. In addition, the costs associated with the continued operation of uneconomic properties are not reflected in the cash flows. The evaluation of potential environmental liability from the operation and abandonment of the properties is beyond the scope of this report. In addition, no evaluation was made to determine the degree of operator compliance with current environmental rules, regulations, and reporting requirements. Therefore, no estimate of the potential economic liability, if any, from environmental concerns is included in the projections presented herein. The reserves included in this report are estimates only and should not be construed as exact quantities. They may or may not be recovered; if recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. These estimates should be accepted with the understanding that future development, production history, changes in regulations, product prices, and operating expenses would probably cause us to make revisions in subsequent evaluations. A portion of these reserves are for producing wells that lack sufficient production history to utilize performance-related reserve estimates. Therefore, these reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogies to similar production. These reserve estimates are subject to a greater degree of uncertainty than those based on substantial production and pressure data. It may be necessary to revise these estimates up or down in the future as additional performance data become available. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geological data; therefore, our conclusions represent informed professional judgments only, not statements of fact. The results of our third-party study were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Lilis. Lilis makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Lilis has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and Form S-8 of Lilis of the references to our name as well as to the references to our third-party report for Lilis which appears in the December 31, 2019 annual report on Form 10-K and/or 10-K/A of Lilis. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Lilis. We have provided Lilis with this digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Lilis and the original signed report letter, the original signed report letter shall control and supersede the digital version. The technical persons responsible for preparing the reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the LaRoche Petroleum Consultants, Ltd.

“Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers. The technical person primarily responsible for overseeing the preparation of reserves estimates herein is William M. Kazmann. Mr. Kazmann is a Professional Engineer licensed in the State of Texas who has 45 years of engineering experience in the oil and gas industry. He has prepared and overseen preparation of reports for public filings for LPC for the past 24 years. We are independent petroleum engineers, geologists, and geophysicists and are not employed on a contingent basis. Data pertinent to the audit are maintained on file in our office. LPC is an independent firm of petroleum engineers, geologists, and geophysicists and is not employed on a contingent basis. Data pertinent to this report are maintained on file in our office. Very truly yours, LaRoche Petroleum Consultants, Ltd. State of Texas Registration Number F-1360 By LPC, Inc. General Partner William M, Kazmann, President Licensed Professional Engineer State of Texas No. 45012 WMK:SS 19-910 Please be advised that the digital document you are viewing is provided by LaRoche Petroleum Consultants, Ltd. (LPC) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by LPC. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document. LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:22:45PM ECONOMIC SUMMARY PROJECTION Grand Total Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Partner : All Cases Discount Rate (%) : 10.00 Proved Developed Producing Cum Oil (Mbbl) : 5,588.429 Based on SEC Parameters Cum Gas (MMcf) : 94,217.521 Constant Prices & Costs Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 1,466.686 8,354.943 1,002.908 4,550.994 346.897 52.68 1.35 14.90 64,144.793 2021 915.496 6,247.665 632.937 3,424.946 264.837 53.57 1.35 14.87 42,454.165 2022 688.624 4,880.818 477.848 2,668.224 206.670 53.57 1.34 14.84 32,244.382 2023 555.973 4,037.249 386.482 2,201.728 170.762 53.57 1.34 14.81 26,179.457 2024 468.548 3,462.706 326.053 1,884.695 146.322 53.57 1.34 14.80 22,148.133 2025 402.759 3,020.288 280.670 1,641.566 127.553 53.57 1.33 14.78 19,109.333 2026 346.900 2,633.709 243.319 1,433.907 111.580 53.57 1.33 14.77 16,590.919 2027 309.769 2,368.806 217.364 1,288.663 100.326 53.57 1.33 14.76 14,838.581 2028 280.753 2,159.214 197.054 1,173.874 91.418 53.57 1.33 14.75 13,465.019 2029 255.467 1,972.777 179.344 1,072.059 83.506 53.57 1.33 14.75 12,263.422 2030 234.951 1,819.110 164.970 988.339 76.991 53.57 1.33 14.75 11,285.719 2031 216.912 1,685.978 152.517 916.060 71.361 53.57 1.33 14.75 10,439.598 2032 198.604 1,440.862 140.917 795.892 61.419 53.57 1.35 14.91 9,540.798 2033 179.232 1,286.731 127.453 709.982 54.809 53.57 1.35 14.90 8,603.855 2034 162.693 1,144.197 115.765 630.929 48.726 53.57 1.35 14.90 7,779.255 Rem 975.422 7,452.621 689.303 4,062.647 315.046 0.00 0.00 0.00 47,040.067 Total 7,658.790 53,967.675 5,334.904 29,444.503 2,278.223 53.40 1.34 14.83 358,127.496 Ult 13,247.219 148,185.196 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 36 3,429.715 1,763.438 5,243.109 11,279.909 3,683.968 38,744.654 37,080.773 37,080.773 2021 35 2,311.430 1,179.467 3,848.995 8,152.558 0.000 26,961.715 23,440.868 60,521.641 2022 33 1,763.126 899.515 3,818.951 6,253.760 0.000 19,509.030 15,409.377 75,931.018 2023 33 1,435.044 731.830 3,818.951 5,104.340 0.000 15,089.292 10,831.480 86,762.498 2024 33 1,216.109 619.906 3,818.951 4,333.813 150.256 12,009.098 7,839.299 94,601.797 2025 33 1,050.654 535.342 3,804.621 3,750.653 110.926 9,857.137 5,847.184 100,448.981 2026 31 913.682 465.889 3,589.310 3,269.396 97.953 8,254.689 4,446.894 104,895.875 2027 30 817.756 416.909 3,582.457 2,928.316 0.000 7,093.144 3,475.403 108,371.278 2028 30 742.464 378.461 3,582.457 2,660.367 0.000 6,101.270 2,717.420 111,088.698 2029 30 676.486 344.796 3,582.457 2,425.049 0.000 5,234.633 2,119.104 113,207.802 2030 30 622.738 317.394 3,582.457 2,233.001 0.000 4,530.128 1,667.215 114,875.018 2031 30 576.269 293.707 3,571.320 2,067.620 61.750 3,868.932 1,295.212 116,170.229 2032 29 524.865 269.125 3,486.475 1,872.328 97.256 3,290.748 999.515 117,169.744 2033 28 473.599 243.693 3,289.627 1,664.027 339.034 2,593.876 717.005 117,886.749 2034 25 428.260 221.346 3,088.832 1,485.213 123.500 2,432.105 612.580 118,499.329 Rem 2,549.245 1,272.999 22,759.101 9,063.967 2,618.902 8,775.854 1,675.094 Total 19,531.441 9,953.817 78,468.069 68,544.319 7,283.545 174,346.304 120,174.423 120,174.423 Present Worth Profile (M$) PW 5.000% : 141,472.965 PW 8.000% : 127,707.537 Eco. Indicators PW 9.000% : 123,800.303 ROInvestment (disc/undisc) : 29.15 / 24.94 PW 10.000% : 120,174.423 Years to Payout : 0.13 PW 12.000% : 113,655.195 Internal ROR (%) : >1000 PW 15.000% : 105,373.937 LPC Eco DetailedNGL Sum.rpt Page 1 of 1 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

3/12/2020 2:22:54PM Project Name : Lilis Energy, Inc. Economic One-Liners Ownership Group : All Cases As of Date : 1/1/2020 Sort : ONE LINE Based on SEC Parameters Filter : Proved Constant Prices & Costs Oil $55.69/bbl, Gas $2.58/mmbtu Gross Reserves Net Reserves Net Revenue Expense Cash Flow Lease Name Oil Gas Oil Gas NGL Oil Gas NGL/Other & Tax Invest. Non-Disc. Disc. 10% (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) (M$) (M$) (M$) (M$) (M$) (M$) (M$) Proved Rsv Class Producing Rsv Category $$ EAST SIDE GAS TREAT CAPITAL 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 100.000 -100.000 -97.653 A.G. HILL 1 - 1 0.000 2,807.912 0.000 1,260.402 110.562 0.000 1,273.006 1,416.150 1,553.911 97.256 1,037.988 718.989 A.G. HILL 1H - 1H 154.301 190.747 115.726 111.587 8.550 6,182.628 152.874 128.554 3,654.207 273.500 2,536.349 1,923.319 A.G. HILL 2H - 2H 479.841 2,044.019 359.880 1,195.751 89.788 19,226.618 1,638.179 1,350.084 10,285.932 273.500 11,655.449 7,688.898 ANTELOPE 1H - 1H 195.506 2,634.882 151.197 1,589.421 119.165 8,074.897 2,177.507 1,791.795 7,425.007 123.500 4,495.692 3,248.433 AXIS 1H - 1H 326.502 828.805 244.876 484.851 37.148 13,081.047 664.246 558.572 6,430.243 273.500 7,600.122 5,314.225 BISON 1H - 1H 408.985 1,999.347 266.914 1,017.764 77.979 14,273.909 1,394.336 1,172.513 7,682.311 225.745 8,932.702 5,300.163 EAST AXIS 2H - 2H 561.026 5,714.212 420.770 3,342.814 256.119 22,481.404 4,579.655 3,851.084 13,743.359 123.500 17,045.283 10,880.597 GRIZZLY 1H - 1H 154.542 804.281 100.235 406.887 31.175 5,356.900 557.435 468.753 3,786.928 660.253 1,935.908 1,314.135 GRIZZLY 2H - 2H 271.037 2,270.791 181.085 1,183.383 90.668 9,679.052 1,621.234 1,363.314 6,180.959 542.588 5,940.053 3,662.685 GRIZZLY A 2H 2.0m 616.259 3,430.130 408.033 1,771.484 135.727 21,735.318 2,426.932 2,040.835 10,003.059 1,051.524 15,148.502 11,047.829 HALEY 1H 154.806 89.988 58.516 26.531 2.033 3,119.850 36.348 30.566 1,487.601 136.750 1,562.413 1,294.117 HALEY 2H 61.427 82.662 23.219 24.372 1.867 1,236.093 33.389 28.077 720.954 136.750 439.856 398.323 HIPPO 1H - 1H 166.958 540.813 122.661 309.915 23.745 6,554.917 424.584 357.037 4,142.479 273.500 2,920.560 2,149.726 HIPPO 2H - 2H 173.697 1,097.008 109.296 538.414 41.252 5,838.215 737.627 620.279 3,682.844 105.474 3,407.804 2,475.839 HOWELL 1H - 1H 98.437 2,105.434 73.828 1,231.679 94.369 3,942.083 1,687.400 1,418.954 5,133.153 123.500 1,791.785 1,441.481 KUDU A 1H - 1H 147.063 996.944 85.656 452.920 34.702 4,575.854 620.500 521.786 3,267.032 92.614 2,358.494 1,806.160 KUDU A 2H (Was Kudu 3H) 418.725 790.546 260.742 383.975 29.419 13,884.092 526.046 442.358 5,521.859 141.326 9,189.312 7,221.400 KUDU B 1H - 1H 34.132 500.552 21.036 240.626 18.436 1,122.795 329.657 277.212 1,348.085 97.953 283.626 268.504 KUDU B 2H (Was Kudu 4H) 212.390 349.166 129.680 166.290 12.741 6,901.765 227.818 191.574 3,021.434 139.545 4,160.178 3,514.071 LION 1H - 1H 120.693 1,275.416 84.529 696.739 53.383 4,516.080 954.532 802.677 3,918.523 257.342 2,097.425 1,615.998 LION 3H - 3H 365.858 2,865.856 264.695 1,617.268 123.912 14,150.550 2,215.657 1,863.171 8,147.952 120.063 9,961.363 6,061.015 MEERKAT 1H - 1H 235.524 3,155.304 176.643 1,845.853 141.425 9,441.723 2,528.818 2,126.512 7,365.297 123.500 6,608.257 4,275.342 MOOSE 1H - 1H 386.305 2,120.069 233.004 997.418 76.420 12,454.269 1,366.463 1,149.074 6,848.693 211.344 7,909.768 5,068.177 NE AXIS 2H 295.641 3,173.493 230.103 1,926.593 147.611 12,284.766 2,639.432 2,219.529 9,335.580 123.500 7,684.647 5,412.611 OSO 1H 194.888 1,170.976 132.702 621.918 47.650 7,082.305 852.028 716.480 4,060.885 107.273 4,482.655 3,354.350 PRIZE HOG BWZ ST COM 1H - #1H 209.926 449.550 165.973 277.232 21.241 8,869.907 379.808 319.385 5,242.888 248.200 4,078.012 2,889.920 PRIZE HOG BWZ ST COM 2H - 002H 208.881 928.387 163.188 565.736 43.345 8,716.885 775.058 651.755 5,545.917 248.200 4,349.580 3,206.557 TIGER 1H - 1H 257.704 1,562.684 187.685 887.718 68.015 10,031.622 1,216.173 1,022.694 6,200.900 110.987 5,958.603 4,046.333 TIGER 3H - 3H 333.825 2,834.167 240.758 1,594.345 122.155 12,861.670 2,184.252 1,836.763 7,365.370 107.819 9,409.496 6,112.441 TUBB ESTATE 21 2 - 2 6.037 13.990 3.979 7.008 0.000 212.554 7.078 0.000 191.705 110.926 -82.999 -39.745 WILD HOG BWX ST COM 1H - #1H 242.895 1,307.020 192.039 806.023 61.756 10,264.953 1,104.252 928.578 6,802.194 248.200 5,247.389 3,562.258 WILD HOG BWX ST COM 2H - 002H 151.609 1,098.579 118.445 669.446 51.292 6,326.246 917.142 771.235 4,467.876 98.200 3,448.546 2,552.351 WOLFE UNIT 1 - 1 8.179 2,726.323 4.692 1,188.661 104.268 251.091 1,200.547 1,335.544 1,770.049 87.208 929.925 530.921 WOLFE UNIT 5&6 - 5,6 5.190 7.620 3.119 3.481 0.305 165.100 3.516 3.911 162.462 88.506 -78.441 -45.346 LPC GrossEcoOneLiner3NGL.rpt THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. Page 1 of 2 CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : $$ EAST SIDE GAS TREAT CAPITAL Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : PHANTOM Archive Set : L19910 Operator : LILIS ENERGY, INC. Reservoir : Cum Oil (Mbbl) : 0.000 Based on SEC Parameters WOLFCAMP B Co., State : Cum Gas (MMcf) : 0.000 Constant Prices & Costs WINKLER, TX API : Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 0.000 0.000 0.000 0.000 0.000 0.00 0.00 0.00 0.000 Rem 0.000 0.000 0.000 0.000 0.000 0.00 0.00 0.00 0.000 Total 0.000 0.000 0.000 0.000 0.000 0.00 0.00 0.00 0.000 Ult 0.000 0.000 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 0.000 0.000 0.000 0.000 100.000 -100.000 -97.653 -97.653 Rem 0.000 0.000 0.000 0.000 0.000 0.000 0.000 Total 0.000 0.000 0.000 0.000 100.000 -100.000 -97.653 -97.653 Major Phase : Oil Abandonment Date : 04/30/2020 Present Worth Profile (M$) Perfs : 0 - 0 Working Int : 1.00000000 PW 5.000% : -98.792 Initial Rate : 0.000 bbl/month Revenue Int : 0.75000000 PW 8.000% : -98.101 Abandonment : 0.000 bbl/month Disc. Initial Invest. (M$) : 97.653 PW 9.000% : -97.876 Initial Decline : 0.00 % year b = 0.000 ROInvestment (disc/undisc) : 0.00 / 0.00 PW 10.000% : -97.653 Beg Ratio : 0.000 mcf/bbl Years to Payout : 0.00 PW 12.000% : -97.216 End Ratio : 0.000 mcf/bbl Internal ROR (%) : 0.000 PW 15.000% : -96.578 LPC Eco DetailedNGL.rpt Page 1 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : A.G. HILL 1 - 1 Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : CHEYENNE (ATOKA) Archive Set : L19910 Operator : LILIS ENERGY, INC. Reservoir : Cum Oil (Mbbl) : 2.660 Based on SEC Parameters ATOKA Co., State : Cum Gas (MMcf) : 4,415.387 Constant Prices & Costs Winkler, TX API : 42495309140100 Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 0.000 355.944 0.000 159.774 14.015 0.00 1.01 12.81 340.890 2021 0.000 326.554 0.000 146.582 12.858 0.00 1.01 12.81 312.743 2022 0.000 300.447 0.000 134.863 11.830 0.00 1.01 12.81 287.740 2023 0.000 276.427 0.000 124.081 10.884 0.00 1.01 12.81 264.736 2024 0.000 254.996 0.000 114.461 10.040 0.00 1.01 12.81 244.211 2025 0.000 233.941 0.000 105.010 9.211 0.00 1.01 12.81 224.047 2026 0.000 215.238 0.000 96.615 8.475 0.00 1.01 12.81 206.135 2027 0.000 198.031 0.000 88.891 7.797 0.00 1.01 12.81 189.655 2028 0.000 182.677 0.000 81.999 7.193 0.00 1.01 12.81 174.951 2029 0.000 167.594 0.000 75.229 6.599 0.00 1.01 12.81 160.506 2030 0.000 154.195 0.000 69.214 6.071 0.00 1.01 12.81 147.674 2031 0.000 141.868 0.000 63.681 5.586 0.00 1.01 12.81 135.868 2032 0.000 0.000 0.000 0.000 0.000 0.00 0.00 0.00 0.000 Rem 0.000 0.000 0.000 0.000 0.000 0.00 0.00 0.00 0.000 Total 0.000 2,807.912 0.000 1,260.402 110.562 0.00 1.01 12.81 2,689.155 Ult 2.660 7,223.299 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 25.679 8.522 15.630 139.004 0.000 152.055 145.110 145.110 2021 1 23.558 7.819 15.630 127.526 0.000 138.210 119.899 265.009 2022 1 21.675 7.194 15.630 117.331 0.000 125.910 99.306 364.315 2023 1 19.942 6.618 15.630 107.951 0.000 114.595 82.171 446.486 2024 1 18.396 6.105 15.630 99.581 0.000 104.498 68.116 514.602 2025 1 16.877 5.601 15.630 91.359 0.000 94.579 56.042 570.643 2026 1 15.528 5.153 15.630 84.055 0.000 85.769 46.204 616.848 2027 1 14.286 4.741 15.630 77.335 0.000 77.662 38.037 654.884 2028 1 13.179 4.374 15.630 71.339 0.000 70.429 31.357 686.242 2029 1 12.091 4.013 15.630 65.449 0.000 63.323 25.629 711.870 2030 1 11.124 3.692 15.630 60.216 0.000 57.011 20.978 732.848 2031 1 10.235 3.397 15.630 55.402 0.000 51.204 17.129 749.977 2032 1 0.000 0.000 0.000 0.000 97.256 -97.256 -30.989 718.989 Rem 0.000 0.000 0.000 0.000 0.000 0.000 0.000 Total 202.569 67.229 187.564 1,096.549 97.256 1,037.988 718.989 718.989 Major Phase : Gas Abandonment Date : 01/01/2032 Present Worth Profile (M$) Perfs : 14686 - 14702 Working Int : 0.78750000 PW 5.000% : 853.361 Initial Rate : 30,848.010 mcf/month Revenue Int : 0.59062500 PW 8.000% : 767.894 Abandonment : 11,341.776 mcf/month Disc. Initial Invest. (M$) : 30.989 PW 9.000% : 742.714 Initial Decline : 8.00 % year b = 0.000 ROInvestment (disc/undisc) : 24.20 / 11.67 PW 10.000% : 718.989 Beg Ratio : 0.000 bbl/mcf Years to Payout : 0.63 PW 12.000% : 675.486 End Ratio : 0.000 bbl/mcf Internal ROR (%) : >1000 PW 15.000% : 618.771 LPC Eco DetailedNGL.rpt Page 2 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : A.G. HILL 1H - 1H Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : PHANTOM Archive Set : L19910 Operator : LILIS ENERGY, INC. Reservoir : Cum Oil (Mbbl) : 80.786 Based on SEC Parameters WOLFCAMP B Co., State : Cum Gas (MMcf) : 105.788 Constant Prices & Costs WINKLER, TX API : 42495339400000 Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 26.662 24.816 19.996 14.518 1.112 52.73 1.37 15.04 1,091.025 2021 19.639 25.531 14.729 14.935 1.144 53.57 1.37 15.04 826.712 2022 15.670 20.371 11.752 11.917 0.913 53.57 1.37 15.04 659.636 2023 13.083 17.008 9.812 9.950 0.762 53.57 1.37 15.04 550.744 2024 11.286 14.672 8.464 8.583 0.658 53.57 1.37 15.04 475.081 2025 9.892 12.860 7.419 7.523 0.576 53.57 1.37 15.04 416.422 2026 8.837 11.488 6.628 6.721 0.515 53.57 1.37 15.04 372.003 2027 7.994 10.392 5.995 6.079 0.466 53.57 1.37 15.04 336.499 2028 7.323 9.519 5.492 5.569 0.427 53.57 1.37 15.04 308.247 2029 6.726 8.744 5.045 5.115 0.392 53.57 1.37 15.04 283.135 2030 6.238 8.110 4.679 4.744 0.363 53.57 1.37 15.04 262.597 2031 5.819 7.565 4.364 4.425 0.339 53.57 1.37 15.04 244.958 2032 5.469 7.110 4.102 4.159 0.319 53.57 1.37 15.04 230.237 2033 5.126 6.664 3.845 3.898 0.299 53.57 1.37 15.04 215.787 2034 4.537 5.898 3.403 3.450 0.264 53.57 1.37 15.04 190.974 Rem 0.000 0.000 0.000 0.000 0.000 0.00 0.00 0.00 0.000 Total 154.301 190.747 115.726 111.587 8.550 53.42 1.37 15.04 6,464.056 Ult 235.087 296.535 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 51.422 27.276 215.634 115.603 150.000 531.090 507.273 507.273 2021 1 39.251 20.668 160.704 94.547 0.000 511.541 444.598 951.871 2022 1 31.319 16.491 160.704 75.440 0.000 375.683 296.728 1,248.599 2023 1 26.149 13.769 160.704 62.986 0.000 287.137 206.134 1,454.733 2024 1 22.556 11.877 160.704 54.333 0.000 225.611 147.216 1,601.949 2025 1 19.771 10.411 160.704 47.624 0.000 177.912 105.512 1,707.461 2026 1 17.662 9.300 160.704 42.544 0.000 141.793 76.447 1,783.907 2027 1 15.977 8.412 160.704 38.484 0.000 112.922 55.348 1,839.256 2028 1 14.635 7.706 160.704 35.253 0.000 89.948 40.085 1,879.340 2029 1 13.443 7.078 160.704 32.381 0.000 69.529 28.163 1,907.503 2030 1 12.468 6.565 160.704 30.032 0.000 52.828 19.456 1,926.959 2031 1 11.630 6.124 160.704 28.015 0.000 38.485 12.888 1,939.847 2032 1 10.931 5.756 160.704 26.331 0.000 26.515 8.080 1,947.927 2033 1 10.245 5.395 160.704 24.679 0.000 14.764 4.093 1,952.019 2034 1 9.067 4.774 151.200 21.841 123.500 -119.409 -28.700 1,923.319 Rem 0.000 0.000 0.000 0.000 0.000 0.000 0.000 Total 306.526 161.601 2,455.986 730.093 273.500 2,536.349 1,923.319 1,923.319 Major Phase : Oil Abandonment Date : 12/09/2034 Present Worth Profile (M$) Perfs : 0 - 0 Working Int : 1.00000000 PW 5.000% : 2,190.571 Initial Rate : 2,664.407 bbl/month Revenue Int : 0.75000000 PW 8.000% : 2,022.212 Abandonment : 390.997 bbl/month Disc. Initial Invest. (M$) : 172.784 PW 9.000% : 1,971.537 Initial Decline : 35.37 % year b = 1.100 ROInvestment (disc/undisc) : 12.13 / 10.27 PW 10.000% : 1,923.319 Beg Ratio : 0.000 mcf/bbl Years to Payout : 0.39 PW 12.000% : 1,833.679 End Ratio : 1.300 mcf/bbl Internal ROR (%) : >1000 PW 15.000% : 1,714.262 LPC Eco DetailedNGL.rpt Page 3 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : A.G. HILL 2H - 2H Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : PHANTOM Archive Set : L19910 Operator : LILIS ENERGY, INC. Reservoir : Cum Oil (Mbbl) : 119.631 Based on SEC Parameters 2ND BONE SPRINGS Co., State : Cum Gas (MMcf) : 576.556 Constant Prices & Costs WINKLER, TX API : 4249533951 Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 79.810 283.883 59.857 166.071 10.896 52.70 1.37 15.04 3,545.732 2021 53.395 234.939 40.046 137.439 10.530 53.57 1.37 15.04 2,491.910 2022 40.635 178.795 30.476 104.595 8.014 53.57 1.37 15.04 1,896.413 2023 32.814 144.382 24.611 84.463 6.471 53.57 1.37 15.04 1,531.408 2024 27.594 121.412 20.695 71.026 5.442 53.57 1.37 15.04 1,287.775 2025 23.697 104.265 17.773 60.995 4.673 53.57 1.37 15.04 1,105.906 2026 20.812 91.574 15.609 53.571 4.104 53.57 1.37 15.04 971.293 2027 18.555 81.641 13.916 47.760 3.659 53.57 1.37 15.04 865.934 2028 16.783 73.846 12.587 43.200 3.310 53.57 1.37 15.04 783.260 2029 15.244 67.076 11.433 39.239 3.006 53.57 1.37 15.04 711.448 2030 13.998 61.591 10.498 36.031 2.761 53.57 1.37 15.04 653.274 2031 12.940 56.936 9.705 33.308 2.552 53.57 1.37 15.04 603.902 2032 12.063 53.076 9.047 31.050 2.379 53.57 1.37 15.04 562.960 2033 11.239 49.453 8.429 28.930 2.217 53.57 1.37 15.04 524.527 2034 10.546 46.402 7.909 27.145 2.080 53.57 1.37 15.04 492.170 Rem 89.716 394.750 67.287 230.929 17.693 0.00 0.00 0.00 4,186.971 Total 479.841 2,044.019 359.880 1,195.751 89.788 53.43 1.37 15.04 22,214.882 Ult 599.472 2,620.575 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 175.056 88.643 187.596 617.602 150.000 2,326.834 2,231.161 2,231.161 2021 1 125.102 62.298 160.704 471.513 0.000 1,672.294 1,453.590 3,684.750 2022 1 95.206 47.410 160.704 358.835 0.000 1,234.258 974.803 4,659.553 2023 1 76.881 38.285 160.704 289.769 0.000 965.768 693.208 5,352.761 2024 1 64.650 32.194 160.704 243.670 0.000 786.557 513.100 5,865.861 2025 1 55.520 27.648 160.704 209.257 0.000 652.778 387.019 6,252.879 2026 1 48.762 24.282 160.704 183.786 0.000 553.759 298.446 6,551.325 2027 1 43.473 21.648 160.704 163.850 0.000 476.259 233.334 6,784.659 2028 1 39.322 19.581 160.704 148.206 0.000 415.446 185.015 6,969.674 2029 1 35.717 17.786 160.704 134.618 0.000 362.622 146.785 7,116.459 2030 1 32.796 16.332 160.704 123.611 0.000 319.831 117.695 7,234.155 2031 1 30.318 15.098 160.704 114.269 0.000 283.514 94.848 7,329.002 2032 1 28.262 14.074 160.704 106.522 0.000 253.397 77.062 7,406.064 2033 1 26.333 13.113 160.704 99.250 0.000 225.127 62.231 7,468.295 2034 1 24.708 12.304 160.704 93.127 0.000 201.326 50.594 7,518.890 Rem 210.199 104.674 2,030.671 792.248 123.500 925.679 170.009 Total 1,112.305 555.372 4,468.123 4,150.133 273.500 11,655.449 7,688.898 7,688.898 Major Phase : Oil Abandonment Date : 08/23/2047 Present Worth Profile (M$) Perfs : 0 - 0 Working Int : 1.00000000 PW 5.000% : 9,205.979 Initial Rate : 9,700.000 bbl/month Revenue Int : 0.75000000 PW 8.000% : 8,218.814 Abandonment : 389.877 bbl/month Disc. Initial Invest. (M$) : 148.511 PW 9.000% : 7,943.038 Initial Decline : 44.01 % year b = 1.001 ROInvestment (disc/undisc) : 52.77 / 43.62 PW 10.000% : 7,688.898 Beg Ratio : 4.204 mcf/bbl Years to Payout : 0.08 PW 12.000% : 7,236.290 End Ratio : 4.400 mcf/bbl Internal ROR (%) : >1000 PW 15.000% : 6,669.346 LPC Eco DetailedNGL.rpt Page 4 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : ANTELOPE 1H - 1H Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : PHANTOM Archive Set : L19910 Operator : LILIS ENERGY, INC. Reservoir : Cum Oil (Mbbl) : 63.513 Based on SEC Parameters 3RD BONE SPRINGS Co., State : Cum Gas (MMcf) : 984.016 Constant Prices & Costs WINKLER, TX API : 4249534034 Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 36.465 408.302 28.201 246.297 16.257 52.69 1.37 15.04 2,067.844 2021 23.874 334.241 18.464 201.622 15.448 53.57 1.37 15.04 1,497.593 2022 17.975 251.647 13.901 151.799 11.631 53.57 1.37 15.04 1,127.523 2023 14.421 201.900 11.153 121.790 9.331 53.57 1.37 15.04 904.626 2024 12.075 169.043 9.338 101.971 7.813 53.57 1.37 15.04 757.410 2025 10.337 144.718 7.994 87.297 6.689 53.57 1.37 15.04 648.419 2026 9.058 126.805 7.005 76.492 5.861 53.57 1.37 15.04 568.159 2027 8.060 112.844 6.234 68.070 5.215 53.57 1.37 15.04 505.605 2028 7.280 101.920 5.630 61.481 4.711 53.57 1.37 15.04 456.662 2029 6.605 92.465 5.108 55.777 4.273 53.57 1.37 15.04 414.295 2030 6.058 84.819 4.685 51.165 3.920 53.57 1.37 15.04 380.037 2031 5.596 78.342 4.328 47.258 3.621 53.57 1.37 15.04 351.017 2032 5.213 72.977 4.031 44.022 3.373 53.57 1.37 15.04 326.980 2033 4.854 67.952 3.754 40.990 3.141 53.57 1.37 15.04 304.464 2034 4.552 63.729 3.520 38.443 2.945 53.57 1.37 15.04 285.543 Rem 23.084 323.178 17.852 194.948 14.937 0.00 0.00 0.00 1,448.022 Total 195.506 2,634.882 151.197 1,589.421 119.165 53.41 1.37 15.04 12,044.199 Ult 259.019 3,618.898 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 112.397 51.696 174.339 653.251 0.000 1,076.161 1,029.063 1,029.063 2021 1 83.927 37.440 107.676 516.054 0.000 752.497 654.236 1,683.298 2022 1 63.188 28.188 107.676 388.531 0.000 539.940 426.519 2,109.817 2023 1 50.696 22.616 107.676 311.724 0.000 411.914 295.715 2,405.532 2024 1 42.446 18.935 107.676 260.995 0.000 327.358 213.586 2,619.118 2025 1 36.338 16.210 107.676 223.438 0.000 264.756 156.995 2,776.114 2026 1 31.840 14.204 107.676 195.781 0.000 218.658 117.865 2,893.979 2027 1 28.335 12.640 107.676 174.226 0.000 182.728 89.541 2,983.520 2028 1 25.592 11.417 107.676 157.360 0.000 154.617 68.873 3,052.392 2029 1 23.218 10.357 107.676 142.761 0.000 130.283 52.748 3,105.140 2030 1 21.298 9.501 107.676 130.956 0.000 110.606 40.711 3,145.851 2031 1 19.671 8.775 107.676 120.956 0.000 93.938 31.434 3,177.285 2032 1 18.324 8.175 107.676 112.674 0.000 80.132 24.377 3,201.662 2033 1 17.063 7.612 107.676 104.915 0.000 67.199 18.581 3,220.243 2034 1 16.002 7.139 107.676 98.395 0.000 56.331 14.161 3,234.404 Rem 81.149 36.201 679.626 498.972 123.500 28.575 14.029 Total 671.484 301.105 2,361.429 4,090.988 123.500 4,495.692 3,248.433 3,248.433 Major Phase : Oil Abandonment Date : 04/25/2041 Present Worth Profile (M$) Perfs : 0 - 0 Working Int : 1.00000000 PW 5.000% : 3,762.990 Initial Rate : 4,488.000 bbl/month Revenue Int : 0.77336256 PW 8.000% : 3,433.950 Abandonment : 248.914 bbl/month Disc. Initial Invest. (M$) : 16.196 PW 9.000% : 3,338.197 Initial Decline : 46.71 % year b = 1.000 ROInvestment (disc/undisc) : 201.57 / 37.40 PW 10.000% : 3,248.433 Beg Ratio : 12.599 mcf/bbl Years to Payout : 0.10 PW 12.000% : 3,084.906 End Ratio : 14.000 mcf/bbl Internal ROR (%) : >1000 PW 15.000% : 2,873.424 LPC Eco DetailedNGL.rpt Page 5 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : AXIS 1H - 1H Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : PHANTOM Archive Set : L19910 Operator : LILIS ENERGY, INC. Reservoir : Cum Oil (Mbbl) : 166.904 Based on SEC Parameters WOLFCAMP B Co., State : Cum Gas (MMcf) : 373.844 Constant Prices & Costs WINKLER, TX API : 4249534139 Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 57.273 141.029 42.955 82.502 6.321 52.71 1.37 15.04 2,472.195 2021 38.759 97.128 29.069 56.820 4.353 53.57 1.37 15.04 1,700.532 2022 29.388 74.303 22.041 43.467 3.330 53.57 1.37 15.04 1,290.344 2023 23.678 60.193 17.759 35.213 2.698 53.57 1.37 15.04 1,040.135 2024 19.881 50.726 14.911 29.675 2.274 53.57 1.37 15.04 873.612 2025 17.055 43.630 12.791 25.524 1.956 53.57 1.37 15.04 749.590 2026 14.967 38.364 11.225 22.443 1.720 53.57 1.37 15.04 657.922 2027 13.335 34.234 10.001 20.027 1.534 53.57 1.37 15.04 586.260 2028 12.055 30.988 9.041 18.128 1.389 53.57 1.37 15.04 530.072 2029 10.945 28.164 8.209 16.476 1.262 53.57 1.37 15.04 481.313 2030 10.047 25.875 7.535 15.137 1.160 53.57 1.37 15.04 441.834 2031 9.285 23.929 6.964 13.999 1.073 53.57 1.37 15.04 408.346 2032 8.653 22.315 6.490 13.054 1.000 53.57 1.37 15.04 380.585 2033 8.061 20.799 6.045 12.167 0.932 53.57 1.37 15.04 354.540 2034 7.562 19.520 5.672 11.419 0.875 53.57 1.37 15.04 332.625 Rem 45.559 117.606 34.169 68.800 5.271 0.00 0.00 0.00 2,003.962 Total 326.502 828.805 244.876 484.851 37.148 53.42 1.37 15.04 14,303.865 Ult 493.406 1,202.649 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 120.162 61.805 187.596 291.468 150.000 1,661.164 1,593.558 1,593.558 2021 1 82.656 42.513 160.704 198.590 0.000 1,216.068 1,057.156 2,650.714 2022 1 62.744 32.259 160.704 151.099 0.000 883.538 697.884 3,348.598 2023 1 50.591 26.003 160.704 122.002 0.000 680.835 488.740 3,837.339 2024 1 42.498 21.840 160.704 102.585 0.000 545.984 356.207 4,193.545 2025 1 36.470 18.740 160.704 88.093 0.000 445.583 264.206 4,457.751 2026 1 32.013 16.448 160.704 77.368 0.000 371.390 200.181 4,657.933 2027 1 28.528 14.656 160.704 68.974 0.000 313.397 153.561 4,811.494 2028 1 25.795 13.252 160.704 62.387 0.000 267.933 119.339 4,930.833 2029 1 23.424 12.033 160.704 56.667 0.000 228.486 92.500 5,023.334 2030 1 21.503 11.046 160.704 52.033 0.000 196.548 72.338 5,095.672 2031 1 19.874 10.209 160.704 48.100 0.000 169.459 56.700 5,152.372 2032 1 18.524 9.515 160.704 44.838 0.000 147.004 44.716 5,197.088 2033 1 17.256 8.864 160.704 41.777 0.000 125.939 34.819 5,231.907 2034 1 16.190 8.316 160.704 39.199 0.000 108.216 27.201 5,259.107 Rem 97.540 50.099 1,258.078 236.167 123.500 238.577 55.118 Total 695.769 357.597 3,695.530 1,681.348 273.500 7,600.122 5,314.225 5,314.225 Major Phase : Oil Abandonment Date : 11/02/2042 Present Worth Profile (M$) Perfs : 0 - 0 Working Int : 1.00000000 PW 5.000% : 6,231.170 Initial Rate : 6,065.589 bbl/month Revenue Int : 0.74999998 PW 8.000% : 5,640.992 Abandonment : 376.353 bbl/month Disc. Initial Invest. (M$) : 153.659 PW 9.000% : 5,471.820 Initial Decline : 44.93 % year b = 1.000 ROInvestment (disc/undisc) : 35.58 / 28.79 PW 10.000% : 5,314.225 Beg Ratio : 2.430 mcf/bbl Years to Payout : 0.13 PW 12.000% : 5,029.515 End Ratio : 2.581 mcf/bbl Internal ROR (%) : >1000 PW 15.000% : 4,665.620 LPC Eco DetailedNGL.rpt Page 6 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : BISON 1H - 1H Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : PHANTOM (WOLFCAMP) Archive Set : L19910 Operator : IMPETRO OPERATING LLC Reservoir : Cum Oil (Mbbl) : 312.509 Based on SEC Parameters WOLFCAMP B Co., State : Cum Gas (MMcf) : 917.445 Constant Prices & Costs Winkler, TX API : 4249531011 Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 46.273 212.573 30.199 108.210 8.291 52.75 1.37 15.04 1,865.965 2021 37.140 174.585 24.238 88.872 6.809 53.57 1.37 15.04 1,522.587 2022 31.090 148.457 20.290 75.572 5.790 53.57 1.37 15.04 1,277.528 2023 26.738 129.144 17.450 65.740 5.037 53.57 1.37 15.04 1,100.594 2024 23.517 114.579 15.348 58.326 4.469 53.57 1.37 15.04 969.292 2025 20.888 102.465 13.632 52.160 3.996 53.57 1.37 15.04 861.803 2026 18.831 92.889 12.290 47.285 3.623 53.57 1.37 15.04 777.618 2027 17.144 84.951 11.189 43.244 3.313 53.57 1.37 15.04 708.437 2028 15.776 78.470 10.296 39.945 3.060 53.57 1.37 15.04 652.285 2029 14.536 72.539 9.487 36.926 2.829 53.57 1.37 15.04 601.334 2030 13.510 67.608 8.817 34.416 2.637 53.57 1.37 15.04 559.138 2031 12.620 63.305 8.236 32.225 2.469 53.57 1.37 15.04 522.481 2032 11.870 59.633 7.747 30.356 2.326 53.57 1.37 15.04 491.552 2033 11.126 55.900 7.261 28.456 2.180 53.57 1.37 15.04 460.747 2034 10.459 52.548 6.826 26.750 2.049 53.57 1.37 15.04 433.120 Rem 97.468 489.700 63.610 249.281 19.099 0.00 0.00 0.00 4,036.279 Total 408.985 1,999.347 266.914 1,017.764 77.979 53.48 1.37 15.04 16,840.759 Ult 721.494 2,916.792 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 94.070 46.649 177.982 266.709 123.809 1,156.745 1,104.218 1,104.218 2021 1 76.798 38.065 132.644 216.816 0.000 1,058.264 918.955 2,023.173 2022 1 64.511 31.938 132.644 183.097 0.000 865.338 682.990 2,706.163 2023 1 55.623 27.515 132.644 158.484 0.000 726.328 521.098 3,227.261 2024 1 49.019 24.232 132.644 140.080 0.000 623.317 406.465 3,633.726 2025 1 43.605 21.545 132.644 124.900 0.000 539.109 319.533 3,953.259 2026 1 39.362 19.440 132.644 112.957 0.000 473.215 254.974 4,208.234 2027 1 35.872 17.711 132.644 103.103 0.000 419.107 205.290 4,413.524 2028 1 33.038 16.307 132.644 95.082 0.000 375.214 167.066 4,580.591 2029 1 30.465 15.033 132.644 87.773 0.000 335.419 135.750 4,716.341 2030 1 28.333 13.978 132.644 81.709 0.000 302.473 111.290 4,827.631 2031 1 26.481 13.062 132.644 76.430 0.000 273.865 91.606 4,919.237 2032 1 24.916 12.289 132.644 71.951 0.000 249.753 75.943 4,995.180 2033 1 23.354 11.519 132.644 67.444 0.000 225.786 62.408 5,057.588 2034 1 21.954 10.828 132.644 63.400 0.000 204.295 51.338 5,108.926 Rem 204.592 100.907 1,933.541 590.827 101.936 1,104.475 191.237 Total 851.995 421.019 3,968.536 2,440.762 225.745 8,932.702 5,300.163 5,300.163 Major Phase : Oil Abandonment Date : 08/01/2049 Present Worth Profile (M$) Perfs : 0 - 0 Working Int : 0.82539157 PW 5.000% : 6,640.020 Initial Rate : 4,350.235 bbl/month Revenue Int : 0.65262587 PW 8.000% : 5,760.371 Abandonment : 342.918 bbl/month Disc. Initial Invest. (M$) : 124.145 PW 9.000% : 5,519.780 Initial Decline : 23.90 % year b = 1.000 ROInvestment (disc/undisc) : 43.69 / 40.57 PW 10.000% : 5,300.163 Beg Ratio : 4.528 mcf/bbl Years to Payout : 0.17 PW 12.000% : 4,914.184 End Ratio : 5.024 mcf/bbl Internal ROR (%) : >1000 PW 15.000% : 4,440.405 LPC Eco DetailedNGL.rpt Page 7 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : EAST AXIS 2H - 2H Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : PHANTOM Archive Set : L19910 Operator : LILIS ENERGY, INC. Reservoir : Cum Oil (Mbbl) : 113.791 Based on SEC Parameters WOLFCAMP A Co., State : Cum Gas (MMcf) : 1,093.632 Constant Prices & Costs WINKLER, TX API : 4249534152 Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 93.512 676.155 70.134 395.551 30.306 52.73 1.37 15.04 4,695.467 2021 67.318 698.538 50.489 408.645 31.309 53.57 1.37 15.04 3,735.310 2022 52.734 556.381 39.550 325.483 24.938 53.57 1.37 15.04 2,939.585 2023 43.358 462.430 32.519 270.522 20.727 53.57 1.37 15.04 2,424.295 2024 36.913 396.691 27.685 232.064 17.780 53.57 1.37 15.04 2,068.363 2025 31.986 345.680 23.990 202.223 15.494 53.57 1.37 15.04 1,795.151 2026 28.285 307.009 21.214 179.600 13.761 53.57 1.37 15.04 1,589.399 2027 25.353 276.129 19.015 161.535 12.376 53.57 1.37 15.04 1,426.024 2028 23.032 251.556 17.274 147.160 11.275 53.57 1.37 15.04 1,296.526 2029 20.996 229.846 15.747 134.460 10.302 53.57 1.37 15.04 1,182.667 2030 19.337 212.100 14.503 124.078 9.507 53.57 1.37 15.04 1,089.834 2031 17.921 196.900 13.441 115.187 8.825 53.57 1.37 15.04 1,010.527 2032 16.743 184.222 12.557 107.770 8.257 53.57 1.37 15.04 944.483 2033 15.630 172.188 11.722 100.730 7.718 53.57 1.37 15.04 882.007 2034 14.683 161.827 11.012 94.669 7.253 53.57 1.37 15.04 828.677 Rem 53.224 586.559 39.918 343.137 26.290 0.00 0.00 0.00 3,003.829 Total 561.026 5,714.212 420.770 3,342.814 256.119 53.43 1.37 15.04 30,912.143 Ult 674.817 6,807.844 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 245.769 117.387 174.339 1,168.721 0.000 2,989.252 2,857.593 2,857.593 2021 1 202.409 93.383 107.676 1,115.732 0.000 2,216.110 1,925.493 4,783.086 2022 1 159.576 73.490 107.676 885.904 0.000 1,712.940 1,352.460 6,135.546 2023 1 131.757 60.607 107.676 734.836 0.000 1,389.419 997.056 7,132.603 2024 1 112.505 51.709 107.676 629.491 0.000 1,166.982 761.097 7,893.700 2025 1 97.704 44.879 107.676 547.981 0.000 996.911 590.936 8,484.636 2026 1 86.546 39.735 107.676 486.294 0.000 869.147 468.339 8,952.976 2027 1 77.679 35.651 107.676 437.108 0.000 767.910 376.159 9,329.135 2028 1 70.647 32.413 107.676 398.007 0.000 687.783 306.240 9,635.375 2029 1 64.459 29.567 107.676 363.505 0.000 617.461 249.900 9,885.275 2030 1 59.412 27.246 107.676 335.321 0.000 560.179 206.108 10,091.383 2031 1 55.099 25.263 107.676 311.196 0.000 511.292 171.022 10,262.405 2032 1 51.506 23.612 107.676 291.082 0.000 470.607 143.090 10,405.496 2033 1 48.105 22.050 107.676 272.008 0.000 432.167 119.443 10,524.938 2034 1 45.199 20.717 107.676 255.620 0.000 399.465 100.373 10,625.311 Rem 163.838 75.096 457.199 926.538 123.500 1,257.658 255.286 Total 1,672.209 772.804 2,139.002 9,159.345 123.500 17,045.283 10,880.597 10,880.597 Major Phase : Oil Abandonment Date : 04/01/2039 Present Worth Profile (M$) Perfs : 0 - 0 Working Int : 1.00000000 PW 5.000% : 13,241.587 Initial Rate : 9,461.224 bbl/month Revenue Int : 0.74999996 PW 8.000% : 11,704.338 Abandonment : 912.500 bbl/month Disc. Initial Invest. (M$) : 19.723 PW 9.000% : 11,275.412 Initial Decline : 37.19 % year b = 1.000 ROInvestment (disc/undisc) : 552.66 / 139.02 PW 10.000% : 10,880.597 Beg Ratio : 0.000 mcf/bbl Years to Payout : 0.04 PW 12.000% : 10,179.037 End Ratio : 11.022 mcf/bbl Internal ROR (%) : >1000 PW 15.000% : 9,304.473 LPC Eco DetailedNGL.rpt Page 8 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : GRIZZLY 1H - 1H Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : PHANTOM (WOLFCAMP) Archive Set : L19910 Operator : IMPETRO OPERATING LLC Reservoir : Cum Oil (Mbbl) : 138.810 Based on SEC Parameters WOLFCAMP B Co., State : Cum Gas (MMcf) : 838.764 Constant Prices & Costs Winkler, TX API : 4249531979 Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 23.720 121.979 15.384 61.710 4.728 52.75 1.37 15.04 967.099 2021 18.552 95.932 12.032 48.532 3.718 53.57 1.37 15.04 766.974 2022 15.269 79.239 9.903 40.087 3.071 53.57 1.37 15.04 631.616 2023 12.975 67.504 8.416 34.151 2.617 53.57 1.37 15.04 536.959 2024 11.311 58.954 7.336 29.825 2.285 53.57 1.37 15.04 468.219 2025 9.977 52.075 6.471 26.345 2.018 53.57 1.37 15.04 413.094 2026 8.946 46.743 5.802 23.647 1.812 53.57 1.37 15.04 370.452 2027 8.108 42.403 5.258 21.452 1.644 53.57 1.37 15.04 335.799 2028 7.433 38.903 4.821 19.681 1.508 53.57 1.37 15.04 307.887 2029 6.827 35.756 4.428 18.089 1.386 53.57 1.37 15.04 282.831 2030 6.328 33.161 4.104 16.776 1.285 53.57 1.37 15.04 262.186 2031 5.897 30.918 3.825 15.641 1.198 53.57 1.37 15.04 244.352 2032 5.536 29.036 3.591 14.689 1.125 53.57 1.37 15.04 229.399 2033 5.186 27.206 3.364 13.763 1.055 53.57 1.37 15.04 214.911 2034 4.875 25.574 3.162 12.938 0.991 53.57 1.37 15.04 202.025 Rem 3.603 18.898 2.337 9.561 0.733 0.00 0.00 0.00 149.286 Total 154.542 804.281 100.235 406.887 31.175 53.44 1.37 15.04 6,383.088 Ult 293.352 1,643.045 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 49.168 24.177 192.917 150.346 549.763 0.727 -18.427 -18.427 2021 1 38.962 19.174 143.774 117.953 0.000 447.111 388.438 370.011 2022 1 32.095 15.790 143.774 97.275 0.000 342.682 270.591 640.602 2023 1 27.290 13.424 143.774 82.779 0.000 269.691 193.573 834.175 2024 1 23.800 11.705 143.774 72.235 0.000 216.705 141.383 975.558 2025 1 21.000 10.327 143.774 63.767 0.000 174.226 103.313 1,078.871 2026 1 18.834 9.261 143.774 57.210 0.000 141.373 76.211 1,155.082 2027 1 17.073 8.395 143.774 51.878 0.000 114.679 56.203 1,211.286 2028 1 15.655 7.697 143.774 47.580 0.000 93.181 41.519 1,252.805 2029 1 14.382 7.071 143.774 43.719 0.000 73.885 29.923 1,282.727 2030 1 13.333 6.555 143.774 40.537 0.000 57.988 21.352 1,304.080 2031 1 12.426 6.109 143.774 37.786 0.000 44.257 14.817 1,318.897 2032 1 11.666 5.735 143.774 35.480 0.000 32.744 9.972 1,328.869 2033 1 10.929 5.373 143.774 33.241 0.000 21.593 5.978 1,334.848 2034 1 10.274 5.051 143.774 31.248 0.000 11.678 2.944 1,337.792 Rem 7.592 3.732 110.992 23.091 110.489 -106.611 -23.657 Total 324.481 159.577 2,316.746 986.124 660.253 1,935.908 1,314.135 1,314.135 Major Phase : Oil Abandonment Date : 10/12/2035 Present Worth Profile (M$) Perfs : 0 - 0 Working Int : 0.89465127 PW 5.000% : 1,581.625 Initial Rate : 2,267.494 bbl/month Revenue Int : 0.64859124 PW 8.000% : 1,412.463 Abandonment : 375.541 bbl/month Disc. Initial Invest. (M$) : 568.098 PW 9.000% : 1,361.981 Initial Decline : 27.01 % year b = 1.000 ROInvestment (disc/undisc) : 3.31 / 3.93 PW 10.000% : 1,314.135 Beg Ratio : 5.124 mcf/bbl Years to Payout : 1.22 PW 12.000% : 1,225.675 End Ratio : 5.246 mcf/bbl Internal ROR (%) : 171.290 PW 15.000% : 1,108.829 LPC Eco DetailedNGL.rpt Page 9 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : GRIZZLY 2H - 2H Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : PHANTOM Archive Set : L19910 Operator : LILIS ENERGY, INC. Reservoir : Cum Oil (Mbbl) : 169.646 Based on SEC Parameters WOLFCAMP B Co., State : Cum Gas (MMcf) : 1,027.279 Constant Prices & Costs WINKLER, TX API : 4249533931 Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 38.632 274.171 25.811 142.879 10.947 52.73 1.37 15.04 1,721.352 2021 28.322 211.315 18.923 110.123 8.437 53.57 1.37 15.04 1,291.429 2022 22.416 173.750 14.976 90.547 6.938 53.57 1.37 15.04 1,030.643 2023 18.553 148.330 12.396 77.299 5.923 53.57 1.37 15.04 858.988 2024 15.869 130.219 10.602 67.861 5.199 53.57 1.37 15.04 739.112 2025 13.798 115.803 9.219 60.349 4.624 53.57 1.37 15.04 646.049 2026 12.234 104.725 8.174 54.576 4.181 53.57 1.37 15.04 575.501 2027 10.988 95.740 7.342 49.893 3.823 53.57 1.37 15.04 519.121 2028 10.000 88.527 6.681 46.134 3.535 53.57 1.37 15.04 474.249 2029 9.128 81.999 6.099 42.732 3.274 53.57 1.37 15.04 434.482 2030 8.417 76.627 5.624 39.933 3.060 53.57 1.37 15.04 401.965 2031 7.809 71.942 5.217 37.491 2.873 53.57 1.37 15.04 374.034 2032 7.302 67.808 4.878 35.337 2.707 53.57 1.37 15.04 350.455 2033 6.821 63.563 4.557 33.124 2.538 53.57 1.37 15.04 327.687 2034 6.410 59.751 4.283 31.138 2.386 53.57 1.37 15.04 307.955 Rem 54.339 506.521 36.305 263.964 20.224 0.00 0.00 0.00 2,610.580 Total 271.037 2,270.791 181.085 1,183.383 90.668 53.45 1.37 15.04 12,663.600 Ult 440.683 3,298.070 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 89.942 43.034 160.875 305.895 428.626 692.980 643.252 643.252 2021 1 67.691 32.286 99.360 231.570 0.000 860.522 747.660 1,390.912 2022 1 54.217 25.766 99.360 187.886 0.000 663.414 523.815 1,914.726 2023 1 45.322 21.475 99.360 158.713 0.000 534.118 383.306 2,298.032 2024 1 39.096 18.478 99.360 138.125 0.000 444.053 289.631 2,587.663 2025 1 34.249 16.151 99.360 121.927 0.000 374.361 221.926 2,809.589 2026 1 30.569 14.388 99.360 109.557 0.000 321.627 173.323 2,982.912 2027 1 27.623 12.978 99.360 99.592 0.000 279.567 136.958 3,119.870 2028 1 25.276 11.856 99.360 91.624 0.000 246.132 109.605 3,229.475 2029 1 23.191 10.862 99.360 84.480 0.000 216.588 87.666 3,317.141 2030 1 21.485 10.049 99.360 78.619 0.000 192.452 70.816 3,387.958 2031 1 20.016 9.351 99.360 73.542 0.000 171.765 57.460 3,445.418 2032 1 18.770 8.761 99.360 69.147 0.000 154.417 46.959 3,492.376 2033 1 17.557 8.192 99.360 64.751 0.000 137.827 38.097 3,530.474 2034 1 16.500 7.699 99.360 60.862 0.000 123.534 31.045 3,561.518 Rem 139.873 65.264 1,248.846 515.937 113.962 526.698 101.167 Total 671.377 316.590 2,800.762 2,392.229 542.588 5,940.053 3,662.685 3,662.685 Major Phase : Oil Abandonment Date : 07/29/2047 Present Worth Profile (M$) Perfs : 0 - 0 Working Int : 0.92276936 PW 5.000% : 4,533.714 Initial Rate : 3,858.470 bbl/month Revenue Int : 0.66811843 PW 8.000% : 3,966.460 Abandonment : 237.993 bbl/month Disc. Initial Invest. (M$) : 436.857 PW 9.000% : 3,808.278 Initial Decline : 34.93 % year b = 1.000 ROInvestment (disc/undisc) : 9.38 / 11.95 PW 10.000% : 3,662.685 Beg Ratio : 6.896 mcf/bbl Years to Payout : 0.45 PW 12.000% : 3,403.930 End Ratio : 9.322 mcf/bbl Internal ROR (%) : >1000 PW 15.000% : 3,081.065 LPC Eco DetailedNGL.rpt Page 10 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : GRIZZLY A 2H 2.0m Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : PHANTOM Archive Set : L19910 Operator : LILIS ENERGY, INC. Reservoir : Cum Oil (Mbbl) : 44.446 Based on SEC Parameters WOLFCAMP B Co., State : Cum Gas (MMcf) : 220.032 Constant Prices & Costs WINKLER, TX API : Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 185.064 1,021.067 122.533 527.328 40.403 52.57 1.37 15.04 7,771.026 2021 78.428 436.718 51.928 225.542 17.281 53.57 1.37 15.04 3,350.623 2022 50.583 282.252 33.492 145.768 11.168 53.57 1.37 15.04 2,161.787 2023 37.414 208.967 24.772 107.920 8.269 53.57 1.37 15.04 1,599.220 2024 29.779 166.419 19.717 85.947 6.585 53.57 1.37 15.04 1,273.015 2025 24.627 137.675 16.306 71.102 5.448 53.57 1.37 15.04 1,052.825 2026 21.043 117.668 13.933 60.769 4.656 53.57 1.37 15.04 899.637 2027 18.371 102.747 12.164 53.063 4.066 53.57 1.37 15.04 785.431 2028 16.344 91.425 10.822 47.216 3.618 53.57 1.37 15.04 698.799 2029 14.648 81.948 9.699 42.322 3.243 53.57 1.37 15.04 626.303 2030 13.303 74.429 8.808 38.439 2.945 53.57 1.37 15.04 568.790 2031 12.184 68.175 8.067 35.209 2.698 53.57 1.37 15.04 520.961 2032 11.269 63.057 7.461 32.566 2.495 53.57 1.37 15.04 481.825 2033 10.428 58.357 6.905 30.138 2.309 53.57 1.37 15.04 445.889 2034 9.728 54.443 6.441 28.117 2.154 53.57 1.37 15.04 415.965 Rem 83.046 464.784 54.986 240.036 18.391 0.00 0.00 0.00 3,550.989 Total 616.259 3,430.130 408.033 1,771.484 135.727 53.27 1.37 15.04 26,203.086 Ult 660.705 3,650.162 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 397.400 194.276 163.666 1,222.526 943.778 4,849.380 4,643.695 4,643.695 2021 1 171.204 83.766 140.204 520.903 0.000 2,434.545 2,119.981 6,763.676 2022 1 110.478 54.045 140.204 336.374 0.000 1,520.686 1,202.095 7,965.772 2023 1 81.734 39.981 140.204 248.938 0.000 1,088.363 781.626 8,747.398 2024 1 65.065 31.825 140.204 198.207 0.000 837.713 546.671 9,294.069 2025 1 53.813 26.321 140.204 163.948 0.000 668.539 396.470 9,690.538 2026 1 45.984 22.491 140.204 140.109 0.000 550.849 296.939 9,987.477 2027 1 40.147 19.636 140.204 122.332 0.000 463.112 226.931 10,214.408 2028 1 35.719 17.470 140.204 108.846 0.000 396.559 176.628 10,391.036 2029 1 32.014 15.658 140.204 97.559 0.000 340.869 137.996 10,529.032 2030 1 29.074 14.220 140.204 88.603 0.000 296.688 109.190 10,638.223 2031 1 26.630 13.024 140.204 81.155 0.000 259.948 86.972 10,725.194 2032 1 24.629 12.046 140.204 75.061 0.000 229.885 69.917 10,795.112 2033 1 22.792 11.147 140.204 69.464 0.000 202.281 55.920 10,851.031 2034 1 21.263 10.399 140.204 64.804 0.000 179.295 45.061 10,896.092 Rem 181.516 88.775 1,789.935 553.227 107.746 829.790 151.736 Total 1,339.463 655.077 3,916.462 4,092.057 1,051.524 15,148.502 11,047.829 11,047.829 Major Phase : Oil Abandonment Date : 10/10/2047 Present Worth Profile (M$) Perfs : 0 - 0 Working Int : 0.87243854 PW 5.000% : 12,653.284 Initial Rate : 31,007.175 bbl/month Revenue Int : 0.66211266 PW 8.000% : 11,615.691 Abandonment : 355.533 bbl/month Disc. Initial Invest. (M$) : 942.383 PW 9.000% : 11,321.240 Initial Decline : 92.53 % year b = 1.000 ROInvestment (disc/undisc) : 12.72 / 15.41 PW 10.000% : 11,047.829 Beg Ratio : 5.493 mcf/bbl Years to Payout : 0.10 PW 12.000% : 10,555.474 End Ratio : 5.597 mcf/bbl Internal ROR (%) : >1000 PW 15.000% : 9,927.520 LPC Eco DetailedNGL.rpt Page 11 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : HALEY 1H Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : PHANTOM Archive Set : L19910 Operator : LILIS ENERGY, INC. Reservoir : Cum Oil (Mbbl) : 79.831 Based on SEC Parameters WOLFCAMP A Co., State : Cum Gas (MMcf) : 72.785 Constant Prices & Costs WINKLER, TX API : Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 43.140 26.363 16.307 7.773 0.596 52.66 1.37 15.04 878.321 2021 24.604 14.364 9.300 4.235 0.324 53.57 1.37 15.04 508.893 2022 17.317 9.944 6.546 2.932 0.225 53.57 1.37 15.04 358.048 2023 13.375 7.614 5.056 2.245 0.172 53.57 1.37 15.04 276.497 2024 10.927 6.187 4.130 1.824 0.140 53.57 1.37 15.04 225.862 2025 9.195 5.188 3.476 1.530 0.117 53.57 1.37 15.04 190.056 2026 7.956 4.477 3.007 1.320 0.101 53.57 1.37 15.04 164.426 2027 7.011 3.937 2.650 1.161 0.089 53.57 1.37 15.04 144.897 2028 6.284 3.523 2.375 1.039 0.080 53.57 1.37 15.04 129.856 2029 5.665 3.172 2.141 0.935 0.072 53.57 1.37 15.04 117.066 2030 5.169 2.891 1.954 0.853 0.065 53.57 1.37 15.04 106.825 2031 4.163 2.326 1.573 0.686 0.053 53.57 1.37 15.04 86.018 Rem 0.000 0.000 0.000 0.000 0.000 0.00 0.00 0.00 0.000 Total 154.806 89.988 58.516 26.531 2.033 53.32 1.37 15.04 3,186.763 Ult 234.637 162.773 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 41.109 21.958 107.817 78.085 75.000 554.351 531.791 531.791 2021 1 23.797 12.722 80.352 44.265 0.000 347.756 302.672 834.463 2022 1 16.740 8.951 80.352 31.089 0.000 220.917 174.649 1,009.112 2023 1 12.926 6.912 80.352 23.985 0.000 152.321 109.430 1,118.542 2024 1 10.558 5.647 80.352 19.582 0.000 109.724 71.644 1,190.186 2025 1 8.884 4.751 80.352 16.471 0.000 79.598 47.236 1,237.423 2026 1 7.685 4.111 80.352 14.246 0.000 58.032 31.309 1,268.732 2027 1 6.772 3.622 80.352 12.551 0.000 41.599 20.406 1,289.138 2028 1 6.069 3.246 80.352 11.246 0.000 28.942 12.913 1,302.051 2029 1 5.471 2.927 80.352 10.137 0.000 18.178 7.375 1,309.426 2030 1 4.993 2.671 80.352 9.249 0.000 9.560 3.532 1,312.957 2031 1 4.020 2.150 69.215 7.447 61.750 -58.565 -18.840 1,294.117 Rem 0.000 0.000 0.000 0.000 0.000 0.000 0.000 Total 149.026 79.669 980.552 278.354 136.750 1,562.413 1,294.117 1,294.117 Major Phase : Oil Abandonment Date : 11/14/2031 Present Worth Profile (M$) Perfs : 0 - 0 Working Int : 0.50000000 PW 5.000% : 1,414.841 Initial Rate : 5,271.014 bbl/month Revenue Int : 0.37799284 PW 8.000% : 1,339.567 Abandonment : 384.726 bbl/month Disc. Initial Invest. (M$) : 91.445 PW 9.000% : 1,316.399 Initial Decline : 65.88 % year b = 1.000 ROInvestment (disc/undisc) : 15.15 / 12.43 PW 10.000% : 1,294.117 Beg Ratio : 0.638 mcf/bbl Years to Payout : 0.17 PW 12.000% : 1,252.049 End Ratio : 0.559 mcf/bbl Internal ROR (%) : >1000 PW 15.000% : 1,194.612 LPC Eco DetailedNGL.rpt Page 12 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : HALEY 2H Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : PHANTOM Archive Set : L19910 Operator : LILIS ENERGY, INC. Reservoir : Cum Oil (Mbbl) : 43.443 Based on SEC Parameters WOLFCAMP A Co., State : Cum Gas (MMcf) : 58.253 Constant Prices & Costs WINKLER, TX API : Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 22.546 29.712 8.522 8.760 0.671 52.66 1.37 15.04 470.887 2021 12.881 17.381 4.869 5.125 0.393 53.57 1.37 15.04 273.756 2022 9.072 12.353 3.429 3.642 0.279 53.57 1.37 15.04 192.886 2023 7.009 9.591 2.650 2.828 0.217 53.57 1.37 15.04 149.066 2024 5.728 7.862 2.165 2.318 0.178 53.57 1.37 15.04 121.826 2025 4.191 5.763 1.584 1.699 0.130 53.57 1.37 15.04 89.139 Rem 0.000 0.000 0.000 0.000 0.000 0.00 0.00 0.00 0.000 Total 61.427 82.662 23.219 24.372 1.867 53.24 1.37 15.04 1,297.560 Ult 104.870 140.915 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 22.377 11.772 107.817 47.198 75.000 206.722 198.487 198.487 2021 1 13.011 6.844 80.352 27.128 0.000 146.421 127.561 326.047 2022 1 9.170 4.822 80.352 19.151 0.000 79.391 62.848 388.895 2023 1 7.087 3.727 80.352 14.816 0.000 43.084 31.017 419.913 2024 1 5.793 3.046 80.352 12.116 61.750 -41.231 -24.889 395.024 2025 1 4.239 2.228 68.335 8.869 0.000 5.468 3.299 398.323 Rem 0.000 0.000 0.000 0.000 0.000 0.000 0.000 Total 61.676 32.439 497.560 129.279 136.750 439.856 398.323 398.323 Major Phase : Oil Abandonment Date : 11/10/2025 Present Worth Profile (M$) Perfs : 0 - 0 Working Int : 0.50000000 PW 5.000% : 418.081 Initial Rate : 2,750.417 bbl/month Revenue Int : 0.37799284 PW 8.000% : 405.994 Abandonment : 379.960 bbl/month Disc. Initial Invest. (M$) : 109.866 PW 9.000% : 402.121 Initial Decline : 65.68 % year b = 1.000 ROInvestment (disc/undisc) : 4.63 / 4.22 PW 10.000% : 398.323 Beg Ratio : 1.290 mcf/bbl Years to Payout : 0.41 PW 12.000% : 390.949 End Ratio : 1.376 mcf/bbl Internal ROR (%) : >1000 PW 15.000% : 380.419 LPC Eco DetailedNGL.rpt Page 13 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : HIPPO 1H - 1H Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : PHANTOM Archive Set : L19910 Operator : LILIS ENERGY, INC. Reservoir : Cum Oil (Mbbl) : 171.486 Based on SEC Parameters WOLFCAMP B Co., State : Cum Gas (MMcf) : 675.815 Constant Prices & Costs WINKLER, TX API : 4249532042 Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 26.375 87.360 19.377 50.062 3.836 52.74 1.37 15.04 1,148.240 2021 20.239 66.304 14.869 37.996 2.911 53.57 1.37 15.04 892.383 2022 16.459 53.560 12.093 30.693 2.352 53.57 1.37 15.04 725.204 2023 13.872 44.935 10.192 25.750 1.973 53.57 1.37 15.04 610.911 2024 12.020 38.806 8.831 22.238 1.704 53.57 1.37 15.04 529.151 2025 10.553 33.986 7.753 19.476 1.492 53.57 1.37 15.04 464.472 2026 9.428 30.303 6.927 17.365 1.330 53.57 1.37 15.04 414.854 2027 8.520 27.340 6.259 15.667 1.200 53.57 1.37 15.04 374.825 2028 7.792 24.971 5.724 14.310 1.096 53.57 1.37 15.04 342.745 2029 7.142 22.865 5.247 13.103 1.004 53.57 1.37 15.04 314.141 2030 6.609 21.138 4.855 12.113 0.928 53.57 1.37 15.04 290.652 2031 6.150 19.653 4.518 11.262 0.863 53.57 1.37 15.04 270.434 2032 5.765 18.413 4.236 10.551 0.808 53.57 1.37 15.04 253.518 2033 5.397 17.228 3.965 9.873 0.756 53.57 1.37 15.04 237.316 2034 5.073 16.195 3.727 9.280 0.711 53.57 1.37 15.04 223.083 Rem 5.563 17.757 4.087 10.176 0.780 0.00 0.00 0.00 244.608 Total 166.958 540.813 122.661 309.915 23.745 53.44 1.37 15.04 7,336.538 Ult 338.444 1,216.628 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 56.673 28.706 215.634 150.637 150.000 546.590 521.719 521.719 2021 1 43.976 22.310 160.704 115.023 0.000 550.370 478.201 999.920 2022 1 35.724 18.130 160.704 93.260 0.000 417.386 329.603 1,329.523 2023 1 30.086 15.273 160.704 78.440 0.000 326.408 234.292 1,563.815 2024 1 26.055 13.229 160.704 67.866 0.000 261.297 170.481 1,734.296 2025 1 22.867 11.612 160.704 59.520 0.000 209.770 124.392 1,858.688 2026 1 20.422 10.371 160.704 53.126 0.000 170.231 91.769 1,950.457 2027 1 18.450 9.371 160.704 47.974 0.000 138.327 67.793 2,018.250 2028 1 16.869 8.569 160.704 43.849 0.000 112.754 50.239 2,068.489 2029 1 15.461 7.854 160.704 40.175 0.000 89.948 36.427 2,104.917 2030 1 14.304 7.266 160.704 37.159 0.000 71.219 26.223 2,131.140 2031 1 13.308 6.761 160.704 34.565 0.000 55.095 18.445 2,149.585 2032 1 12.475 6.338 160.704 32.395 0.000 41.605 12.668 2,162.253 2033 1 11.678 5.933 160.704 30.320 0.000 28.681 7.939 2,170.192 2034 1 10.977 5.577 160.704 28.501 0.000 17.323 4.364 2,174.556 Rem 12.037 6.115 188.152 31.251 123.500 -116.446 -24.829 Total 361.361 183.413 2,653.642 944.063 273.500 2,920.560 2,149.726 2,149.726 Major Phase : Oil Abandonment Date : 03/03/2036 Present Worth Profile (M$) Perfs : 12310 - 16415 Working Int : 1.00000000 PW 5.000% : 2,480.149 Initial Rate : 2,553.245 bbl/month Revenue Int : 0.73468481 PW 8.000% : 2,270.995 Abandonment : 381.449 bbl/month Disc. Initial Invest. (M$) : 169.489 PW 9.000% : 2,208.708 Initial Decline : 29.32 % year b = 1.000 ROInvestment (disc/undisc) : 13.68 / 11.68 PW 10.000% : 2,149.726 Beg Ratio : 3.337 mcf/bbl Years to Payout : 0.39 PW 12.000% : 2,040.807 End Ratio : 3.192 mcf/bbl Internal ROR (%) : >1000 PW 15.000% : 1,897.171 LPC Eco DetailedNGL.rpt Page 14 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : HIPPO 2H - 2H Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : PHANTOM Archive Set : L19910 Operator : LILIS ENERGY, INC. Reservoir : Cum Oil (Mbbl) : 173.473 Based on SEC Parameters WOLFCAMP B Co., State : Cum Gas (MMcf) : 889.418 Constant Prices & Costs WINKLER, TX API : 42495339970000 Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 31.054 186.395 19.540 91.483 7.009 52.71 1.37 15.04 1,260.724 2021 21.237 131.227 13.363 64.406 4.935 53.57 1.37 15.04 878.280 2022 16.187 101.555 10.186 49.843 3.819 53.57 1.37 15.04 671.352 2023 13.084 82.861 8.233 40.668 3.116 53.57 1.37 15.04 543.619 2024 11.010 70.171 6.928 34.440 2.639 53.57 1.37 15.04 457.986 2025 9.460 60.569 5.952 29.727 2.278 53.57 1.37 15.04 393.837 2026 8.311 53.402 5.230 26.210 2.008 53.57 1.37 15.04 346.253 2027 7.412 47.754 4.664 23.438 1.796 53.57 1.37 15.04 308.942 2028 6.706 43.300 4.219 21.252 1.628 53.57 1.37 15.04 279.627 2029 6.092 39.409 3.833 19.342 1.482 53.57 1.37 15.04 254.126 2030 5.595 36.248 3.520 17.790 1.363 53.57 1.37 15.04 233.450 2031 5.172 33.556 3.255 16.469 1.262 53.57 1.37 15.04 215.889 2032 4.822 31.320 3.034 15.372 1.178 53.57 1.37 15.04 201.319 2033 4.494 29.213 2.827 14.338 1.099 53.57 1.37 15.04 187.628 2034 4.217 27.431 2.653 13.463 1.032 53.57 1.37 15.04 176.089 Rem 18.845 122.600 11.858 60.173 4.610 0.00 0.00 0.00 787.000 Total 173.697 1,097.008 109.296 538.414 41.252 53.42 1.37 15.04 7,196.122 Ult 347.170 1,986.426 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 64.907 31.518 148.892 207.428 0.000 807.979 772.784 772.784 2021 1 45.265 21.957 91.959 144.361 0.000 574.738 499.628 1,272.412 2022 1 34.645 16.784 91.959 111.058 0.000 416.906 329.310 1,601.722 2023 1 28.076 13.590 91.959 90.285 0.000 319.707 229.512 1,831.234 2024 1 23.667 11.450 91.959 76.270 0.000 254.641 166.140 1,997.374 2025 1 20.360 9.846 91.959 65.716 0.000 205.957 122.128 2,119.502 2026 1 17.905 8.656 91.959 57.862 0.000 169.870 91.567 2,211.069 2027 1 15.980 7.724 91.959 51.687 0.000 141.592 69.384 2,280.453 2028 1 14.466 6.991 91.959 46.827 0.000 119.384 53.180 2,333.633 2029 1 13.149 6.353 91.959 42.590 0.000 100.075 40.518 2,374.151 2030 1 12.081 5.836 91.959 39.150 0.000 84.424 31.075 2,405.226 2031 1 11.173 5.397 91.959 36.225 0.000 71.134 23.804 2,429.030 2032 1 10.420 5.033 91.959 33.796 0.000 60.110 18.288 2,447.318 2033 1 9.713 4.691 91.959 31.511 0.000 49.755 13.758 2,461.076 2034 1 9.116 4.402 91.959 29.581 0.000 41.030 10.315 2,471.391 Rem 40.741 19.675 498.396 132.211 105.474 -9.497 4.448 Total 371.666 179.903 1,934.717 1,196.558 105.474 3,407.804 2,475.839 2,475.839 Major Phase : Oil Abandonment Date : 06/03/2040 Present Worth Profile (M$) Perfs : 0 - 0 Working Int : 0.85403656 PW 5.000% : 2,863.384 Initial Rate : 3,262.722 bbl/month Revenue Int : 0.62923359 PW 8.000% : 2,616.040 Abandonment : 243.681 bbl/month Disc. Initial Invest. (M$) : 15.060 PW 9.000% : 2,543.742 Initial Decline : 43.61 % year b = 1.000 ROInvestment (disc/undisc) : 165.39 / 33.31 PW 10.000% : 2,475.839 Beg Ratio : 5.874 mcf/bbl Years to Payout : 0.11 PW 12.000% : 2,351.838 End Ratio : 6.506 mcf/bbl Internal ROR (%) : >1000 PW 15.000% : 2,190.932 LPC Eco DetailedNGL.rpt Page 15 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : HOWELL 1H - 1H Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : PHANTOM Archive Set : L19910 Operator : LILIS ENERGY, INC. Reservoir : Cum Oil (Mbbl) : 47.601 Based on SEC Parameters WOLFCAMP XY Co., State : Cum Gas (MMcf) : 799.739 Constant Prices & Costs WINKLER, TX API : 4249533964 Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 20.120 328.011 15.090 191.886 14.702 52.72 1.37 15.04 1,279.446 2021 14.005 320.258 10.504 187.351 14.354 53.57 1.37 15.04 1,035.190 2022 10.773 245.359 8.080 143.535 10.997 53.57 1.37 15.04 794.840 2023 8.757 198.946 6.568 116.383 8.917 53.57 1.37 15.04 645.364 2024 7.397 167.759 5.548 98.139 7.519 53.57 1.37 15.04 544.702 2025 6.373 144.355 4.780 84.448 6.470 53.57 1.37 15.04 469.026 2026 5.611 126.975 4.208 74.280 5.691 53.57 1.37 15.04 412.767 2027 5.012 113.335 3.759 66.301 5.080 53.57 1.37 15.04 368.575 2028 4.540 102.612 3.405 60.028 4.599 53.57 1.37 15.04 333.811 2029 4.129 93.277 3.097 54.567 4.181 53.57 1.37 15.04 303.523 2030 3.796 85.706 2.847 50.138 3.841 53.57 1.37 15.04 278.948 2031 3.512 79.272 2.634 46.374 3.553 53.57 1.37 15.04 258.058 2032 3.276 73.933 2.457 43.251 3.314 53.57 1.37 15.04 240.717 2033 1.136 25.635 0.852 14.996 1.149 53.57 1.37 15.04 83.471 Rem 0.000 0.000 0.000 0.000 0.000 0.00 0.00 0.00 0.000 Total 98.437 2,105.434 73.828 1,231.679 94.369 53.40 1.37 15.04 7,048.438 Ult 146.038 2,905.173 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 73.146 31.986 174.339 487.947 0.000 512.028 489.353 489.353 2021 1 61.538 25.880 107.676 458.762 0.000 381.334 331.556 820.909 2022 1 47.227 19.871 107.676 351.607 0.000 268.459 212.102 1,033.011 2023 1 38.334 16.134 107.676 285.164 0.000 198.056 142.221 1,175.232 2024 1 32.348 13.618 107.676 240.501 0.000 150.559 98.269 1,273.501 2025 1 27.850 11.726 107.676 206.973 0.000 114.801 68.102 1,341.603 2026 1 24.506 10.319 107.676 182.071 0.000 88.195 47.564 1,389.166 2027 1 21.881 9.214 107.676 162.524 0.000 67.280 32.988 1,422.155 2028 1 19.815 8.345 107.676 147.155 0.000 50.818 22.657 1,444.811 2029 1 18.016 7.588 107.676 133.774 0.000 36.468 14.780 1,459.591 2030 1 16.557 6.974 107.676 122.921 0.000 24.821 9.149 1,468.740 2031 1 15.316 6.451 107.676 113.698 0.000 14.917 5.003 1,473.743 2032 1 14.287 6.018 107.676 106.043 0.000 6.693 2.049 1,475.792 2033 1 4.954 2.087 38.807 36.769 123.500 -122.645 -34.311 1,441.481 Rem 0.000 0.000 0.000 0.000 0.000 0.000 0.000 Total 415.774 176.211 1,505.258 3,035.909 123.500 1,791.785 1,441.481 1,441.481 Major Phase : Oil Abandonment Date : 05/13/2033 Present Worth Profile (M$) Perfs : 0 - 0 Working Int : 1.00000000 PW 5.000% : 1,599.893 Initial Rate : 2,086.168 bbl/month Revenue Int : 0.75000000 PW 8.000% : 1,501.120 Abandonment : 256.909 bbl/month Disc. Initial Invest. (M$) : 34.556 PW 9.000% : 1,470.709 Initial Decline : 41.40 % year b = 1.000 ROInvestment (disc/undisc) : 42.71 / 15.51 PW 10.000% : 1,441.481 Beg Ratio : 0.000 mcf/bbl Years to Payout : 0.21 PW 12.000% : 1,386.384 End Ratio : 22.561 mcf/bbl Internal ROR (%) : >1000 PW 15.000% : 1,311.450 LPC Eco DetailedNGL.rpt Page 16 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : KUDU A 1H - 1H Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : PHANTOM Archive Set : L19910 Operator : LILIS ENERGY, INC. Reservoir : Cum Oil (Mbbl) : 261.042 Based on SEC Parameters WOLFCAMP B Co., State : Cum Gas (MMcf) : 1,090.404 Constant Prices & Costs WINKLER, TX API : 4249533917 Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 26.053 163.002 15.175 74.053 5.674 52.73 1.37 15.04 986.930 2021 19.078 124.922 11.112 56.753 4.348 53.57 1.37 15.04 738.400 2022 15.089 101.511 8.788 46.117 3.533 53.57 1.37 15.04 587.108 2023 12.483 85.508 7.271 38.847 2.976 53.57 1.37 15.04 487.474 2024 10.674 74.061 6.217 33.647 2.578 53.57 1.37 15.04 417.901 2025 9.279 65.006 5.404 29.533 2.263 53.57 1.37 15.04 363.999 2026 8.225 58.060 4.791 26.377 2.021 53.57 1.37 15.04 323.172 2027 7.387 52.457 4.303 23.832 1.826 53.57 1.37 15.04 290.594 2028 6.722 47.966 3.915 21.791 1.670 53.57 1.37 15.04 264.683 2029 6.135 43.930 3.573 19.958 1.529 53.57 1.37 15.04 241.764 2030 5.657 40.417 3.295 18.362 1.407 53.57 1.37 15.04 222.810 2031 5.248 37.186 3.056 16.894 1.294 53.57 1.37 15.04 206.339 2032 4.907 34.303 2.858 15.584 1.194 53.57 1.37 15.04 192.397 2033 4.584 31.471 2.670 14.297 1.095 53.57 1.37 15.04 179.075 2034 4.307 28.955 2.509 13.154 1.008 53.57 1.37 15.04 167.565 Rem 1.235 8.189 0.720 3.720 0.285 0.00 0.00 0.00 47.931 Total 147.063 996.944 85.656 452.920 34.702 53.42 1.37 15.04 5,718.140 Ult 408.105 2,087.348 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 50.990 24.673 142.957 161.866 0.000 606.443 579.555 579.555 2021 1 38.247 18.460 120.514 121.964 0.000 439.214 381.728 961.283 2022 1 30.484 14.678 120.514 98.137 0.000 323.296 255.352 1,216.635 2023 1 25.351 12.187 120.514 82.133 0.000 247.289 177.529 1,394.164 2024 1 21.758 10.448 120.514 70.813 0.000 194.368 126.830 1,520.994 2025 1 18.969 9.100 120.514 61.944 0.000 153.472 91.019 1,612.013 2026 1 16.853 8.079 120.514 55.180 0.000 122.546 66.071 1,678.084 2027 1 15.162 7.265 120.514 49.750 0.000 97.903 47.987 1,726.072 2028 1 13.816 6.617 120.514 45.413 0.000 78.322 34.903 1,760.975 2029 1 12.624 6.044 120.514 41.543 0.000 61.039 24.724 1,785.698 2030 1 11.632 5.570 120.514 38.250 0.000 46.844 17.252 1,802.951 2031 1 10.764 5.158 120.514 35.293 0.000 34.610 11.591 1,814.541 2032 1 10.024 4.810 120.514 32.711 0.000 24.337 7.415 1,821.957 2033 1 9.315 4.477 120.514 30.203 0.000 14.566 4.036 1,825.992 2034 1 8.700 4.189 120.514 28.000 0.000 6.163 1.557 1,827.549 Rem 2.485 1.198 35.593 7.960 92.614 -91.920 -21.389 Total 297.174 142.954 1,865.744 961.160 92.614 2,358.494 1,806.160 1,806.160 Major Phase : Oil Abandonment Date : 04/19/2035 Present Worth Profile (M$) Perfs : 0 - 0 Working Int : 0.74991180 PW 5.000% : 2,045.626 Initial Rate : 2,604.342 bbl/month Revenue Int : 0.58244672 PW 8.000% : 1,894.572 Abandonment : 341.812 bbl/month Disc. Initial Invest. (M$) : 21.554 PW 9.000% : 1,849.241 Initial Decline : 35.08 % year b = 1.000 ROInvestment (disc/undisc) : 84.80 / 26.47 PW 10.000% : 1,806.160 Beg Ratio : 6.064 mcf/bbl Years to Payout : 0.14 PW 12.000% : 1,726.191 End Ratio : 6.607 mcf/bbl Internal ROR (%) : >1000 PW 15.000% : 1,619.866 LPC Eco DetailedNGL.rpt Page 17 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : KUDU A 2H (Was Kudu 3H) Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : PHANTOM Archive Set : L19910 Operator : LILIS ENERGY, INC. Reservoir : Cum Oil (Mbbl) : 31.107 Based on SEC Parameters WOLFCAMP B Co., State : Cum Gas (MMcf) : 49.103 Constant Prices & Costs WINKLER, TX API : Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 133.724 225.439 83.271 109.498 8.389 52.56 1.37 15.04 4,653.126 2021 56.179 106.494 34.983 51.725 3.963 53.57 1.37 15.04 2,004.491 2022 36.163 70.551 22.519 34.267 2.625 53.57 1.37 15.04 1,292.774 2023 26.724 52.846 16.641 25.668 1.967 53.57 1.37 15.04 956.216 2024 21.260 42.375 13.239 20.582 1.577 53.57 1.37 15.04 761.115 2025 17.576 35.214 10.945 17.104 1.310 53.57 1.37 15.04 629.440 2026 15.014 30.193 9.350 14.665 1.124 53.57 1.37 15.04 537.841 2027 13.106 26.427 8.161 12.836 0.983 53.57 1.37 15.04 469.555 2028 11.658 23.559 7.260 11.443 0.877 53.57 1.37 15.04 417.757 2029 10.447 21.148 6.506 10.272 0.787 53.57 1.37 15.04 374.413 2030 9.487 19.231 5.908 9.341 0.716 53.57 1.37 15.04 340.028 2031 8.689 17.632 5.410 8.564 0.656 53.57 1.37 15.04 311.433 2032 8.035 16.323 5.004 7.928 0.607 53.57 1.37 15.04 288.036 2033 7.435 15.117 4.630 7.342 0.563 53.57 1.37 15.04 266.552 2034 6.936 14.112 4.319 6.854 0.525 53.57 1.37 15.04 248.663 Rem 36.289 73.886 22.597 35.887 2.750 0.00 0.00 0.00 1,301.056 Total 418.725 790.546 260.742 383.975 29.419 53.25 1.37 15.04 14,852.496 Ult 449.832 839.649 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 222.806 116.328 152.808 489.856 40.728 3,630.601 3,497.990 3,497.990 2021 1 96.310 50.112 130.903 213.578 0.000 1,513.588 1,318.194 4,816.184 2022 1 62.181 32.319 130.903 138.804 0.000 928.567 734.123 5,550.307 2023 1 46.016 23.905 130.903 103.044 0.000 652.348 468.558 6,018.866 2024 1 36.639 19.028 130.903 82.196 0.000 492.350 321.344 6,340.210 2025 1 30.306 15.736 130.903 68.072 0.000 384.423 228.012 6,568.222 2026 1 25.899 13.446 130.903 58.225 0.000 309.368 166.793 6,735.015 2027 1 22.614 11.739 130.903 50.871 0.000 253.429 124.204 6,859.219 2028 1 20.121 10.444 130.903 45.285 0.000 211.004 94.001 6,953.220 2029 1 18.034 9.360 130.903 40.606 0.000 175.510 71.067 7,024.287 2030 1 16.379 8.501 130.903 36.891 0.000 147.355 54.243 7,078.530 2031 1 15.002 7.786 130.903 33.799 0.000 123.943 41.478 7,120.008 2032 1 13.876 7.201 130.903 31.268 0.000 104.788 31.881 7,151.889 2033 1 12.841 6.664 130.903 28.943 0.000 87.201 24.114 7,176.002 2034 1 11.980 6.217 130.903 27.006 0.000 72.558 18.241 7,194.243 Rem 62.682 32.526 861.644 141.328 100.598 102.277 27.157 Total 713.686 371.312 2,847.088 1,589.772 141.326 9,189.312 7,221.400 7,221.400 Major Phase : Oil Abandonment Date : 08/03/2041 Present Worth Profile (M$) Perfs : 0 - 0 Working Int : 0.81455719 PW 5.000% : 8,037.038 Initial Rate : 22,812.500 bbl/month Revenue Int : 0.62270403 PW 8.000% : 7,516.900 Abandonment : 371.654 bbl/month Disc. Initial Invest. (M$) : 50.771 PW 9.000% : 7,364.637 Initial Decline : 93.00 % year b = 1.000 ROInvestment (disc/undisc) : 143.24 / 66.02 PW 10.000% : 7,221.400 Beg Ratio : 1.467 mcf/bbl Years to Payout : 0.02 PW 12.000% : 6,958.985 End Ratio : 2.036 mcf/bbl Internal ROR (%) : >1000 PW 15.000% : 6,616.114 LPC Eco DetailedNGL.rpt Page 18 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : KUDU B 1H - 1H Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : PHANTOM (WOLFCAMP) Archive Set : L19910 Operator : IMPETRO OPERATING LLC Reservoir : Cum Oil (Mbbl) : 106.551 Based on SEC Parameters WOLFCAMP A Co., State : Cum Gas (MMcf) : 679.075 Constant Prices & Costs Winkler, TX API : 4249531705 Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 8.179 128.042 5.041 61.552 4.716 52.76 1.37 15.04 421.166 2021 6.717 100.468 4.140 48.297 3.700 53.57 1.37 15.04 343.577 2022 5.712 82.861 3.520 39.833 3.052 53.57 1.37 15.04 289.042 2023 4.969 70.516 3.062 33.899 2.597 53.57 1.37 15.04 249.543 2024 4.408 61.537 2.717 29.582 2.267 53.57 1.37 15.04 220.155 2025 3.942 54.324 2.430 26.115 2.001 53.57 1.37 15.04 196.023 2026 0.205 2.804 0.126 1.348 0.103 53.57 1.37 15.04 10.159 Rem 0.000 0.000 0.000 0.000 0.000 0.00 0.00 0.00 0.000 Total 34.132 500.552 21.036 240.626 18.436 53.38 1.37 15.04 1,729.665 Ult 140.683 1,179.627 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 23.960 10.529 151.198 104.015 0.000 131.464 125.210 125.210 2021 1 19.404 8.589 127.461 82.359 0.000 105.763 91.954 217.163 2022 1 16.266 7.226 127.461 68.353 0.000 69.736 55.130 272.293 2023 1 14.007 6.239 127.461 58.438 0.000 43.399 31.207 303.500 2024 1 12.334 5.504 127.461 51.176 0.000 23.681 15.507 319.007 2025 1 10.965 4.901 127.461 45.303 0.000 7.393 4.428 323.435 2026 1 0.568 0.254 6.853 2.342 97.953 -97.810 -54.931 268.504 Rem 0.000 0.000 0.000 0.000 0.000 0.000 0.000 Total 97.503 43.242 795.356 411.984 97.953 283.626 268.504 268.504 Major Phase : Oil Abandonment Date : 01/20/2026 Present Worth Profile (M$) Perfs : 0 - 0 Working Int : 0.79314179 PW 5.000% : 277.089 Initial Rate : 757.870 bbl/month Revenue Int : 0.61630850 PW 8.000% : 272.096 Abandonment : 310.723 bbl/month Disc. Initial Invest. (M$) : 55.011 PW 9.000% : 270.321 Initial Decline : 21.18 % year b = 1.000 ROInvestment (disc/undisc) : 5.88 / 3.90 PW 10.000% : 268.504 Beg Ratio : 16.117 mcf/bbl Years to Payout : 0.76 PW 12.000% : 264.774 End Ratio : 13.694 mcf/bbl Internal ROR (%) : >1000 PW 15.000% : 259.024 LPC Eco DetailedNGL.rpt Page 19 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : KUDU B 2H (Was Kudu 4H) Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : PHANTOM Archive Set : L19910 Operator : LILIS ENERGY, INC. Reservoir : Cum Oil (Mbbl) : 19.144 Based on SEC Parameters WOLFCAMP B Co., State : Cum Gas (MMcf) : 29.934 Constant Prices & Costs WINKLER, TX API : Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 74.455 85.526 45.461 40.732 3.121 52.58 1.37 15.04 2,492.852 2021 32.476 52.595 19.829 25.048 1.919 53.57 1.37 15.04 1,125.416 2022 21.085 38.152 12.874 18.170 1.392 53.57 1.37 15.04 735.479 2023 15.643 29.957 9.551 14.267 1.093 53.57 1.37 15.04 547.647 2024 12.473 24.731 7.616 11.778 0.902 53.57 1.37 15.04 437.689 2025 10.327 20.963 6.306 9.983 0.765 53.57 1.37 15.04 362.968 2026 8.831 18.233 5.392 8.683 0.665 53.57 1.37 15.04 310.765 2027 7.715 16.133 4.710 7.683 0.589 53.57 1.37 15.04 271.719 2028 6.867 14.505 4.193 6.908 0.529 53.57 1.37 15.04 242.031 2029 6.157 13.110 3.759 6.244 0.478 53.57 1.37 15.04 217.127 2030 5.593 11.989 3.415 5.710 0.437 53.57 1.37 15.04 197.341 2031 5.124 11.045 3.129 5.260 0.403 53.57 1.37 15.04 180.864 2032 4.740 10.266 2.894 4.889 0.375 53.57 1.37 15.04 167.370 2033 0.903 1.961 0.551 0.934 0.072 53.57 1.37 15.04 31.891 Rem 0.000 0.000 0.000 0.000 0.000 0.00 0.00 0.00 0.000 Total 212.390 349.166 129.680 166.290 12.741 53.22 1.37 15.04 7,321.157 Ult 231.534 379.100 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 118.048 62.321 150.882 242.832 40.215 1,878.553 1,809.880 1,809.880 2021 1 53.780 28.135 129.253 115.822 0.000 798.426 695.470 2,505.350 2022 1 35.278 18.387 129.253 77.791 0.000 474.769 375.452 2,880.802 2023 1 26.323 13.691 129.253 58.784 0.000 319.596 229.630 3,110.432 2024 1 21.065 10.942 129.253 47.419 0.000 229.009 149.531 3,259.963 2025 1 17.485 9.074 129.253 39.576 0.000 167.580 99.442 3,359.405 2026 1 14.980 7.769 129.253 34.042 0.000 124.720 67.279 3,426.684 2027 1 13.105 6.793 129.253 29.871 0.000 92.697 45.461 3,472.145 2028 1 11.678 6.051 129.253 26.682 0.000 68.367 30.487 3,502.632 2029 1 10.479 5.428 129.253 23.991 0.000 47.975 19.448 3,522.080 2030 1 9.527 4.934 129.253 21.846 0.000 31.781 11.718 3,533.798 2031 1 8.734 4.522 129.253 20.053 0.000 18.302 6.141 3,539.939 2032 1 8.084 4.184 129.253 18.582 0.000 7.267 2.229 3,542.168 2033 1 1.540 0.797 25.544 3.543 99.330 -98.864 -28.098 3,514.071 Rem 0.000 0.000 0.000 0.000 0.000 0.000 0.000 Total 350.106 183.029 1,727.466 760.833 139.545 4,160.178 3,514.071 3,514.071 Major Phase : Oil Abandonment Date : 03/14/2033 Present Worth Profile (M$) Perfs : 0 - 0 Working Int : 0.80429422 PW 5.000% : 3,802.257 Initial Rate : 12,046.892 bbl/month Revenue Int : 0.61057701 PW 8.000% : 3,622.141 Abandonment : 373.739 bbl/month Disc. Initial Invest. (M$) : 65.671 PW 9.000% : 3,566.991 Initial Decline : 90.82 % year b = 1.000 ROInvestment (disc/undisc) : 54.51 / 30.81 PW 10.000% : 3,514.071 Beg Ratio : 0.812 mcf/bbl Years to Payout : 0.04 PW 12.000% : 3,414.446 End Ratio : 2.172 mcf/bbl Internal ROR (%) : >1000 PW 15.000% : 3,278.961 LPC Eco DetailedNGL.rpt Page 20 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : LION 1H - 1H Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : PHANTOM Archive Set : L19910 Operator : LILIS ENERGY, INC. Reservoir : Cum Oil (Mbbl) : 160.506 Based on SEC Parameters WOLFCAMP B Co., State : Cum Gas (MMcf) : 1,107.513 Constant Prices & Costs WINKLER, TX API : 4249531858 Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 20.859 216.187 14.609 118.100 9.049 52.74 1.37 15.04 1,068.303 2021 15.850 164.138 11.101 89.666 6.870 53.57 1.37 15.04 820.819 2022 12.813 133.225 8.974 72.779 5.576 53.57 1.37 15.04 664.270 2023 10.755 112.467 7.532 61.439 4.707 53.57 1.37 15.04 558.455 2024 9.291 97.768 6.507 53.409 4.092 53.57 1.37 15.04 483.293 2025 8.139 86.188 5.701 47.083 3.607 53.57 1.37 15.04 424.126 2026 7.259 77.334 5.084 42.246 3.237 53.57 1.37 15.04 378.883 2027 6.550 70.197 4.588 38.348 2.938 53.57 1.37 15.04 342.467 2028 5.983 64.486 4.191 35.228 2.699 53.57 1.37 15.04 313.335 2029 5.479 59.372 3.838 32.434 2.485 53.57 1.37 15.04 287.378 2030 5.066 55.175 3.548 30.141 2.309 53.57 1.37 15.04 266.085 2031 4.711 51.556 3.299 28.164 2.158 53.57 1.37 15.04 247.766 2032 4.414 48.518 3.091 26.505 2.031 53.57 1.37 15.04 232.437 2033 3.524 38.805 2.468 21.199 1.624 53.57 1.37 15.04 185.674 Rem 0.000 0.000 0.000 0.000 0.000 0.00 0.00 0.00 0.000 Total 120.693 1,275.416 84.529 696.739 53.383 53.43 1.37 15.04 6,273.290 Ult 281.199 2,382.929 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 57.981 26.708 176.513 222.046 141.138 443.917 427.779 427.779 2021 1 44.469 20.520 151.210 168.626 0.000 435.994 378.882 806.661 2022 1 36.003 16.607 151.210 136.714 0.000 323.736 255.687 1,062.347 2023 1 30.287 13.961 151.210 115.230 0.000 247.767 177.871 1,240.218 2024 1 26.228 12.082 151.210 100.000 0.000 193.773 126.448 1,366.666 2025 1 23.033 10.603 151.210 88.004 0.000 151.276 89.722 1,456.389 2026 1 20.589 9.472 151.210 78.832 0.000 118.779 64.046 1,520.435 2027 1 18.622 8.562 151.210 71.443 0.000 92.630 45.409 1,565.844 2028 1 17.049 7.833 151.210 65.531 0.000 71.712 31.965 1,597.809 2029 1 15.645 7.184 151.210 60.248 0.000 53.091 21.511 1,619.320 2030 1 14.494 6.652 151.210 55.911 0.000 37.817 13.934 1,633.253 2031 1 13.504 6.194 151.210 52.176 0.000 24.683 8.272 1,641.526 2032 1 12.674 5.811 151.210 49.045 0.000 13.697 4.183 1,645.708 2033 1 10.126 4.642 126.940 39.208 116.204 -111.446 -29.710 1,615.998 Rem 0.000 0.000 0.000 0.000 0.000 0.000 0.000 Total 340.705 156.832 2,117.970 1,303.016 257.342 2,097.425 1,615.998 1,615.998 Major Phase : Oil Abandonment Date : 11/06/2033 Present Worth Profile (M$) Perfs : 0 - 0 Working Int : 0.94092107 PW 5.000% : 1,828.030 Initial Rate : 2,032.579 bbl/month Revenue Int : 0.70036395 PW 8.000% : 1,694.853 Abandonment : 336.970 bbl/month Disc. Initial Invest. (M$) : 162.446 PW 9.000% : 1,654.504 Initial Decline : 30.51 % year b = 1.001 ROInvestment (disc/undisc) : 10.95 / 9.15 PW 10.000% : 1,615.998 Beg Ratio : 10.402 mcf/bbl Years to Payout : 0.41 PW 12.000% : 1,544.120 End Ratio : 11.013 mcf/bbl Internal ROR (%) : >1000 PW 15.000% : 1,447.776 LPC Eco DetailedNGL.rpt Page 21 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : LION 3H - 3H Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : PHANTOM Archive Set : L19910 Operator : LILIS ENERGY, INC. Reservoir : Cum Oil (Mbbl) : 201.350 Based on SEC Parameters WOLFCAMP B Co., State : Cum Gas (MMcf) : 1,428.456 Constant Prices & Costs WINKLER, TX API : 4249533944 Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 48.215 391.336 34.883 220.840 16.920 52.73 1.37 15.04 2,396.510 2021 35.979 290.811 26.031 164.111 12.574 53.57 1.37 15.04 1,808.364 2022 28.770 231.577 20.815 130.684 10.013 53.57 1.37 15.04 1,444.650 2023 23.974 192.173 17.345 108.448 8.309 53.57 1.37 15.04 1,202.685 2024 20.604 164.474 14.907 92.816 7.111 53.57 1.37 15.04 1,032.641 2025 17.979 142.927 13.008 80.657 6.180 53.57 1.37 15.04 900.249 2026 15.985 126.548 11.565 71.414 5.472 53.57 1.37 15.04 799.643 2027 14.389 113.445 10.411 64.020 4.905 53.57 1.37 15.04 719.156 2028 13.118 102.994 9.491 58.122 4.453 53.57 1.37 15.04 655.006 2029 11.993 93.770 8.677 52.917 4.054 53.57 1.37 15.04 598.269 2030 11.072 86.215 8.011 48.653 3.728 53.57 1.37 15.04 551.839 2031 10.283 79.739 7.440 44.999 3.448 53.57 1.37 15.04 512.037 2032 9.625 74.323 6.963 41.942 3.214 53.57 1.37 15.04 478.802 2033 8.999 69.203 6.510 39.053 2.992 53.57 1.37 15.04 447.258 2034 8.458 64.774 6.119 36.553 2.801 53.57 1.37 15.04 419.985 Rem 86.415 641.547 62.520 362.039 27.739 0.00 0.00 0.00 4,262.284 Total 365.858 2,865.856 264.695 1,617.268 123.912 53.46 1.37 15.04 18,229.378 Ult 567.208 4,294.312 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 126.830 59.913 169.488 447.055 0.000 1,593.225 1,522.495 1,522.495 2021 1 95.514 45.209 104.680 332.673 0.000 1,230.288 1,068.798 2,591.293 2022 1 76.273 36.116 104.680 265.275 0.000 962.306 759.743 3,351.036 2023 1 63.472 30.067 104.680 220.440 0.000 784.027 562.608 3,913.643 2024 1 54.476 25.816 104.680 188.926 0.000 658.743 429.629 4,343.273 2025 1 47.473 22.506 104.680 164.403 0.000 561.188 332.658 4,675.931 2026 1 42.151 19.991 104.680 145.763 0.000 487.058 262.457 4,938.388 2027 1 37.893 17.979 104.680 130.852 0.000 427.752 209.540 5,147.927 2028 1 34.499 16.375 104.680 118.963 0.000 380.490 169.424 5,317.351 2029 1 31.498 14.957 104.680 108.460 0.000 338.675 137.075 5,454.426 2030 1 29.042 13.796 104.680 99.860 0.000 304.461 112.026 5,566.452 2031 1 26.937 12.801 104.680 92.489 0.000 275.130 92.033 5,658.485 2032 1 25.178 11.970 104.680 86.328 0.000 250.645 76.215 5,734.700 2033 1 23.510 11.181 104.680 80.494 0.000 227.393 62.850 5,797.550 2034 1 22.068 10.500 104.680 75.448 0.000 207.290 52.089 5,849.639 Rem 223.306 106.557 1,784.339 755.325 120.063 1,272.694 211.376 Total 960.120 455.734 3,419.344 3,312.753 120.063 9,961.363 6,061.015 6,061.015 Major Phase : Oil Abandonment Date : 01/17/2052 Present Worth Profile (M$) Perfs : 0 - 0 Working Int : 0.97217342 PW 5.000% : 7,490.595 Initial Rate : 4,756.723 bbl/month Revenue Int : 0.72349069 PW 8.000% : 6,551.279 Abandonment : 238.128 bbl/month Disc. Initial Invest. (M$) : 5.663 PW 9.000% : 6,294.916 Initial Decline : 32.74 % year b = 1.000 ROInvestment (disc/undisc) : 1,071.32 / 83.97 PW 10.000% : 6,061.015 Beg Ratio : 8.132 mcf/bbl Years to Payout : 0.07 PW 12.000% : 5,650.005 End Ratio : 7.122 mcf/bbl Internal ROR (%) : >1000 PW 15.000% : 5,145.097 LPC Eco DetailedNGL.rpt Page 22 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : MEERKAT 1H - 1H Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : PHANTOM Archive Set : L19910 Operator : LILIS ENERGY, INC. Reservoir : Cum Oil (Mbbl) : 121.980 Based on SEC Parameters WOLFCAMP XY Co., State : Cum Gas (MMcf) : 1,290.570 Constant Prices & Costs WINKLER, TX API : 4249533991 Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 33.437 420.543 25.078 246.017 18.849 52.73 1.37 15.04 1,942.861 2021 24.628 318.959 18.471 186.591 14.296 53.57 1.37 15.04 1,460.084 2022 19.544 257.540 14.658 150.661 11.543 53.57 1.37 15.04 1,165.190 2023 16.204 216.005 12.153 126.363 9.682 53.57 1.37 15.04 969.737 2024 13.877 186.505 10.408 109.105 8.359 53.57 1.37 15.04 832.702 2025 12.077 163.316 9.058 95.540 7.320 53.57 1.37 15.04 726.176 2026 10.715 145.596 8.036 85.174 6.526 53.57 1.37 15.04 645.325 2027 9.630 131.349 7.222 76.839 5.887 53.57 1.37 15.04 580.698 2028 8.767 119.958 6.575 70.176 5.377 53.57 1.37 15.04 529.235 2029 8.006 109.833 6.005 64.252 4.923 53.57 1.37 15.04 483.723 2030 7.385 101.531 5.539 59.395 4.551 53.57 1.37 15.04 446.504 2031 6.853 94.396 5.140 55.222 4.231 53.57 1.37 15.04 414.609 2032 6.410 88.433 4.807 51.733 3.964 53.57 1.37 15.04 387.996 2033 5.989 82.743 4.492 48.405 3.709 53.57 1.37 15.04 362.712 2034 5.628 77.778 4.221 45.500 3.486 53.57 1.37 15.04 340.888 Rem 46.373 640.819 34.780 374.879 28.722 0.00 0.00 0.00 2,808.613 Total 235.524 3,155.304 176.643 1,845.853 141.425 53.45 1.37 15.04 14,097.054 Ult 357.504 4,445.874 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 107.741 48.572 174.339 439.242 0.000 1,172.968 1,120.915 1,120.915 2021 1 81.092 36.502 107.676 330.850 0.000 903.964 785.393 1,906.308 2022 1 64.843 29.130 107.676 266.070 0.000 697.471 550.706 2,457.014 2023 1 54.037 24.243 107.676 222.572 0.000 561.208 402.749 2,859.763 2024 1 46.445 20.818 107.676 191.817 0.000 465.946 303.914 3,163.677 2025 1 40.532 18.154 107.676 167.735 0.000 392.079 232.432 3,396.109 2026 1 36.039 16.133 107.676 149.375 0.000 336.101 181.126 3,577.236 2027 1 32.445 14.517 107.676 134.643 0.000 291.417 142.765 3,720.001 2028 1 29.580 13.231 107.676 122.881 0.000 255.867 113.943 3,833.944 2029 1 27.044 12.093 107.676 112.443 0.000 224.467 90.857 3,924.801 2030 1 24.970 11.163 107.676 103.892 0.000 198.803 73.155 3,997.956 2031 1 23.191 10.365 107.676 96.552 0.000 176.825 59.154 4,057.110 2032 1 21.707 9.700 107.676 90.420 0.000 158.494 48.199 4,105.309 2033 1 20.295 9.068 107.676 84.577 0.000 141.096 39.002 4,144.311 2034 1 19.075 8.522 107.676 79.497 0.000 126.118 31.695 4,176.005 Rem 157.160 70.215 1,297.322 654.983 123.500 505.433 99.336 Total 786.196 352.426 2,979.125 3,247.549 123.500 6,608.257 4,275.342 4,275.342 Major Phase : Oil Abandonment Date : 01/18/2047 Present Worth Profile (M$) Perfs : 0 - 0 Working Int : 1.00000000 PW 5.000% : 5,172.872 Initial Rate : 3,328.820 bbl/month Revenue Int : 0.75000001 PW 8.000% : 4,589.119 Abandonment : 215.881 bbl/month Disc. Initial Invest. (M$) : 9.378 PW 9.000% : 4,425.830 Initial Decline : 34.35 % year b = 1.000 ROInvestment (disc/undisc) : 456.89 / 54.51 PW 10.000% : 4,275.342 Beg Ratio : 12.326 mcf/bbl Years to Payout : 0.09 PW 12.000% : 4,007.430 End Ratio : 13.819 mcf/bbl Internal ROR (%) : >1000 PW 15.000% : 3,672.341 LPC Eco DetailedNGL.rpt Page 23 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : MOOSE 1H - 1H Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : PHANTOM Archive Set : L19910 Operator : LILIS ENERGY, INC. Reservoir : Cum Oil (Mbbl) : 148.265 Based on SEC Parameters WOLFCAMP A Co., State : Cum Gas (MMcf) : 831.566 Constant Prices & Costs WINKLER, TX API : 4249534035 Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 54.845 297.515 33.080 139.970 10.724 52.73 1.37 15.04 2,097.367 2021 40.327 219.980 24.324 103.493 7.929 53.57 1.37 15.04 1,564.039 2022 31.971 174.957 19.283 82.311 6.306 53.57 1.37 15.04 1,240.603 2023 26.491 145.274 15.978 68.346 5.237 53.57 1.37 15.04 1,028.322 2024 22.676 124.537 13.677 58.590 4.489 53.57 1.37 15.04 880.445 2025 19.728 108.468 11.899 51.030 3.910 53.57 1.37 15.04 766.134 2026 17.499 96.295 10.555 45.304 3.471 53.57 1.37 15.04 679.676 2027 15.723 86.583 9.484 40.734 3.121 53.57 1.37 15.04 610.775 2028 14.313 78.857 8.633 37.100 2.842 53.57 1.37 15.04 556.023 2029 13.068 72.036 7.882 33.891 2.597 53.57 1.37 15.04 507.733 2030 12.053 66.463 7.270 31.268 2.396 53.57 1.37 15.04 468.296 2031 11.183 61.690 6.745 29.023 2.224 53.57 1.37 15.04 434.549 2032 10.459 57.710 6.308 27.151 2.080 53.57 1.37 15.04 406.417 2033 9.772 53.935 5.894 25.374 1.944 53.57 1.37 15.04 379.750 2034 9.183 50.688 5.539 23.847 1.827 53.57 1.37 15.04 356.868 Rem 77.014 425.083 46.452 199.986 15.323 0.00 0.00 0.00 2,992.807 Total 386.305 2,120.069 233.004 997.418 76.420 53.45 1.37 15.04 14,969.805 Ult 534.570 2,951.635 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 107.083 52.434 144.963 323.012 115.911 1,353.964 1,297.331 1,297.331 2021 1 79.785 39.101 124.182 238.289 0.000 1,082.682 940.698 2,238.029 2022 1 63.302 31.015 124.182 189.269 0.000 832.834 657.597 2,895.626 2023 1 52.479 25.708 124.182 157.023 0.000 668.929 480.061 3,375.687 2024 1 44.938 22.011 124.182 134.527 0.000 554.786 361.863 3,737.550 2025 1 39.107 19.153 124.182 117.116 0.000 466.576 276.597 4,014.147 2026 1 34.696 16.992 124.182 103.937 0.000 399.869 215.491 4,229.638 2027 1 31.180 15.269 124.182 93.428 0.000 346.715 169.856 4,399.494 2028 1 28.387 13.901 124.182 85.073 0.000 304.481 135.591 4,535.085 2029 1 25.922 12.693 124.182 77.700 0.000 267.236 108.169 4,643.254 2030 1 23.910 11.707 124.182 71.676 0.000 236.821 87.145 4,730.399 2031 1 22.187 10.864 124.182 66.520 0.000 210.796 70.518 4,800.917 2032 1 20.751 10.160 124.182 62.222 0.000 189.101 57.507 4,858.424 2033 1 19.390 9.494 124.182 58.145 0.000 168.539 46.587 4,905.011 2034 1 18.222 8.922 124.182 54.643 0.000 150.899 37.922 4,942.933 Rem 152.813 74.820 1,535.945 458.254 95.433 675.541 125.245 Total 764.153 374.245 3,419.460 2,290.835 211.344 7,909.768 5,068.177 5,068.177 Major Phase : Oil Abandonment Date : 05/16/2047 Present Worth Profile (M$) Perfs : 0 - 0 Working Int : 0.77273914 PW 5.000% : 6,150.098 Initial Rate : 5,466.529 bbl/month Revenue Int : 0.60315999 PW 8.000% : 5,445.066 Abandonment : 345.262 bbl/month Disc. Initial Invest. (M$) : 114.940 PW 9.000% : 5,248.768 Initial Decline : 34.56 % year b = 1.000 ROInvestment (disc/undisc) : 45.09 / 38.43 PW 10.000% : 5,068.177 Beg Ratio : 5.404 mcf/bbl Years to Payout : 0.13 PW 12.000% : 4,747.376 End Ratio : 5.520 mcf/bbl Internal ROR (%) : >1000 PW 15.000% : 4,347.266 LPC Eco DetailedNGL.rpt Page 24 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : NE AXIS 2H Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : PHANTOM Archive Set : L19910 Operator : LILIS ENERGY, INC. Reservoir : Cum Oil (Mbbl) : 52.198 Based on SEC Parameters WOLFCAMP A Co., State : Cum Gas (MMcf) : 830.002 Constant Prices & Costs WINKLER, TX API : Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 60.187 523.142 46.845 317.594 24.333 52.68 1.37 15.04 3,268.586 2021 36.204 432.510 28.178 262.572 20.118 53.57 1.37 15.04 2,171.725 2022 26.020 301.143 20.252 182.821 14.007 53.57 1.37 15.04 1,545.979 2023 20.327 231.272 15.821 140.403 10.757 53.57 1.37 15.04 1,201.611 2024 16.725 188.273 13.018 114.298 8.757 53.57 1.37 15.04 985.621 2025 14.144 158.054 11.009 95.953 7.352 53.57 1.37 15.04 831.744 2026 12.282 136.508 9.559 82.872 6.350 53.57 1.37 15.04 721.091 2027 10.853 120.139 8.447 72.935 5.588 53.57 1.37 15.04 636.468 2028 9.748 107.559 7.587 65.298 5.003 53.57 1.37 15.04 571.128 2029 8.804 96.886 6.852 58.818 4.507 53.57 1.37 15.04 515.405 2030 8.045 88.351 6.262 53.637 4.110 53.57 1.37 15.04 470.718 2031 7.407 81.199 5.765 49.295 3.777 53.57 1.37 15.04 433.169 2032 6.881 75.317 5.356 45.724 3.503 53.57 1.37 15.04 402.232 2033 6.392 69.874 4.975 42.420 3.250 53.57 1.37 15.04 373.512 2034 5.983 65.325 4.657 39.658 3.039 53.57 1.37 15.04 349.485 Rem 45.638 497.939 35.521 302.294 23.161 0.00 0.00 0.00 2,665.256 Total 295.641 3,173.493 230.103 1,926.593 147.611 53.39 1.37 15.04 17,143.727 Ult 347.839 4,003.495 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 174.186 81.715 174.339 881.884 0.000 1,956.462 1,874.181 1,874.181 2021 1 119.516 54.293 107.676 686.671 0.000 1,203.568 1,046.831 2,921.013 2022 1 84.779 38.649 107.676 480.651 0.000 834.223 659.102 3,580.115 2023 1 65.770 30.040 107.676 370.207 0.000 627.919 450.818 4,030.932 2024 1 53.884 24.641 107.676 301.932 0.000 497.488 324.590 4,355.523 2025 1 45.435 20.794 107.676 253.795 0.000 404.044 239.585 4,595.108 2026 1 39.367 18.027 107.676 219.402 0.000 336.618 181.441 4,776.549 2027 1 34.732 15.912 107.676 193.232 0.000 284.916 139.605 4,916.154 2028 1 31.155 14.278 107.676 173.097 0.000 244.922 109.085 5,025.239 2029 1 28.107 12.885 107.676 155.991 0.000 210.745 85.315 5,110.555 2030 1 25.664 11.768 107.676 142.303 0.000 183.307 67.462 5,178.016 2031 1 23.613 10.829 107.676 130.825 0.000 160.226 53.607 5,231.624 2032 1 21.922 10.056 107.676 121.382 0.000 141.196 42.944 5,274.568 2033 1 20.354 9.338 107.676 112.636 0.000 123.509 34.144 5,308.712 2034 1 19.042 8.737 107.676 105.325 0.000 108.704 27.320 5,336.032 Rem 145.212 66.631 1,160.174 802.936 123.500 366.803 76.579 Total 932.740 428.593 2,841.977 5,132.270 123.500 7,684.647 5,412.611 5,412.611 Major Phase : Oil Abandonment Date : 10/13/2045 Present Worth Profile (M$) Perfs : 0 - 0 Working Int : 1.00000000 PW 5.000% : 6,311.733 Initial Rate : 7,014.484 bbl/month Revenue Int : 0.77831945 PW 8.000% : 5,731.252 Abandonment : 247.983 bbl/month Disc. Initial Invest. (M$) : 10.580 PW 9.000% : 5,566.056 Initial Decline : 59.54 % year b = 1.000 ROInvestment (disc/undisc) : 512.61 / 63.22 PW 10.000% : 5,412.611 Beg Ratio : 0.000 mcf/bbl Years to Payout : 0.05 PW 12.000% : 5,136.395 End Ratio : 10.911 mcf/bbl Internal ROR (%) : >1000 PW 15.000% : 4,784.949 LPC Eco DetailedNGL.rpt Page 25 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : OSO 1H Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : PHANTOM Archive Set : L19910 Operator : LILIS ENERGY, INC. Reservoir : Cum Oil (Mbbl) : 83.763 Based on SEC Parameters WOLFCAMP A Co., State : Cum Gas (MMcf) : 550.299 Constant Prices & Costs WINKLER, TX API : Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 43.280 252.915 29.470 134.326 10.292 52.67 1.37 15.04 1,890.955 2021 25.474 151.936 17.346 80.695 6.183 53.57 1.37 15.04 1,132.729 2022 18.149 109.139 12.358 57.965 4.441 53.57 1.37 15.04 808.194 2023 14.110 85.233 9.607 45.268 3.468 53.57 1.37 15.04 628.839 2024 11.575 70.119 7.881 37.241 2.853 53.57 1.37 15.04 516.122 2025 9.768 59.291 6.651 31.490 2.413 53.57 1.37 15.04 435.717 2026 8.468 51.478 5.766 27.341 2.095 53.57 1.37 15.04 377.855 2027 7.475 45.487 5.090 24.159 1.851 53.57 1.37 15.04 333.580 2028 6.707 40.853 4.567 21.698 1.662 53.57 1.37 15.04 299.381 2029 6.053 36.893 4.121 19.594 1.501 53.57 1.37 15.04 270.205 2030 5.528 33.714 3.764 17.906 1.372 53.57 1.37 15.04 246.802 2031 5.087 31.039 3.464 16.485 1.263 53.57 1.37 15.04 227.133 2032 4.724 28.835 3.216 15.314 1.173 53.57 1.37 15.04 210.927 2033 4.386 26.785 2.987 14.226 1.090 53.57 1.37 15.04 195.878 2034 4.104 25.070 2.795 13.315 1.020 53.57 1.37 15.04 183.286 Rem 20.000 122.190 13.618 64.896 4.972 0.00 0.00 0.00 893.210 Total 194.888 1,170.976 132.702 621.918 47.650 53.37 1.37 15.04 8,650.813 Ult 278.651 1,721.275 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 97.142 47.274 151.433 300.351 0.000 1,294.755 1,240.923 1,240.923 2021 1 58.205 28.318 93.529 179.003 0.000 773.674 673.042 1,913.965 2022 1 41.557 20.205 93.529 128.174 0.000 524.729 414.637 2,328.602 2023 1 32.347 15.721 93.529 99.925 0.000 387.317 278.115 2,606.717 2024 1 26.555 12.903 93.529 82.116 0.000 301.019 196.431 2,803.148 2025 1 22.422 10.893 93.529 69.383 0.000 239.490 142.030 2,945.178 2026 1 19.447 9.446 93.529 60.207 0.000 195.226 105.245 3,050.422 2027 1 17.170 8.339 93.529 53.178 0.000 161.364 79.078 3,129.500 2028 1 15.411 7.485 93.529 47.744 0.000 135.213 60.234 3,189.734 2029 1 13.910 6.755 93.529 43.105 0.000 112.907 45.716 3,235.450 2030 1 12.706 6.170 93.529 39.381 0.000 95.017 34.975 3,270.425 2031 1 11.694 5.678 93.529 36.251 0.000 79.983 26.766 3,297.191 2032 1 10.860 5.273 93.529 33.670 0.000 67.595 20.565 3,317.756 2033 1 10.085 4.897 93.529 31.273 0.000 56.094 15.511 3,333.268 2034 1 9.437 4.582 93.529 29.266 0.000 46.472 11.683 3,344.951 Rem 45.990 22.330 563.182 142.635 107.273 11.799 9.399 Total 444.938 216.270 2,024.015 1,375.662 107.273 4,482.655 3,354.350 3,354.350 Major Phase : Oil Abandonment Date : 01/08/2041 Present Worth Profile (M$) Perfs : 0 - 0 Working Int : 0.86861066 PW 5.000% : 3,824.074 Initial Rate : 5,140.698 bbl/month Revenue Int : 0.68091125 PW 8.000% : 3,524.508 Abandonment : 228.340 bbl/month Disc. Initial Invest. (M$) : 14.467 PW 9.000% : 3,436.804 Initial Decline : 62.16 % year b = 1.000 ROInvestment (disc/undisc) : 232.87 / 42.79 PW 10.000% : 3,354.350 Beg Ratio : 5.740 mcf/bbl Years to Payout : 0.06 PW 12.000% : 3,203.521 End Ratio : 6.109 mcf/bbl Internal ROR (%) : >1000 PW 15.000% : 3,007.176 LPC Eco DetailedNGL.rpt Page 26 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : PRIZE HOG BWZ ST COM 1H - #1H Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : TBD Archive Set : L19910 Operator : LILIS ENERGY, INC. Reservoir : Cum Oil (Mbbl) : 161.108 Based on SEC Parameters WOLFCAMP B Co., State : Cum Gas (MMcf) : 335.951 Constant Prices & Costs LEA, NM API : 3002542744 Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 32.302 69.662 25.539 42.960 3.291 52.74 1.37 15.04 1,455.207 2021 24.387 52.411 19.281 32.322 2.476 53.57 1.37 15.04 1,114.390 2022 19.636 42.114 15.525 25.971 1.990 53.57 1.37 15.04 897.163 2023 16.438 35.207 12.997 21.712 1.664 53.57 1.37 15.04 750.988 2024 14.174 30.328 11.207 18.703 1.433 53.57 1.37 15.04 647.505 2025 12.399 26.511 9.803 16.349 1.253 53.57 1.37 15.04 566.394 2026 11.045 23.602 8.733 14.555 1.115 53.57 1.37 15.04 504.518 2027 9.958 21.269 7.873 13.116 1.005 53.57 1.37 15.04 454.845 2028 9.090 19.407 7.187 11.968 0.917 53.57 1.37 15.04 415.172 2029 8.319 17.755 6.577 10.950 0.839 53.57 1.37 15.04 379.953 2030 7.687 16.403 6.078 10.115 0.775 53.57 1.37 15.04 351.096 2031 7.145 15.242 5.649 9.399 0.720 53.57 1.37 15.04 326.316 2032 6.692 14.272 5.291 8.801 0.674 53.57 1.37 15.04 305.614 2033 6.260 13.349 4.949 8.232 0.631 53.57 1.37 15.04 285.886 2034 5.884 12.547 4.652 7.738 0.593 53.57 1.37 15.04 268.724 Rem 18.509 39.470 14.634 24.341 1.865 0.00 0.00 0.00 845.328 Total 209.926 449.550 165.973 277.232 21.241 53.44 1.37 15.04 9,569.100 Ult 371.034 785.501 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 104.095 72.760 215.634 159.531 150.000 753.187 719.298 719.298 2021 1 79.703 55.720 160.704 120.288 0.000 697.976 606.461 1,325.759 2022 1 64.166 44.858 160.704 96.782 0.000 530.653 419.037 1,744.796 2023 1 53.711 37.549 160.704 80.981 0.000 418.044 300.052 2,044.848 2024 1 46.309 32.375 160.704 69.802 0.000 338.315 220.711 2,265.559 2025 1 40.508 28.320 160.704 61.044 0.000 275.818 163.543 2,429.102 2026 1 36.082 25.226 160.704 54.367 0.000 228.139 122.972 2,552.074 2027 1 32.530 22.742 160.704 49.007 0.000 189.862 93.036 2,645.110 2028 1 29.692 20.759 160.704 44.728 0.000 159.289 70.958 2,716.068 2029 1 27.173 18.998 160.704 40.930 0.000 132.148 53.506 2,769.574 2030 1 25.110 17.555 160.704 37.818 0.000 109.909 40.458 2,810.032 2031 1 23.337 16.316 160.704 35.147 0.000 90.812 30.392 2,840.424 2032 1 21.857 15.281 160.704 32.915 0.000 74.858 22.778 2,863.202 2033 1 20.446 14.294 160.704 30.789 0.000 59.653 16.498 2,879.700 2034 1 19.218 13.436 160.704 28.940 0.000 46.425 11.676 2,891.376 Rem 60.456 42.266 580.447 91.038 98.200 -27.078 -1.456 Total 684.392 478.455 3,045.937 1,034.105 248.200 4,078.012 2,889.920 2,889.920 Major Phase : Oil Abandonment Date : 08/14/2038 Present Worth Profile (M$) Perfs : 0 - 0 Working Int : 1.00000000 PW 5.000% : 3,382.225 Initial Rate : 3,161.594 bbl/month Revenue Int : 0.79062500 PW 8.000% : 3,067.857 Abandonment : 380.215 bbl/month Disc. Initial Invest. (M$) : 159.696 PW 9.000% : 2,976.080 Initial Decline : 31.31 % year b = 1.000 ROInvestment (disc/undisc) : 19.10 / 17.43 PW 10.000% : 2,889.920 Beg Ratio : 2.162 mcf/bbl Years to Payout : 0.26 PW 12.000% : 2,732.660 End Ratio : 2.132 mcf/bbl Internal ROR (%) : >1000 PW 15.000% : 2,528.766 LPC Eco DetailedNGL.rpt Page 27 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : PRIZE HOG BWZ ST COM 2H - 002H Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : PHANTOM Archive Set : L19910 Operator : LILIS ENERGY, INC. Reservoir : Cum Oil (Mbbl) : 140.137 Based on SEC Parameters WOLFCAMP A Co., State : Cum Gas (MMcf) : 474.200 Constant Prices & Costs LEA, NM API : 3002544111 Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 37.741 154.887 29.485 94.384 7.232 52.72 1.37 15.04 1,792.424 2021 26.409 113.277 20.632 69.028 5.289 53.57 1.37 15.04 1,279.355 2022 20.372 89.527 15.915 54.555 4.180 53.57 1.37 15.04 990.177 2023 16.588 74.033 12.959 45.114 3.457 53.57 1.37 15.04 808.019 2024 14.028 63.281 10.960 38.562 2.955 53.57 1.37 15.04 684.357 2025 12.096 54.997 9.450 33.514 2.568 53.57 1.37 15.04 590.778 2026 10.657 48.745 8.326 29.704 2.276 53.57 1.37 15.04 520.923 2027 9.524 43.770 7.441 26.672 2.044 53.57 1.37 15.04 465.864 2028 8.632 39.822 6.743 24.266 1.859 53.57 1.37 15.04 422.446 2029 7.853 36.345 6.135 22.148 1.697 53.57 1.37 15.04 384.510 2030 7.220 33.507 5.641 20.418 1.564 53.57 1.37 15.04 353.681 2031 6.682 31.081 5.221 18.940 1.451 53.57 1.37 15.04 327.434 2032 6.235 29.060 4.871 17.708 1.357 53.57 1.37 15.04 305.623 2033 5.815 27.145 4.543 16.542 1.267 53.57 1.37 15.04 285.074 2034 5.459 25.508 4.265 15.544 1.191 53.57 1.37 15.04 267.680 Rem 13.570 63.403 10.601 38.636 2.960 0.00 0.00 0.00 665.353 Total 208.881 928.387 163.188 565.736 43.345 53.42 1.37 15.04 10,143.697 Ult 349.018 1,402.587 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 129.106 89.621 187.596 246.490 150.000 989.611 950.526 950.526 2021 1 92.186 63.968 160.704 176.538 0.000 785.959 683.212 1,633.738 2022 1 71.373 49.509 160.704 137.959 0.000 570.633 450.741 2,084.479 2023 1 58.256 40.401 160.704 113.276 0.000 435.383 312.566 2,397.044 2024 1 49.348 34.218 160.704 96.353 0.000 343.735 224.286 2,621.330 2025 1 42.605 29.539 160.704 83.441 0.000 274.489 162.780 2,784.110 2026 1 37.570 26.046 160.704 73.753 0.000 222.849 120.137 2,904.247 2027 1 33.602 23.293 160.704 66.085 0.000 182.180 89.284 2,993.531 2028 1 30.472 21.122 160.704 60.019 0.000 150.129 66.887 3,060.418 2029 1 27.737 19.225 160.704 54.700 0.000 122.144 49.462 3,109.880 2030 1 25.514 17.684 160.704 50.369 0.000 99.411 36.599 3,146.479 2031 1 23.621 16.372 160.704 46.674 0.000 80.063 26.799 3,173.277 2032 1 22.048 15.281 160.704 43.600 0.000 63.990 19.476 3,192.754 2033 1 20.566 14.254 160.704 40.697 0.000 48.853 13.514 3,206.268 2034 1 19.312 13.384 160.704 38.227 0.000 36.053 9.070 3,215.338 Rem 48.002 33.268 446.766 95.018 98.200 -55.901 -8.781 Total 731.316 507.185 2,884.218 1,423.198 248.200 4,349.580 3,206.557 3,206.557 Major Phase : Oil Abandonment Date : 10/15/2037 Present Worth Profile (M$) Perfs : 0 - 0 Working Int : 1.00000000 PW 5.000% : 3,686.550 Initial Rate : 3,897.892 bbl/month Revenue Int : 0.78125000 PW 8.000% : 3,381.195 Abandonment : 371.347 bbl/month Disc. Initial Invest. (M$) : 157.673 PW 9.000% : 3,291.289 Initial Decline : 40.73 % year b = 1.000 ROInvestment (disc/undisc) : 21.34 / 18.52 PW 10.000% : 3,206.557 Beg Ratio : 3.976 mcf/bbl Years to Payout : 0.19 PW 12.000% : 3,051.050 End Ratio : 4.672 mcf/bbl Internal ROR (%) : >1000 PW 15.000% : 2,847.710 LPC Eco DetailedNGL.rpt Page 28 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : TIGER 1H - 1H Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : PHANTOM Archive Set : L19910 Operator : LILIS ENERGY, INC. Reservoir : Cum Oil (Mbbl) : 174.812 Based on SEC Parameters WOLFCAMP B Co., State : Cum Gas (MMcf) : 1,050.700 Constant Prices & Costs WINKLER, TX API : 4249530016 Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 37.321 221.511 27.181 125.834 9.641 52.74 1.37 15.04 1,750.746 2021 27.944 167.536 20.352 95.172 7.292 53.57 1.37 15.04 1,330.269 2022 22.390 135.046 16.306 76.716 5.878 53.57 1.37 15.04 1,067.014 2023 18.682 113.137 13.606 64.270 4.924 53.57 1.37 15.04 890.972 2024 16.071 97.606 11.704 55.447 4.248 53.57 1.37 15.04 766.849 2025 14.034 85.418 10.221 48.524 3.718 53.57 1.37 15.04 669.901 2026 12.484 76.113 9.092 43.238 3.313 53.57 1.37 15.04 596.106 2027 11.243 68.639 8.188 38.992 2.987 53.57 1.37 15.04 536.974 2028 10.253 62.666 7.467 35.599 2.728 53.57 1.37 15.04 489.806 2029 9.376 57.361 6.829 32.585 2.497 53.57 1.37 15.04 448.004 2030 8.659 53.014 6.306 30.116 2.307 53.57 1.37 15.04 413.782 2031 8.044 49.279 5.858 27.994 2.145 53.57 1.37 15.04 384.421 2032 7.530 46.158 5.484 26.221 2.009 53.57 1.37 15.04 359.905 2033 7.041 43.183 5.128 24.531 1.880 53.57 1.37 15.04 336.578 2034 6.618 40.591 4.820 23.059 1.767 53.57 1.37 15.04 316.359 Rem 40.015 245.425 29.143 139.419 10.682 0.00 0.00 0.00 1,912.805 Total 257.704 1,562.684 187.685 887.718 68.015 53.45 1.37 15.04 12,270.490 Ult 432.516 2,613.384 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 90.047 43.769 171.317 276.113 0.000 1,169.501 1,117.534 1,117.534 2021 1 68.385 33.257 144.421 208.037 0.000 876.168 761.243 1,878.777 2022 1 54.880 26.675 144.421 167.313 0.000 673.725 531.972 2,410.749 2023 1 45.841 22.274 144.421 139.958 0.000 538.478 386.455 2,797.204 2024 1 39.464 19.171 144.421 120.614 0.000 443.178 289.084 3,086.288 2025 1 34.481 16.748 144.421 105.467 0.000 368.785 218.638 3,304.926 2026 1 30.687 14.903 144.421 93.919 0.000 312.176 168.245 3,473.171 2027 1 27.646 13.424 144.421 84.653 0.000 266.829 130.730 3,603.902 2028 1 25.220 12.245 144.421 77.255 0.000 230.664 102.731 3,706.632 2029 1 23.070 11.200 144.421 70.691 0.000 198.622 80.404 3,787.036 2030 1 21.309 10.345 144.421 65.314 0.000 172.393 63.444 3,850.480 2031 1 19.798 9.611 144.421 60.697 0.000 149.894 50.150 3,900.630 2032 1 18.536 8.998 144.421 56.841 0.000 131.109 39.878 3,940.508 2033 1 17.336 8.414 144.421 53.168 0.000 113.239 31.306 3,971.814 2034 1 16.294 7.909 144.421 49.975 0.000 97.759 24.572 3,996.386 Rem 98.520 47.820 1,137.229 302.167 110.987 216.082 49.947 Total 631.516 306.762 3,330.440 1,932.182 110.987 5,958.603 4,046.333 4,046.333 Major Phase : Oil Abandonment Date : 11/15/2042 Present Worth Profile (M$) Perfs : 0 - 0 Working Int : 0.89867727 PW 5.000% : 4,807.698 Initial Rate : 3,673.421 bbl/month Revenue Int : 0.72829804 PW 8.000% : 4,316.577 Abandonment : 328.670 bbl/month Disc. Initial Invest. (M$) : 12.547 PW 9.000% : 4,176.505 Initial Decline : 32.32 % year b = 1.000 ROInvestment (disc/undisc) : 323.50 / 54.69 PW 10.000% : 4,046.333 Beg Ratio : 5.895 mcf/bbl Years to Payout : 0.08 PW 12.000% : 3,811.984 End Ratio : 6.133 mcf/bbl Internal ROR (%) : >1000 PW 15.000% : 3,514.140 LPC Eco DetailedNGL.rpt Page 29 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : TIGER 3H - 3H Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : PHANTOM Archive Set : L19910 Operator : LILIS ENERGY, INC. Reservoir : Cum Oil (Mbbl) : 157.238 Based on SEC Parameters 3RD BONE SPRINGS Co., State : Cum Gas (MMcf) : 1,144.484 Constant Prices & Costs WINKLER, TX API : 4249534177 Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 56.999 465.053 41.108 261.613 20.044 52.70 1.37 15.04 2,826.199 2021 37.312 311.580 26.910 175.277 13.429 53.57 1.37 15.04 1,883.629 2022 27.837 235.073 20.076 132.239 10.132 53.57 1.37 15.04 1,408.999 2023 22.213 188.837 16.021 106.229 8.139 53.57 1.37 15.04 1,126.137 2024 18.532 158.237 13.365 89.015 6.820 53.57 1.37 15.04 940.485 2025 15.825 135.547 11.413 76.251 5.842 53.57 1.37 15.04 803.698 2026 13.839 118.822 9.981 66.843 5.121 53.57 1.37 15.04 703.271 2027 12.297 105.777 8.869 59.504 4.559 53.57 1.37 15.04 625.186 2028 11.094 95.564 8.001 53.759 4.119 53.57 1.37 15.04 564.195 2029 10.055 86.718 7.252 48.783 3.738 53.57 1.37 15.04 511.501 2030 9.216 79.562 6.647 44.757 3.429 53.57 1.37 15.04 468.939 2031 8.506 73.498 6.135 41.346 3.168 53.57 1.37 15.04 432.921 2032 7.919 68.475 5.711 38.520 2.951 53.57 1.37 15.04 403.110 2033 7.370 63.767 5.315 35.872 2.748 53.57 1.37 15.04 375.217 2034 6.909 59.810 4.983 33.646 2.578 53.57 1.37 15.04 351.796 Rem 67.901 587.847 48.971 330.690 25.337 0.00 0.00 0.00 3,457.402 Total 333.825 2,834.167 240.758 1,594.345 122.155 53.42 1.37 15.04 16,882.685 Ult 491.063 3,978.651 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 149.657 70.655 152.202 511.546 0.000 1,942.139 1,858.834 1,858.834 2021 1 99.808 47.091 94.004 340.336 0.000 1,302.391 1,132.232 2,991.067 2022 1 74.741 35.225 94.004 255.911 0.000 949.117 749.651 3,740.718 2023 1 59.776 28.153 94.004 205.171 0.000 739.032 530.476 4,271.194 2024 1 49.944 23.512 94.004 171.701 0.000 601.324 392.266 4,663.460 2025 1 42.693 20.092 94.004 146.944 0.000 499.965 296.416 4,959.876 2026 1 37.367 17.582 94.004 128.723 0.000 425.594 229.368 5,189.244 2027 1 33.224 15.630 94.004 114.529 0.000 367.799 180.192 5,369.436 2028 1 29.988 14.105 94.004 103.427 0.000 322.672 143.693 5,513.129 2029 1 27.190 12.788 94.004 93.820 0.000 283.700 114.834 5,627.963 2030 1 24.930 11.723 94.004 86.053 0.000 252.228 92.814 5,720.777 2031 1 23.017 10.823 94.004 79.475 0.000 225.602 75.471 5,796.248 2032 1 21.434 10.078 94.004 74.027 0.000 203.567 61.904 5,858.152 2033 1 19.952 9.380 94.004 68.925 0.000 182.956 50.571 5,908.723 2034 1 18.707 8.795 94.004 64.638 0.000 165.652 41.627 5,950.350 Rem 183.856 86.435 1,498.251 635.284 107.819 945.757 162.091 Total 896.285 422.067 2,966.508 3,080.510 107.819 9,409.496 6,112.441 6,112.441 Major Phase : Oil Abandonment Date : 12/08/2050 Present Worth Profile (M$) Perfs : 0 - 0 Working Int : 0.87302580 PW 5.000% : 7,347.755 Initial Rate : 6,194.375 bbl/month Revenue Int : 0.72121077 PW 8.000% : 6,540.398 Abandonment : 208.306 bbl/month Disc. Initial Invest. (M$) : 5.652 PW 9.000% : 6,317.226 Initial Decline : 49.10 % year b = 1.000 ROInvestment (disc/undisc) : 1,082.44 / 88.27 PW 10.000% : 6,112.441 Beg Ratio : 8.012 mcf/bbl Years to Payout : 0.04 PW 12.000% : 5,749.714 End Ratio : 8.657 mcf/bbl Internal ROR (%) : >1000 PW 15.000% : 5,298.636 LPC Eco DetailedNGL.rpt Page 30 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : TUBB ESTATE 21 2 - 2 Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : CRITTENDON (BRUSHY CANYON) Archive Set : L19910 Operator : IMPETRO OPERATING LLC Reservoir : Cum Oil (Mbbl) : 30.551 Based on SEC Parameters BRUSHY CANYON Co., State : Cum Gas (MMcf) : 26.050 Constant Prices & Costs Winkler, TX API : 42495302850000 Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 1.155 2.677 0.761 1.341 0.000 52.79 1.01 0.00 41.541 2021 1.094 2.536 0.721 1.270 0.000 53.57 1.01 0.00 39.918 2022 1.040 2.409 0.685 1.207 0.000 53.57 1.01 0.00 37.923 2023 0.988 2.289 0.651 1.146 0.000 53.57 1.01 0.00 36.028 2024 0.941 2.180 0.620 1.092 0.000 53.57 1.01 0.00 34.319 2025 0.820 1.900 0.540 0.952 0.000 53.57 1.01 0.00 29.903 Rem 0.000 0.000 0.000 0.000 0.000 0.00 0.00 0.00 0.000 Total 6.037 13.990 3.979 7.008 0.000 53.42 1.01 0.00 219.632 Ult 36.588 40.040 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 1.957 1.039 28.681 1.167 0.000 8.698 8.293 8.293 2021 1 1.880 0.998 28.681 1.105 0.000 7.254 6.295 14.589 2022 1 1.786 0.948 28.681 1.050 0.000 5.458 4.308 18.897 2023 1 1.697 0.901 28.681 0.997 0.000 3.752 2.694 21.591 2024 1 1.616 0.858 28.681 0.950 0.000 2.214 1.448 23.039 2025 1 1.408 0.748 26.368 0.828 110.926 -110.374 -62.784 -39.745 Rem 0.000 0.000 0.000 0.000 0.000 0.000 0.000 Total 10.346 5.491 169.772 6.097 110.926 -82.999 -39.745 -39.745 Major Phase : Oil Abandonment Date : 12/01/2025 Present Worth Profile (M$) Perfs : 8366 - 8394 Working Int : 0.89818250 PW 5.000% : -57.672 Initial Rate : 98.527 bbl/month Revenue Int : 0.65911489 PW 8.000% : -46.198 Abandonment : 72.737 bbl/month Disc. Initial Invest. (M$) : 63.115 PW 9.000% : -42.864 Initial Decline : 5.00 % year b = 0.000 ROInvestment (disc/undisc) : 0.37 / 0.25 PW 10.000% : -39.745 Beg Ratio : 2.318 mcf/bbl Years to Payout : 0.00 PW 12.000% : -34.096 End Ratio : 2.318 mcf/bbl Internal ROR (%) : 38.465 PW 15.000% : -26.895 LPC Eco DetailedNGL.rpt Page 31 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : WILD HOG BWX ST COM 1H - #1H Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : TBD Archive Set : L19910 Operator : LILIS ENERGY, INC. Reservoir : Cum Oil (Mbbl) : 163.636 Based on SEC Parameters WOLFCAMP B Co., State : Cum Gas (MMcf) : 552.724 Constant Prices & Costs LEA, NM API : 3002542733 Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 34.442 162.574 27.231 100.257 7.681 52.74 1.37 15.04 1,689.044 2021 26.371 131.608 20.850 81.161 6.218 53.57 1.37 15.04 1,321.600 2022 21.416 110.806 16.932 68.333 5.236 53.57 1.37 15.04 1,079.406 2023 18.033 95.694 14.257 59.013 4.521 53.57 1.37 15.04 912.598 2024 15.614 84.432 12.345 52.068 3.989 53.57 1.37 15.04 792.645 2025 13.702 75.176 10.833 46.360 3.552 53.57 1.37 15.04 697.267 2026 12.236 67.909 9.674 41.879 3.209 53.57 1.37 15.04 623.865 2027 11.054 61.925 8.739 38.188 2.926 53.57 1.37 15.04 564.477 2028 10.106 57.060 7.990 35.188 2.696 53.57 1.37 15.04 516.786 2029 9.262 52.638 7.323 32.461 2.487 53.57 1.37 15.04 474.141 2030 8.568 48.971 6.774 30.200 2.314 53.57 1.37 15.04 439.072 2031 7.972 45.783 6.303 28.234 2.163 53.57 1.37 15.04 408.841 2032 7.473 43.090 5.908 26.573 2.036 53.57 1.37 15.04 383.511 2033 6.995 40.391 5.530 24.909 1.908 53.57 1.37 15.04 359.073 2034 6.575 37.969 5.199 23.415 1.794 53.57 1.37 15.04 337.538 Rem 33.075 190.997 26.150 117.785 9.024 0.00 0.00 0.00 1,697.918 Total 242.895 1,307.020 192.039 806.023 61.756 53.45 1.37 15.04 12,297.782 Ult 406.531 1,859.744 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 121.902 84.452 187.596 244.154 150.000 900.939 864.592 864.592 2021 1 95.441 66.080 160.704 192.920 0.000 806.455 700.590 1,565.183 2022 1 77.995 53.970 160.704 159.966 0.000 626.771 494.864 2,060.047 2023 1 65.968 45.630 160.704 136.701 0.000 503.595 361.407 2,421.454 2024 1 57.315 39.632 160.704 119.685 0.000 415.309 270.902 2,692.355 2025 1 50.430 34.863 160.704 105.938 0.000 345.332 204.733 2,897.089 2026 1 45.130 31.193 160.704 95.254 0.000 291.584 157.149 3,054.237 2027 1 40.840 28.224 160.704 86.534 0.000 248.175 121.593 3,175.831 2028 1 37.394 25.839 160.704 79.489 0.000 213.359 95.027 3,270.858 2029 1 34.312 23.707 160.704 73.136 0.000 182.281 73.792 3,344.650 2030 1 31.778 21.954 160.704 67.891 0.000 156.746 57.688 3,402.337 2031 1 29.592 20.442 160.704 63.349 0.000 134.754 45.087 3,447.424 2032 1 27.761 19.176 160.704 59.528 0.000 116.342 35.390 3,482.814 2033 1 25.992 17.954 160.704 55.769 0.000 98.654 27.276 3,510.090 2034 1 24.433 16.877 160.704 52.425 0.000 83.099 20.890 3,530.980 Rem 122.907 84.896 1,004.208 263.713 98.200 123.994 31.278 Total 889.192 614.889 3,441.660 1,856.453 248.200 5,247.389 3,562.258 3,562.258 Major Phase : Oil Abandonment Date : 04/02/2041 Present Worth Profile (M$) Perfs : 0 - 0 Working Int : 1.00000000 PW 5.000% : 4,239.356 Initial Rate : 3,339.229 bbl/month Revenue Int : 0.79062500 PW 8.000% : 3,803.550 Abandonment : 360.986 bbl/month Disc. Initial Invest. (M$) : 152.605 PW 9.000% : 3,678.614 Initial Decline : 29.59 % year b = 1.000 ROInvestment (disc/undisc) : 24.34 / 22.14 PW 10.000% : 3,562.258 Beg Ratio : 4.552 mcf/bbl Years to Payout : 0.21 PW 12.000% : 3,352.194 End Ratio : 5.775 mcf/bbl Internal ROR (%) : >1000 PW 15.000% : 3,084.200 LPC Eco DetailedNGL.rpt Page 32 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : WILD HOG BWX ST COM 2H - 002H Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : PHANTOM Archive Set : L19910 Operator : LILIS ENERGY, INC. Reservoir : Cum Oil (Mbbl) : 115.870 Based on SEC Parameters WOLFCAMP XY Co., State : Cum Gas (MMcf) : 802.993 Constant Prices & Costs LEA, NM API : 3002544112 Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 28.077 195.094 21.935 118.885 9.109 52.71 1.37 15.04 1,456.067 2021 19.114 136.130 14.933 82.954 6.356 53.57 1.37 15.04 1,009.163 2022 14.536 104.851 11.356 63.894 4.895 53.57 1.37 15.04 769.490 2023 11.733 85.298 9.166 51.978 3.982 53.57 1.37 15.04 622.136 2024 9.863 72.088 7.706 43.929 3.366 53.57 1.37 15.04 523.593 2025 8.469 62.132 6.616 37.862 2.901 53.57 1.37 15.04 449.918 2026 7.437 54.719 5.810 33.344 2.555 53.57 1.37 15.04 395.333 2027 6.629 48.888 5.179 29.791 2.283 53.57 1.37 15.04 352.577 2028 5.996 44.298 4.684 26.994 2.068 53.57 1.37 15.04 319.008 2029 5.446 40.294 4.254 24.554 1.881 53.57 1.37 15.04 289.829 2030 5.000 37.043 3.906 22.573 1.729 53.57 1.37 15.04 266.184 2031 4.622 34.278 3.611 20.888 1.600 53.57 1.37 15.04 246.109 2032 4.308 31.982 3.366 19.489 1.493 53.57 1.37 15.04 229.457 2033 4.014 29.821 3.136 18.172 1.392 53.57 1.37 15.04 213.820 2034 3.766 27.996 2.942 17.060 1.307 53.57 1.37 15.04 200.647 Rem 12.600 93.668 9.844 57.079 4.373 0.00 0.00 0.00 671.292 Total 151.609 1,098.579 118.445 669.446 51.292 53.41 1.37 15.04 8,014.622 Ult 267.479 1,901.572 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 105.784 72.803 174.339 249.566 0.000 853.575 816.426 816.426 2021 1 73.328 50.458 107.676 172.644 0.000 605.057 526.020 1,342.446 2022 1 55.927 38.474 107.676 132.392 0.000 435.020 343.640 1,686.086 2023 1 45.224 31.107 107.676 107.415 0.000 330.715 237.428 1,923.514 2024 1 38.064 26.180 107.676 90.616 0.000 261.057 170.338 2,093.852 2025 1 32.711 22.496 107.676 77.999 0.000 209.036 123.962 2,217.814 2026 1 28.744 19.767 107.676 68.625 0.000 170.521 91.925 2,309.739 2027 1 25.636 17.629 107.676 61.266 0.000 140.370 68.791 2,378.530 2028 1 23.196 15.950 107.676 55.478 0.000 116.707 51.993 2,430.522 2029 1 21.075 14.491 107.676 50.438 0.000 96.149 38.933 2,469.455 2030 1 19.356 13.309 107.676 46.349 0.000 79.493 29.264 2,498.719 2031 1 17.897 12.305 107.676 42.874 0.000 65.356 21.874 2,520.593 2032 1 16.686 11.473 107.676 39.990 0.000 53.632 16.320 2,536.913 2033 1 15.549 10.691 107.676 37.278 0.000 42.626 11.789 2,548.702 2034 1 14.592 10.032 107.676 34.990 0.000 33.357 8.389 2,557.091 Rem 48.818 33.565 417.770 117.066 98.200 -44.126 -4.740 Total 582.588 400.731 2,099.573 1,384.985 98.200 3,448.546 2,552.351 2,552.351 Major Phase : Oil Abandonment Date : 11/17/2038 Present Worth Profile (M$) Perfs : 0 - 0 Working Int : 1.00000000 PW 5.000% : 2,929.185 Initial Rate : 2,960.162 bbl/month Revenue Int : 0.78125000 PW 8.000% : 2,689.457 Abandonment : 239.468 bbl/month Disc. Initial Invest. (M$) : 16.245 PW 9.000% : 2,618.870 Initial Decline : 44.19 % year b = 1.000 ROInvestment (disc/undisc) : 158.12 / 36.12 PW 10.000% : 2,552.351 Beg Ratio : 6.821 mcf/bbl Years to Payout : 0.10 PW 12.000% : 2,430.301 End Ratio : 7.434 mcf/bbl Internal ROR (%) : >1000 PW 15.000% : 2,270.789 LPC Eco DetailedNGL.rpt Page 33 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : WOLFE UNIT 1 - 1 Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : CRITTENDON (PENN.) Archive Set : L19910 Operator : IMPETRO OPERATING LLC Reservoir : Cum Oil (Mbbl) : 767.946 Based on SEC Parameters PENN. Co., State : Cum Gas (MMcf) : 68,002.176 Constant Prices & Costs Winkler, TX API : 4249510744 Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 0.588 195.938 0.337 85.428 7.494 52.79 1.01 12.81 200.067 2021 0.550 183.280 0.315 79.909 7.010 53.57 1.01 12.81 187.389 2022 0.516 171.924 0.296 74.958 6.575 53.57 1.01 12.81 175.778 2023 0.484 161.272 0.278 70.313 6.168 53.57 1.01 12.81 164.887 2024 0.455 151.681 0.261 66.132 5.801 53.57 1.01 12.81 155.081 2025 0.426 141.881 0.244 61.859 5.426 53.57 1.01 12.81 145.062 2026 0.399 133.091 0.229 58.027 5.090 53.57 1.01 12.81 136.074 2027 0.375 124.844 0.215 54.431 4.775 53.57 1.01 12.81 127.643 2028 0.352 117.420 0.202 51.194 4.491 53.57 1.01 12.81 120.052 2029 0.330 109.834 0.189 47.887 4.201 53.57 1.01 12.81 112.296 2030 0.309 103.029 0.177 44.920 3.940 53.57 1.01 12.81 105.339 2031 0.290 96.645 0.166 42.137 3.696 53.57 1.01 12.81 98.812 2032 0.273 90.898 0.156 39.631 3.476 53.57 1.01 12.81 92.936 2033 0.255 85.025 0.146 37.071 3.252 53.57 1.01 12.81 86.932 2034 0.239 79.757 0.137 34.774 3.050 53.57 1.01 12.81 81.545 Rem 2.339 779.804 1.342 339.990 29.824 0.00 0.00 0.00 797.287 Total 8.179 2,726.323 4.692 1,188.661 104.268 53.51 1.01 12.81 2,787.182 Ult 776.125 70,728.499 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 1 14.551 5.002 14.854 74.322 0.000 91.337 87.148 87.148 2021 1 13.623 4.685 14.854 69.521 0.000 84.706 73.473 160.621 2022 1 12.779 4.394 14.854 65.213 0.000 78.538 61.934 222.554 2023 1 11.987 4.122 14.854 61.173 0.000 72.751 52.159 274.713 2024 1 11.274 3.877 14.854 57.535 0.000 67.541 44.019 318.732 2025 1 10.546 3.627 14.854 53.818 0.000 62.218 36.861 355.593 2026 1 9.892 3.402 14.854 50.483 0.000 57.443 30.940 386.533 2027 1 9.279 3.191 14.854 47.355 0.000 52.963 25.936 412.469 2028 1 8.727 3.001 14.854 44.539 0.000 48.930 21.782 434.251 2029 1 8.164 2.807 14.854 41.662 0.000 44.810 18.133 452.384 2030 1 7.658 2.633 14.854 39.080 0.000 41.113 15.125 467.509 2031 1 7.183 2.470 14.854 36.659 0.000 37.645 12.592 480.100 2032 1 6.756 2.323 14.854 34.479 0.000 34.523 10.497 490.598 2033 1 6.320 2.173 14.854 32.251 0.000 31.333 8.660 499.258 2034 1 5.928 2.039 14.854 30.253 0.000 28.471 7.155 506.413 Rem 57.960 19.932 240.794 295.791 87.208 95.602 24.509 Total 202.627 69.680 463.608 1,034.135 87.208 929.925 530.921 530.921 Major Phase : Gas Abandonment Date : 03/19/2051 Present Worth Profile (M$) Perfs : 0 - 0 Working Int : 0.70613370 PW 5.000% : 686.118 Initial Rate : 16,819.905 mcf/month Revenue Int : 0.57367634 PW 8.000% : 584.657 Abandonment : 2,281.250 mcf/month Disc. Initial Invest. (M$) : 4.453 PW 9.000% : 556.585 Initial Decline : 6.20 % year b = 0.000 ROInvestment (disc/undisc) : 120.24 / 11.66 PW 10.000% : 530.921 Beg Ratio : 0.003 bbl/mcf Years to Payout : 0.96 PW 12.000% : 485.854 End Ratio : 0.003 bbl/mcf Internal ROR (%) : >1000 PW 15.000% : 430.896 LPC Eco DetailedNGL.rpt Page 34 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.

Date : 3/12/2020 2:23:03PM ECONOMIC PROJECTION Project Name : Lilis Energy, Inc. As Of Date : 1/1/2020 Case : WOLFE UNIT 5&6 - 5,6 Partner : All Cases Discount Rate (%) : 10.00 Reserve Cat. : Proved Producing Case Type : LEASE CASE Field : CRITTENDON (BELL CANYON) Archive Set : L19910 Operator : IMPETRO OPERATING LLC Reservoir : Cum Oil (Mbbl) : 962.695 Based on SEC Parameters BELL CANYON Co., State : Cum Gas (MMcf) : 892.568 Constant Prices & Costs Winkler, TX API : 4249532776 Cum NGL (Mbbl) : 0.000 Oil $55.69/bbl, Gas $2.58/mmbtu Gross Gross Net Net Net Oil Gas NGL Total Year Oil Gas Oil Gas NGL Price Price Price Revenue (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) ($/bbl) ($/Mcf) ($/bbl) (M$) 2020 4.182 6.140 2.513 2.805 0.246 52.78 1.01 12.81 138.632 2021 1.008 1.480 0.606 0.676 0.059 53.57 1.01 12.81 33.895 2022 0.000 0.000 0.000 0.000 0.000 0.00 0.00 0.00 0.000 2023 0.000 0.000 0.000 0.000 0.000 0.00 0.00 0.00 0.000 2024 0.000 0.000 0.000 0.000 0.000 0.00 0.00 0.00 0.000 Rem 0.000 0.000 0.000 0.000 0.000 0.00 0.00 0.00 0.000 Total 5.190 7.620 3.119 3.481 0.305 52.93 1.01 12.81 172.527 Ult 967.885 900.188 Well Net Tax Net Tax Net Net Net Non-Disc. 10.0% Ann 10.0% Cum Year Count Production AdValorem Oper. Costs Other Costs Investment Cash Flow Disc. Cash Disc. Cash (M$) (M$) (M$) (M$) (M$) (M$) Flow (M$) Flow (M$) 2020 2 6.573 3.466 116.897 2.440 0.000 9.256 8.885 8.885 2021 2 1.606 0.847 30.044 0.588 0.000 0.809 0.728 9.613 2022 0 0.000 0.000 0.000 0.000 0.000 0.000 0.000 9.613 2023 0 0.000 0.000 0.000 0.000 0.000 0.000 0.000 9.613 2024 0 0.000 0.000 0.000 0.000 88.506 -88.506 -54.959 -45.346 Rem 0.000 0.000 0.000 0.000 0.000 0.000 0.000 Total 8.179 4.313 146.941 3.028 88.506 -78.441 -45.346 -45.346 Major Phase : Oil Abandonment Date : 04/05/2021 Present Worth Profile (M$) Perfs : 0 - 0 Working Int : 0.71664785 PW 5.000% : -59.519 Initial Rate : 368.345 bbl/month Revenue Int : 0.60103904 PW 8.000% : -50.541 Abandonment : 318.065 bbl/month Disc. Initial Invest. (M$) : 54.959 PW 9.000% : -47.871 Initial Decline : 11.00 % year b = 0.000 ROInvestment (disc/undisc) : 0.17 / 0.11 PW 10.000% : -45.346 Beg Ratio : 1.468 mcf/bbl Years to Payout : 0.00 PW 12.000% : -40.694 End Ratio : 1.468 mcf/bbl Internal ROR (%) : 61.483 PW 15.000% : -34.596 LPC Eco DetailedNGL.rpt Page 35 of 35 THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. CERTIFICATE OF REGISTRATION NUMBER F-1360 LaRoche Petroleum Consultants, Ltd.