Lilis Energy
Annual Report 2017

Plain-text annual report

UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549 FORM 10-K x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2017 or ¨ TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from __________to_________ Commission file number: 001-35330 Lilis Energy, Inc.(Name of registrant as specified in its charter) Nevada 74-3231613(State or other jurisdiction ofincorporation or organization) (I.R.S. EmployerIdentification No.) 300 E. Sonterra Blvd., Suite No. 1220, San Antonio, TX 78258(Address of principal executive offices, including zip code) Registrant’s telephone number including area code: (210) 999-5400 Securities registered under Section 12(b) of the Act: Common Stock, $0.0001 par value NYSE AmericanTitle of class Name of exchange on which registered Securities registered under Section 12(g) of the 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 x Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. Yes ¨ No x 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 thepast 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 past90 days. Yes x No ¨ Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required tobe submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period thatthe registrant was required to submit and post such files). Yes x No ¨ Indicate by check mark if disclosure of delinquent filers in response to Item 405 of Regulation S-K is not contained herein, and will not be contained, to thebest of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment tothis Form 10-K. ¨ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company (asdefined in Rule 12b-2 of the Act): Large accelerated filer¨Accelerated filerxNon-accelerated filer ¨Smaller reporting companyxEmerging 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 orrevised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨ Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x As of June 30, 2017, 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 $186,032,195 based on the closing sales price of $4.90 per share of the registrant’scommon stock on June 30, 2017 on the NYSE American. As of March 5, 2018, 53,496,205 shares of the registrant’s common stock were issued and outstanding.  FORM 10-K ANNUAL REPORTYEAR ENDED DECEMBER 31, 2017LILIS ENERGY, INC. PagePART I Special Note regarding Forward Looking StatementsItems 1 and 2.Business and Properties4Item 1A.Risk Factors19Item 1B.Unresolved Staff Comments33Item 3.Legal Proceedings33Item 4.Mine Safety Disclosures33 PART II Item 5.Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities34Item 6.Selected Financial Data35Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations35Item 7A.Quantitative and Qualitative Disclosures About Market Risk50Item 8.Financial Statements and Supplementary Data50Item 9.Changes in and disagreements with Accountants on Accounting and Financial Disclosure50Item 9A.Controls and Procedures50Item 9B.Other Information51 PART III Item 10.Directors, Executive Officers and Corporate Governance51Item 11.Executive Compensation57Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters78Item 13.Certain Relationships and Related Transactions, and Director Independence83Item 14.Principal Accounting Fees and Services86 PART IV Item 15.Exhibits, Financial Statement Schedules90Item 16. Form 10-K Summary90 2  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 theSecurities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Thesestatements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materiallydifferent from any future results, performance or achievements expressed or implied by the forward-looking statements. Forward-looking statements mayinclude 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 that address activities, events or developments that weexpect or anticipate will or may occur in the future are forward-looking statements,” including, but not limited to, any projections of earnings, revenue orother financial items; any statements of the plans, strategies and objectives of management for future operations; any statements concerning futureproduction, reserves or other resource development opportunities; any projected well performance or economics, or potential joint ventures or strategicpartnerships; any statements regarding future economic conditions or performance; any statements regarding future capital-raising activities; any statementsof belief; commodity price risk management activities and the impact on our average realized price; and any statements of assumptions underlying any of theforegoing. Although we believe that the expectations, plans, and intentions reflected in or suggested by any of our forward-looking statements are reasonable,we can give no assurance that these plans, intentions, or expectations will be achieved, and the actual results could differ materially from those projected orassumed 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 thoseexpressed in our forward-looking statements include but are not limited to, the 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 Form occur, or should underlying assumptions prove incorrect, ouractual results and plans could differ materially from those in any forward-looking statements. These forward-looking statements present our estimates and assumptions only as of the date of this Annual Report. Except as required by law, wespecifically disclaim all responsibility to publicly update any information contained in any forward-looking statement and, therefore, disclaim any resultingliability for potentially related damages. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in theirentirety by this cautionary statement. For a detailed description of these and other factors that could cause actual results to differ materially from those expressed in any forward-lookingstatement, we urge you to carefully review and consider the disclosures made in the “Risk Factors” sections of our SEC filings, available free of charge at thewebsite of the Securities Exchange Commission (the “SEC”) - www.sec.gov. 3  PART I Items 1. Business and Properties Overview Lilis is an independent oil and gas company focused on the exploration, acquisition, development, and production of oil and natural gas reservesfrom properties in the Permian Basin. Our operations are focused in the Delaware Basin of the Permian in Winkler, Loving, and Reeves Counties, Texas andLea County, New Mexico. Our Business Lilis was incorporated in the State of Nevada in 2007 as “Universal Holdings, Inc.” The name of the corporation was changed to “Recovery Energy,Inc.” in October 2009 and changed to “Lilis Energy, Inc.” in December 2013. On June 23, 2016, we completed a merger transaction with Brushy Resources, Inc. (“Brushy Resources” or “Brushy”). The merger resulted in theacquisition of our initial properties in the Delaware Basin. In connection with the merger with Brushy Resources, we effected a 1-for-10 reverse stock split. Asa result of the reverse split, every ten shares of issued and outstanding common stock were automatically converted into one newly issued and outstandingshare of common stock, without any change in the par value per share; however, the number of authorized shares of common stock remained unchanged.Subsequently, on March 31, 2017, we completed the divestiture of all our oil and gas properties located in the Denver-Julesburg Basin (the “DJ Basin”),completing our transformation to a pure play Permian Basin oil and natural gas company. We intend to grow our company through generating cash flow from new production of oil, natural gas and natural gas liquids (“NGL”), as well asthrough de-risking the development profile of our portfolio of properties in order to add overall value. We believe that horizontal development of ourproperties will provide attractive returns on a majority of our acreage positions. We believe our significant inventory of oil and liquids-rich drillingopportunities in the Delaware Basin provides us with a platform for continued growth. As of December 31, 2017, we had accumulated approximately 35,200gross (15,700 net) acres that we believe to be in the core of the Delaware Basin, with approximately 33,080 gross (14,430 net) acres in Winkler, Loving, andReeves Counties, Texas and approximately 2,120 gross (1,270 net) acres in Lea County, New Mexico. Our leasehold position is largely contiguous, which webelieve gives us significant control over the pace of our development and the ability to design an efficient and profitable drilling program that maximizesrecovery of hydrocarbons. Shortly after our merger with Brushy Resources, we commenced a development program to delineate and de-risk our properties by drilling of newhorizontal wells across multiple potentially productive formations. Our drilling program utilizes the development of new horizontal wells across severalpotentially productive formations in the Delaware Basin. We commenced our drilling program in 2016, when we drilled two wells, which were completed in2017. In 2017, we drilled eight wells on our leases and completed five of these wellbores, which targeted the Wolfcamp formation for initial development. As a result of our development activity, our proved reserves increased to approximately 11,453 MBOE (million barrels of oil equivalent) as ofDecember 31, 2017. Our proved reserves as of that date consisted of 63% oil, 23% natural gas and 14% NGL. Of those reserves, 37% of our proved reservesare classified as proved developed and approximately 63% are classified as proved undeveloped. In addition, 34% of our net acreage position was held by production, and we operated approximately 90% of our acreage, which we believe gives ussignificant control over the pace of our development and the ability to design a more efficient and profitable drilling program to maximize recovery of oiland natural gas. In 2017, we also entered into a long-term gas gathering, processing and purchase agreement with an affiliate of Lucid Energy Group (“Lucid”) tosupport our active drilling program in the Delaware Basin. Lucid will receive, gather and process our gas production from certain production areas located inLea County, New Mexico and Winkler and Loving Counties, Texas. The agreement secures sufficient term and capacity for Lilis during our development andexploitation life cycle of the production areas committed to the new agreement. We expect that substantially all of our estimated 2018 capital expenditure budget will be focused on the development and expansion of ourDelaware Basin acreage and operations in order to further delineate the prospectivity of Wolfcamp and Bone Spring development on our properties. We alsoplan to continue selectively and opportunistically pursuing strategic acreage acquisitions and organic leasing prospects in the Delaware Basin. 4  Our Business Strategy Our business objective is to increase stockholder value by growing our leasehold position, reserves, production and cash flows at attractive rates ofreturn on invested capital. We continue to focus on developing our existing acreage position, gaining additional operational control and expanding our coreassets in the Delaware Basin. We plan to achieve our business objective by implementing a business strategy focused on the following: ·Execute our Operated, Horizontal Drilling Program to Grow Production from our Delaware Basin Leasehold. We plan to drill and develop ourexisting acreage base of approximately 35,800 gross (16,200 net) acres in the Delaware Basin, which we believe will maximize our resourcepotential and value to our stockholders. Through the development of our properties, we seek to de-risk our acreage position and substantiallyincrease our production and cash flow, thereby increasing the value of our properties. Our current leasehold position in the Delaware Basin hassignificant stacked-pay potential, which we believe includes at least seven productive zones. We estimate that all productive zones within ourproperties may support approximately 900 future drilling locations, including over 400 longer lateral locations, and we expect that inventory toincrease with the closing of our pending acquisition from OneEnergy Partners Operating, LLC. We focused our horizontal development in 2017 onthe Wolfcamp B formation but intend to expand our target zones to the Wolfcamp A, Wolfcamp XY and 2nd Bone Spring during 2018. Our long-term gas gathering, processing and purchase agreement with Lucid will support our active drilling program and alleviate production constraints wehave experienced. ·Focus on Delineation of our Existing Acreage. We plan to focus on the delineation and de-risking of our existing acreage. We expect that ourdrilling activity will also grow our drilling inventory and the identified resource potential of our Delaware Basin properties. We believe that ourcurrent reserves represent only a small portion of the resource potential within our acreage. Our development plan for 2018 contemplates thecontinued delineation of our acreage both geographically and geologically by testing our eastern acreage and by drilling and completing wellswithin additional prospective benches, including the Wolfcamp A, Wolfcamp XY and the 2nd Bone Spring. ·Leverage our Extensive Operational Expertise to Reduce Costs and Enhance Returns. As of December 31, 2017, we operated approximately 90%of our acreage position, giving us significant control over the pace of our development and allowing us to increase value through operational andcost efficiencies. We intend to obtain the highest possible returns on the capital we expend on our development projects using results from the wellswe have completed and the operational expertise of our management team. We also plan to focus on operational efficiencies, including salt waterdisposal and midstream costs, and capital costs of our development wells in order to maximize returns to our stockholders. ·Pursue Selective Acquisitions and Organic Leasing to Grow Our Leasehold Position. Since entering the Delaware Basin in June 2016, we havegrown our net acreage position approximately 376% from 3,400 net (7,200 gross) acres to approximately 16,200 net (35,800 gross) acres at March 1,2018. On January 30, 2018, we announced our entry into a pending Purchase and Sale Agreement with OneEnergy Partners Operating, LLC toacquire 2,798 net acres in New Mexico, which are largely overlapping or contiguous with our existing properties, for approximately $70 million (the“OEP Acquisition”). Pro forma for the closing of the OEP Acquisition, we expect our acreage position to approximate 19,000 net acres. Our mostsignificant acquisition in 2017 included approximately 4,400 net acres, approximately 92% of which overlapped our existing acreage position. Ouracquisitions to date have added approximately 600 drilling locations with multiple stacked pay zones. In addition to our continued evaluation ofstrategic acquisition opportunities in the Delaware Basin, we will continue to expand our leasehold position through our organic leasing program. ·Maintain Fiscal Discipline and Financial Liquidity. We actively manage the level of our development, leasing and acquisition activity in responseto commodity prices, access to capital, and to the performance of our wells. We hold significant control over the pace of our drilling activity as aresult of our operatorship on approximately 90% of our properties. During 2017, we commenced an active hedging program to provide certaintyregarding our cash flow and protect returns from our development activity in the event of decreases in the prices received for our production. Inaddition, we have structured our balance sheet with the intent to reduce our leverage profile over time. The Second Lien Term Loan (as definedbelow) that we primarily relied upon to finance our capital spending and operations in 2017 is convertible, and we announced the issuance of $100million in convertible, perpetual Series C preferred stock on January 31, 2018. In addition, the closing of our recently announced OEP Acquisition,which carries a purchase price of approximately $70 million, will be funded in part with $30 million of common stock to be issued to the seller. Our Strengths ·Pure Play Permian Focus with Established Acreage Position in the Core of the Delaware Basin. We believe we have assembled a substantialportfolio of Delaware Basin properties that offers significant exploration and low-risk development opportunities, including one of the highest ratesof return among formations in North America. As of March 1, 2018, we hold over 35,800 gross (16,200 net) acres in the core of the Delaware Basin,with an average working interest per well of approximately 66%. In addition, 35% of our acreage position is held by production, and we operateapproximately 90% of our acreage, which we believe gives us significant control over the pace of development and the ability to design a moreefficient and profitable drilling program to maximize recovery of oil and natural gas. Based on our drilling and production results to date and well-established offset operator activity in and around our project areas, we believe there are relatively low geologic risks and ample repeatable drillingopportunities across our core acreage. ·Multi-year Portfolio of Drilling and Development Opportunities. We have a significant inventory of drilling and development locations in Winkler,Loving and Reeves Counties, Texas and Lea County, New Mexico. We believe our properties form part of the core of the Delaware Basin. Based onour drilling to date and results from nearby wells, we have identified more than 900 horizontal well locations on our acreage, includingapproximately 400 longer lateral locations, exclusive of the acreage to be acquired pursuant to the pending OEP Acquisition. We believe thatinventory of drilling locations will allow us to grow our reserves and production at attractive rates of return based on current expectations forcommodity prices. 5  ·Contiguous Acreage Position Provides Operating Leverage and Consolidation Opportunities. Our geographically-concentrated acreage positionallows us to capitalize on economies of scale with respect to drilling and production costs. Our leasehold position is highly contiguous, and we heldoperatorship on approximately 90% of our properties at December 31, 2017, enabling us to maximize our development efficiency and manage ourcosts. In addition, we believe those efficiencies provide us with an advantage in competing for acquisitions and organic leasing opportunities onand around our acreage. On January 31, 2018, we announced our pending OEP Acquisition, pursuant to which we expect to acquire 2,798 net acrescomprised of working interests that overlap or are contiguous to our existing properties in Lea County, New Mexico. We expect that we willcontinue to see opportunities for accretive acquisitions where we may benefit from current and potential economies of scale going forward. ·Strong Financial Position and Liquidity. We believe our financial position is strong and provides the financial flexibility to fund our currentlyplanned 2018 capital expenditures. On January 31, 2018, we announced our entry into a new $50 million, three-year term loan with RiverstoneCredit Partners, LLC, that refinanced our existing first-lien bridge loan and provided approximately $18 million in net proceeds, and the concurrentissuance of $100 million in convertible, perpetual Series C preferred stock to Varde Partners, Inc. We expect to use $40 million in proceeds from thepreferred stock issuance to fund the closing of the OEP Acquisition and to use remaining net proceeds from both financings to fund our planned2018 capital expenditures. The remainder of the $70 million purchase price for the OEP Acquisition will be funded from the issuance of commonstock to the sellers. We believe this financial liquidity and flexibility will result in continued growth in our oil and natural gas production, provedreserves, and cash flows. ·Experienced Management Team. We have an experienced and skilled management team with a long track record of driving growth through assetdevelopment and strategic acquisitions. Our management team holds 105 years of collective experience in the oil and gas industry, with asignificant amount of such experience being in the Permian Basin. We believe that our team’s experience through various commodity price cyclesand operational expertise position us to operate effectively and efficiently and will help us to increase our returns and value to our stockholders. Business Segments Our operations are all oil and natural gas exploration and production related activities in the United States. Summary of Oil and Natural Gas Properties and Projects We are engaged in oil and natural gas acquisition, exploration, development and production, with all of our oil and natural gas properties beinglocated in the Delaware Basin in Winkler, Loving, and Reeves Counties, Texas and Lea County, New Mexico. As of December 31, 2017, we owned leasehold in approximately 35,200 gross (15,700 net) acres in the Delaware Basin, comprised of approximately14,430 net acres in Winkler, Loving, and Reeves Counties, Texas and approximately 1,270 net acres in Lea County, New Mexico. Of these properties, approximately 8,300 gross (5,300 net) acres were classified as developed and held by production and the remainingapproximately 26,900 gross (10,400 net) acres we classified as undeveloped. We currently estimate our properties include at least seven productive zones andhold approximately 900 future drilling locations across all of the productive zones within this position. Our reserve estimates include 20 horizontal PUDwells, as well as the capital costs required to develop these wells. Reserve Data Reserve Estimates Our reserve data and estimates were compiled and prepared internally and audited by third party independent consultants, Cawley, Gillespie &Associates, Inc. (“CG&A”), as described in more detail herein, in compliance with SEC definitions and guidance and in accordance with generally acceptedpetroleum 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 gas reservequantities and values in compliance with the regulations of the SEC. Responsibility for compliance in reserve bookings is delegated to our Chief FinancialOfficer with assistance from our senior geologist and a senior reservoir engineer. We have a Reserves Committee to provide additional oversight of ourreserves estimation and certification process. The members of the Reserves Committee currently consist of Ron Ormand, our Executive Chairman, and GlennDawson, a member of our Board of Directors. Mr. Dawson serves as the Chairman of the Reserves Committee. 6  Technical reviews are performed throughout the year by our senior reservoir engineer and our senior geologist and other consultants who evaluateall available geological and engineering data, under the guidance of our appropriate executive officer(s). This data, in conjunction with economic data andownership information, is used in making a determination of estimated proved reserve quantities. The 2017 and 2016 reserve processes were overseen byChris Cantrell, our senior reservoir engineer. Mr. Cantrell holds a Bachelor of Science degree in Petroleum Engineering conferred by Texas A&M Universityin 1995. He is a registered professional engineer licensed in the State of Texas, license number 90521. He has been continuously involved in evaluating oiland gas properties since 1997 and is a member of the Society of Petroleum Engineers and the American Petroleum Institute. Third-party Reserves Study Our independent third-party consultant, CG&A, performed reserve studies as of December 31, 2017 and 2016, using its own engineeringassumptions and other economic data provided by us. All of our total calculated proved reserve value was audited by CG&A. CG&A is an independentpetroleum engineering consulting firm that has been providing petroleum engineering consulting services for over 20 years. The individual at CG&Aprimarily responsible for overseeing our reserve audit is Todd Brooker, President of CG&A, who received a Bachelor of Science degree in PetroleumEngineering from the University of Texas and is a registered Professional Engineer in the State of Texas. He is also a member of the Society of PetroleumEngineers. Mr. Brooker and the other technical persons employed by CG&A engaged in the reserve study met the requirements regarding qualifications,independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Natural Gas ReservesInformation promulgated by the Society of Petroleum Engineer. 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 asprescribed by the SEC and Financial Accounting Standards Board (“FASB”) guidelines. Reserve calculations involve the estimate of future net recoverablereserves 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 onassumptions regarding a variety of factors, many of which are variable and uncertain. Proved reserves were estimated in accordance with guidelinesestablished by the SEC and the FASB, which require that reserve estimates be prepared under existing economic and operating conditions with no provisionfor price and cost escalations except by contractual arrangements. For the years ended December 31, 2017 and 2016, we based the estimated discountedfuture net cash flows from proved reserves on the 12-month average oil and natural gas index prices, calculated as the un-weighted arithmetic average for thefirst-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 theproperties. In addition to a third-party reserve study, our reserves and the corresponding report, along with the process for developing such estimates, arereviewed by our geologist and the Audit Committee of our Board of Directors to ensure compliance with SEC disclosure and internal control requirementsand to verify the independence of the third-party consultants. The Audit Committee of our Board of Directors reviews the final reserves estimate inconjunction with CG&A’s audit letter. Actual quantities of reserves recovered will most likely vary from the estimates set forth below. Reserves and cash flow estimates rely oninterpretations of data and require assumptions that may be inaccurate. For a discussion of these interpretations and assumptions, see " Any significantinaccuracies in these reserves estimates or underlying assumptions will materially affect the quantities and present value of our reserves” under Item 1A,"Risk Factors," of this Annual Report. See "Supplementary Information on Oil and Natural Gas Exploration, Development and Production Activities" to ourconsolidated financial statements in Item 15 of this Annual Report for additional reserves disclosures. Estimates of Proved Reserves The table below summarizes our estimates of proved reserves at December 31, 2017. Oil(MBbl) Natural Gas(MMcf) NGLs (MBbl) Total(MBOE) Proved Developed Reserves 2,531 6,594 645 4,275 Proved Undeveloped Reserves 4,640 9,466 960 7,178 Total Proved Reserves 7,171 16,060 1,605 11,453 7  Total Proved Reserves Our estimates of proved reserves and related standardized measure of future net cash flows and PV-10 as of December 31, 2017 are calculated basedupon SEC pricing, which uses a twelve-month unweighted average of first-day-of-the-month oil and natural gas benchmark prices, adjusted for marketing andother differentials and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. SEC pricing forcrude oil, natural gas and NGLs has been volatile since December 2014, and any future changes in oil and natural gas pricing will impact future estimatedproved reserve volumes. Our year-end 2017 proved reserves of 11,453 MBOE consisted of 4,275 MBOE proved developed, and 7,178 MBOE proved undeveloped reserves.For 2017, crude oil reserves increased to 6,620 MBbls to 7,131 MBbls from 551 MBbls at December 31, 2016, while NGL reserves increased to 1,605 MBblsfrom 3 MBbls at December 31, 2016. At December 31, 2017, our proved natural gas reserves increased 12,188 MMcf to 16,060 Mcf from 3,872 MMcf atDecember 31, 2016. At year-end 2017, all our proved reserves were located in the Delaware Basin. At December 31, 2017, the SEC pricing for oil was $51.34 per barrel, a 20% increase compared to the prior year end price of $42.75 per barrel, andpricing for natural gas was $2.98 per MMBtu, a 21% increase compared to the prior year end price of $2.46 per MMBtu. Our total proved reserves increasedby 10,253 MBOE; 10,654 MBOE in extensions, discoveries and other additions and 331 MBOE in revisions offset by a 732 MBOE reduction in provedreserves from production and the sale of reserves in 2017. Proved Undeveloped Reserves During 2017, we added 7,178 MBOE of proved undeveloped (“PUD”) reserves through the extension of proved acreage, primarily as a result ofsuccessful drilling on properties in the core of the Delaware Basin in Winkler, Loving, and Reeves Counties, Texas and Lea County, New Mexico. Estimates of proved undeveloped reserve quantities are limited by development drilling activity that we intend to undertake during the 2018 to2022 timeframe. For additional information regarding the changes in our proved reserves, see our "Supplementary Information on Oil and Natural GasExploration, Development and Production Activities" to our consolidated financial statements in Item 15 of this Annual Report. Production History The following table summarizes the average volumes and realized prices of oil and natural gas produced from properties during the periodsindicated, and production cost per BOE: For the Years Ended December 31, 2017 2016Product Oil (Bbls)-net production 371,993 61,088 Oil (Bbls)-average realized price $47.92 $39.59 Natural Gas (MCF)-production 776,164 332,643 Natural Gas (MCF)-average realized price $2.74 $2.54 Natural gas liquids (Bbls)-net production 73,875 11,355 Natural gas liquids (Bbls)-average realized price $22.49 $15.22 Barrels of oil equivalent (BOE) 575,229 127,863 Average daily net production (BOE) 1,576 350 Average Price per BOE $37.57 $26.87 8  Oil and Natural Gas Production Costs, Production Taxes, Depreciation, Depletion, and Amortization For the Years Ended December 31, 2017 2016Production costs per BOE $12.21 $12.43 Production taxes per BOE 2.06 (1.30)Depreciation, depletion, and amortization per BOE 12.21 12.25 Total operating costs per BOE $26.48 $23.38 The average oil and NGL sales prices above are calculated by dividing revenue from oil sales by volume of oil sold, in barrels “Bbl.” The averagenatural gas sales prices above are calculated by dividing revenue from natural gas sales by the volume of natural gas sold, in thousand cubic feet “Mcf.” Thetotal average sales price amounts are calculated by dividing total revenues by total volume sold, in BOE. The average production costs above are calculatedby dividing production costs by total production in BOE. Acreage The following table sets forth our approximate gross and net developed and undeveloped acreage as of December 31, 2017: Undeveloped Acreage Developed Acreage Total Gross Net Gross Net Gross Net Delaware Basin 26,900 10,400 8,300 5,300 35,200 15,700 Productive Wells As of December 31, 2017, we have had 13 gross (10.4 net) oil wells and 10 gross (6.6 net) natural gas wells. A net well is our percentage ownershipinterest of a gross well. Productive wells are either wells producing in commercial quantities or wells capable of commercial production, but are currently shut-in. Multiplecompletions 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 onthe ratio of natural gas to oil produced when it first commenced production, and such designation may not be indicative of current production. Drilling Activity Exploratory Wells During 2017, we drilled 8 gross (6.7 net) horizontal exploratory wells in the Delaware Basin. We completed and placed on production 5 gross (4.1net) horizontal exploratory wells, leaving 3 gross (2.6 net) horizontal exploratory wells drilled but not yet completed as of December 31, 2017. All of thesewells were successful and none were a dry hole. During 2016, we drilled 2 gross (1.6 net) horizontal exploratory wells in Texas. These wells were drilled but not yet completed. These wells weresuccessful and placed on production during the first quarter of 2017. 9  Year Ended December 31, 2017 2016 Gross Net Gross Net Exploratory: Productive 5.00 4.10 — — Dry — — — — Total: Productive 5.00 4.10 — — Dry — — — As of December 31, 2017, we had 3 gross (2.6 net) wells in the process of drilling, completing or dewatering or shut in awaiting infrastructure that arenot reflected in the above table. At December 31, 2016, we had 2 gross (1.6 net) wells in the process of drilling, completing or dewatering or shut in awaitinginfrastructure that are not reflected in the above table that were placed on production during the first quarter of 2017. Present Activities Subsequent to December 31, 2017 and through March 1, 2018, we drilled or were in the process of drilling 6 gross (5.1 net) horizontal wells andcompleted or were in the process of completing 4 gross (3.6 net) horizontal wells and had 5 gross (4.1 net) horizontal wells awaiting completion. Title to Properties We generally conduct a preliminary title examination prior to the acquisition of properties or leasehold interests. Prior to commencement ofoperations on such acreage, a thorough title examination will usually be conducted and any significant defects will be remedied before proceeding withoperations. We believe the title to our leasehold properties is good, defensible and customary with practices in the oil and natural gas industry, subject tosuch exceptions that we believe do not materially detract from the use of such properties. Our properties are potentially subject to one or more of thefollowing: ·royalties and other burdens and obligations under oil and natural gas leases, purchase agreements and leasehold assignments;·overriding royalties and other burdens created by us or our predecessors in title;·contractual obligations arising under operating agreements, farm-out agreements, production sales contracts and other agreements that may affectthe properties or their titles;·liens that arise in the normal course of operations, including those for unpaid taxes, statutory liens securing obligations to unpaid suppliers andcontractors and contractual liens under operating agreements; and·easements, restrictions, rights-of-way and other matters that commonly affect property. Additionally, the majority of our Delaware Basin leasehold position is subject to mortgages securing indebtedness under our credit and guaranteeagreement. With respect to our properties of which we are not the record owner, we rely instead on contracts with the owner or operator of the property orassignment 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 gas industry is intensely competitive, particularly with respect to acquiring prospective oil and natural gas properties. We believe ourleasehold position provides a solid foundation for an economically robust exploration program and our future growth. Our success and growth also dependon our geological, geophysical, and engineering expertise, design and planning, and our financial resources. We believe the location of our acreage, ourtechnical expertise, available technologies, our financial resources and expertise, and the experience and knowledge of our management enables us tocompete effectively in our core operating areas. However, we face intense competition from a substantial number of major and independent oil and gascompanies, which have larger technical staffs and greater financial and operational resources. We also compete with other oil and gas companies in attempting to secure drilling rigs and other equipment and services necessary for the drilling,completion, production, processing and maintenance of wells. Consequently, we may face shortages or delays in securing these services from time to time.The oil and 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. 10  In addition, we compete for people, including experienced geologists, geophysicists, engineers, and other professionals and consultants.Throughout the oil and gas industry, the need to attract and retain talented people has grown at a time when the number of talented people available isconstrained. We are not insulated from this resource constraint, and we must compete effectively in this market in order to be successful. Marketing and Pricing We derive 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, byprevailing 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 forwarddelivery contracts. The market price for oil, natural gas and NGLs is dictated by supply and demand, and we cannot accurately predict or control the price wemay receive for our oil and natural gas. Our revenues, cash flows, profitability and future rate of growth will depend substantially upon prevailing prices for oil, natural gas and NGLs. Pricesmay also affect the amount of cash flow available for capital expenditures and other cash requirements and our ability to borrow money or raise additionalcapital. Lower prices may also adversely affect the value of our reserves and make it uneconomical for us to commence or continue production levels ofnatural gas and crude oil. Historically, the prices received for oil, natural gas and NGLs have fluctuated widely. Furthermore, regional natural gas, condensate, oil and NGL prices may move independently of broad industry price trends. Because some of ouroperations are located outside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTI or other major market pricing. From time to time, we may enter into derivative contracts. These contracts economically hedge our exposure to decreases in the prices of oil andnatural gas. Hedging arrangements may expose us to risk of significant financial loss in some circumstances. In addition, hedging arrangements may limit thebenefit we would receive from increases in the prices for oil and natural gas. Major Customers Our major customers for the year ended December 31, 2017 include Texican Crude & Hydrocarbons, LLC and ETC Field Services LLC, whoaccounted for approximately 85% and 14% of our revenue for the year ended December 31, 2017, respectively. Our major customers for the year endedDecember 31, 2016 included Noble Energy, Inc., Texican Crude & Hydrocarbons, LLC and Energy Transfer Partners, L.P., who accounted for approximately41%, 38%, and 16% of our revenue for the year ended December 31, 2016, respectively. Delivery Commitments As of December 31, 2017, we were not committed to providing a fixed quantity of oil or natural gas under any existing contracts. Regulation of the Oil and Natural Gas Industry General. Our operations covering the exploration, production and sale of oil and natural gas are subject to various types of federal, state and locallaws and regulations. The failure to comply with these laws and regulations can result in substantial penalties. These laws and regulations materially impactour operations and can affect our profitability. However, we do not believe that these laws and regulations affect us in a manner significantly different thanour competitors. Matters regulated include, but are not limited to, permits for drilling operations, drilling and abandonment bonds, reports concerningoperations, the spacing of wells and unitization and pooling of properties, restoration of surface areas, plugging and abandonment of wells, requirements forthe operation of wells, production and processing facilities, land use, subsurface injection, air emissions, the disposal of fluids used or other wastes obtainedin connection with operations, the valuation and payment of royalties and taxation of production. At various times, regulatory agencies have imposed pricecontrols and limitations on production. In order to conserve supplies of oil and natural gas, these agencies have restricted the rates of flow of oil and naturalgas wells below actual production capacity, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding production.Federal, state and local laws regulate production, handling, storage, transportation and disposal of oil and natural gas, by-products from oil and natural gasand other substances and materials produced or used in connection with oil and natural gas operations. While we believe that we will be able to substantiallycomply with all applicable laws and regulations through our strict attention to regulatory compliance, the requirements of such laws and regulations arefrequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings thataffect the oil and natural gas industry are regularly considered by Congress, the states, Federal Energy Regulatory Commission (the "FERC") and the courts.We cannot predict when or whether any such proposals may become effective. We do not believe that we would be affected by any such action materiallydifferently than similarly situated competitors. 11  Regulation of Production of Oil and Natural Gas. The production of oil and natural gas is subject to regulation under a wide range of local, stateand federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds andreports concerning operations. We own interests in properties located in Texas, which regulates drilling and operating activities by requiring, among otherthings, permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the methodof drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The lawsof Texas also govern a number of conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishmentof 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 thelocations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing or density. Moreover, Texasimposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. The failure to comply with these rules and regulationscan result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions thataffect our operations. Environmental, Health, and Safety Regulations. Our operations are subject to stringent federal, state, and local laws and regulations relating to theprotection of the environment and human health and safety (“EHS”). We are committed to strict compliance with these regulations and the utmost attentionto EHS issues. Environmental laws and regulations may require that permits be obtained before drilling commences or facilities are commissioned, restrict thetypes, 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. As a result, these laws and regulations maysubstantially increase the costs of exploring for, developing, or producing oil and natural gas and may prevent or delay the commencement or continuationof certain projects. In addition, these laws and regulations may impose substantial clean-up, remediation, and other obligations in the event of any dischargesor emissions in violation of these laws and regulations. Further, legislative and regulatory initiatives related to global warming or climate change could havean adverse effect on our operations and the demand for oil and natural gas. See “Risk Factors-Risks Relating to the Oil and Gas Industry-Legislative andregulatory 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 following is a summary of the more significant existing and proposed environmental and occupational health and safety laws and regulations to whichour business operations are or may be subject and for which compliance may have a material adverse impact on our capital expenditures, results of operationsor financial position. During the years ended December 31, 2017 and 2016, we incurred approximately $32,000 and approximately $182,000, respectively,related to compliance with environmental laws for our oil and natural gas properties. The Resource Conservation and Recovery Act The Resource Conservation and Recovery Act of 1976, 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, andliability 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 ahazardous waste treatment, storage or disposal facility. At present, the RCRA includes an exemption that allows certain oil and natural gas exploration andproduction waste to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. As a result, we are notrequired to comply with a substantial portion of RCRA’s hazardous waste requirements. At various times in the past, proposals have been made to amend theRCRA to rescind the exemption that excludes oil and natural gas exploration and production wastes from regulation as hazardous waste. For example, in2010, a petition was filed by the Natural Resources Defense Council (“NRDC”) with the Environmental Protection Agency (“EPA”) requesting that theagency reassess its prior determination that certain exploration and production wastes are not subject to the RCRA hazardous waste requirements. The EPAhas not yet acted on the petition. On May 5, 2016, moreover, the NRDC, along with other environmental organizations, commenced a lawsuit against theEPA, asking the U.S. District Court for the District of Columbia to order the agency to “revise” its RCRA regulations as they pertain to oil and gas wastes. OnDecember 28, 2016, the court signed a consent decree, resolving the lawsuit, under which the EPA agreed that, by March 15, 2019, it will either sign a noticeof proposed rulemaking for a revision of its RCRA regulations as they pertain to oil and gas wastes (in which case it will take a final action on the proposedrulemaking by July 15, 2021) or sign a determination that no such revision is necessary. Repeal or modification of the RCRA oil and gas exemption byadministrative, legislative or judicial process, or modification of similar exemptions in applicable state statutes, would increase the volume of hazardouswaste we are required to manage and dispose of and would cause us to incur, perhaps significantly, increased operating expenses. 12  Water Discharges The Federal Water Pollution Control Act, also known as the Clean Water Act (the “Clean Water Act”) imposes restrictions and controls on thedischarge of produced waters and other oil and natural gas wastes into navigable waters. Permits must be obtained to discharge pollutants into state andfederal waters and to discharge fill and pollutants into regulated waters and wetlands. Uncertainty regarding regulatory jurisdiction over wetlands and otherregulated waters of the United States has complicated, and will continue to complicate and increase the cost of, obtaining such permits or other approvals.Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge ofproduced waters and sand, drilling fluids, drill cuttings and certain other substances related to the crude oil and natural gas industry into certain coastal andoffshore waters. Further, the EPA has adopted regulations requiring certain crude oil and natural gas exploration and production facilities to obtain permitsfor storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution preventionplans. 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 orleak. The EPA and U.S. Army Corps of Engineers released a Connectivity Report in September 2013, which determined that virtually all tributary streams,wetlands, open water in floodplains and riparian areas are connected. This report supported the drafting of proposed rules providing updated standards forwhat will be considered jurisdictional waters of the United States. Those rules were finalized on May 27, 2015. Then, on October 9, 2015, in presiding over achallenge to the rules, the U.S. Court of Appeals for the Sixth Circuit stayed them, nationwide. It later determined (in February of 2016) that it has jurisdictionto adjudicate the challenge. In January of 2017, the U.S. Supreme Court accepted an appeal of that determination. In the meantime, the Sixth Circuit’s stay ofthe rules remains in place. On February 28, 2017, moreover, President Trump directed the EPA to review the rules and “publish for notice and comment aproposed 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 thosedischarges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. Webelieve that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution. The Oil Pollution Act of 1990 (“OPA”) and regulations thereunder impose a variety of regulations on “responsible parties” related to the preventionof oil spills and liability for damages resulting from such spills in United States waters. The OPA assigns strict liability to each responsible party for oilremoval costs and a variety of public and private damages, including natural resource damages. While liability limits apply in some circumstances, a partycannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of federal safety,construction or operating regulations. Few defenses exist to the liability imposed by the OPA. In addition, to the extent we acquire offshore leases and thoseoperations affect state waters, we may be subject to additional state and local clean-up requirements or incur liability under state and local laws. The OPAalso imposes ongoing requirements on responsible parties, including proof of financial responsibility to cover at least some costs in a potential spill. Wecannot predict whether the financial responsibility requirements under the OPA amendments will adversely restrict our proposed operations or imposesubstantial additional annual costs to us or otherwise materially adversely affect us. The impact, however, should not be any more adverse to us than it will beto other similarly situated owners or operators. Safe Drinking Water Act The Safe Drinking Water Act of 1974, as amended, establishes a regulatory framework for the underground injection of a variety of wastes, includingbrine produced and separated from crude oil and natural gas production, with the main goal being the protection of usable aquifers. The primary objective ofinjection well operating permits and requirements is to ensure the mechanical integrity of the wellbore and to prevent migration of fluids from the injectionzone into underground sources of drinking water. Class II underground injection wells, a predominant storage method for crude oil and natural gaswastewater, are strictly controlled, and certain wastes, absent an exemption, cannot be injected into such wells. Failure to abide by our permits could subjectus to civil or criminal enforcement. We believe that we are in compliance in all material respects with the requirements of applicable state undergroundinjection control programs and our permits. In Texas, the Texas Railroad Commission (“RRC”) regulates the disposal of produced water by injection well.The RRC requires operators to obtain a permit from the agency for the operation of saltwater disposal wells and establishes minimum standards for injectionwell operations. In response to recent seismic events near underground injection wells used for the disposal of oil and gas-related wastewaters, federal andsome state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or imposedmoratoria on the use of such injection wells. In response to these concerns, regulators in some states are considering additional requirements related toseismic safety. For example, the RRC has adopted new permit rules for injection wells to address these seismic activity concerns within the state. Amongother things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequentmonitoring and reporting for certain wells, and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, ordetermined to be, causing seismic activity. These new 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 producedwater disposal, may reduce our profitability; however, these costs are commonly incurred by all oil and gas producers and we do not believe that the costsassociated with the disposal of produced water will have a material adverse effect on our operations. 13  Air Pollutant Emissions The federal Clean Air Act (the “Clean Air Act”) and comparable state and local air pollution laws adopted to fulfill its mandate provide a frameworkfor national, state and local efforts to protect air quality. Our operations utilize equipment that emits air pollutants which may be subject to federal and stateair pollution control laws. These laws generally require utilization of air emissions control equipment to achieve prescribed emissions limitations andambient air quality standards, as well as operating permits for existing equipment and construction permits for new and modified equipment. We believe thatwe are in compliance in all material respects with the requirements of applicable federal and state air pollution control laws. Over the next several years, wemay be required to incur capital expenditures for air pollution control equipment or other air emissions-related issues. The EPA promulgated significant NewSource Performance Standards (“NSPS OOOO”) in 2012, as amended in 2013 and 2014, which have added administrative and operational costs. On October 1, 2015, under the Clean Air Act, the EPA lowered the national ambient air quality standard for ozone from 75 ppb to 70 ppb. Thischange could result in an expansion of ozone nonattainment areas across the United States, including areas in which we operate. Oil and natural gasoperations in ozone nonattainment areas would likely be subject to increased regulatory burdens in the form of more stringent emission controls, emissionoffset requirements, and increased permitting delays and costs. Regulation of “Greenhouse Gas” Emissions In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public healthand the environment, the EPA, under the Clean Air Act, 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. Facilities required to comply withPSD requirements for their GHG emissions will be required to meet “best available control technology” standards for those emissions, which will beestablished on a case-by-case basis. EPA rulemakings related to GHG emissions could adversely affect our operations and restrict or delay our ability toobtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions fromspecified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include certain of our operations. While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form ofadopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state andregional cap and trade programs have emerged that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrenderemission allowances in return for emitting GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted toaddress GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGsfrom, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. In addition, substantiallimitations on GHG emissions could adversely affect demand for the oil and natural gas we produce. Finally, it should be noted that some scientists haveconcluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such asincreased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on ourexploration and production operations. Hydraulic Fracturing Activities Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tightunconventional formations. For additional information about hydraulic fracturing and related regulatory matters, see “Risk Factors-Risks Relating to the Oiland Gas Industry.” Federal and state legislation and regulatory initiatives related to hydraulic fracturing could result in increased costs and additionaloperating restrictions or delays /cancellations in the completion of oil and gas wells. Federal and state occupational safety and health laws require us to organize and maintain information about hazardous materials used, released, orproduced in our operations. Some of this information must be provided to our employees, state and local governmental authorities, and local citizens. We arealso subject to the requirements and reporting framework set forth in the federal workplace standards. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to the government and third parties and mayrequire us to incur costs to remedy discharges. Natural gas, oil or other pollutants, including salt water brine, may be discharged in many ways, includingfrom a well or drilling equipment at a drill site, leakage from pipelines or other gathering and transportation facilities, leakage from storage tanks and suddendischarges from damage or explosion at natural gas facilities of oil and gas wells. Discharged hydrocarbons may migrate through soil to fresh water aquifersor adjoining property, giving rise to additional liabilities. 14  Several states, including Texas, and local jurisdictions have adopted, or are considering adopting, regulations that could restrict or prohibithydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulicfracturing fluids. For example, the Texas Legislature adopted legislation, effective September 1, 2011, requiring oil and gas operators to publicly disclose thechemicals used in the hydraulic fracturing process. The RRC adopted rules and regulations implementing this legislation that apply to all wells for which theRRC issues an initial drilling permit after February 1, 2012. The law requires that the well operator disclose the list of chemical ingredients subject to therequirements 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 volumeof water used to hydraulically fracture a well must also be disclosed to the public and filed with the RRC. Further, in May 2013, the RRC adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturingoperations 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 orhydraulic fracturing in particular. In addition, the Texas Legislature adopted new legislation requiring oil and gas operators to publicly disclose thechemicals used in the hydraulic fracturing process, effective as of September 1, 2011. The RRC has adopted rules and regulations implementing thislegislation that apply to all wells for which the RRC issues an initial drilling permit after February 1, 2012. The new law requires that the well operatordisclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) for disclosure on an internetweb site 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 mustalso be disclosed to the public and filed with the RRC. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturingactivities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas wherewe operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit ofexploration, development, or production activities, and perhaps even be precluded from drilling wells. A variety of federal and state laws and regulations govern the environmental aspects of natural gas and oil production, transportation andprocessing. These laws and regulations may impose liability in the event of discharges, including for accidental discharges, failure to notify the properauthorities of a discharge, and other noncompliance. Compliance with such laws and regulations may increase the cost of oil and natural gas exploration,development and production; although we do not anticipate that compliance will have a material adverse effect on our capital expenditures or earnings.Failure to comply with the requirements of the applicable laws and regulations could subject us to substantial civil and/or criminal penalties and to thetemporary or permanent curtailment or cessation of all or a portion of our operations. Comprehensive Environmental Response, Compensation and Liability Act The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “superfund law,” imposes joint andseveral liabilities, regardless of fault or the legality of the original conduct, on some classes of persons that are considered to have contributed to the releaseof a “hazardous substance” into the environment. These persons include the owner or operator of a disposal site or sites where the release occurred andcompanies that transport, dispose, or arrange for disposal of the hazardous substance(s) released. Persons who are or were responsible for releases of hazardoussubstances under CERCLA may be jointly and severally liable for the costs of cleaning up the hazardous substances and for damages to natural resources. Itis not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by thehazardous substances released into the environment. We could be subject to liability under CERCLA, including for jointly-owned drilling and productionactivities that generate relatively small amounts of liquid and solid waste that may be subject to classification as hazardous substances under CERCLA. We generate materials in the course of our operations that may be regulated as hazardous substances. Despite the “petroleum exclusion” ofCERCLA, which currently encompasses natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar statestatutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required toclean up sites at which these hazardous substances have been released into the environment. In addition, we currently own, lease, or operate numerousproperties that have been used for oil and natural gas exploration, production and processing for many years. Although we believe that we have utilizedoperating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been releasedon, 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 beentaken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal ofhazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from themmay be subject to CERCLA, RCRA and analogous state and local laws. Under such laws, we could be required to undertake investigatory, response, orcorrective measures, which could include soil and groundwater sampling, the removal of previously disposed substances and wastes, the cleanup ofcontaminated property, or performance of remedial plugging or pit closure operations to prevent future contamination, the costs of which could besubstantial. 15  Endangered Species Act and Migratory Birds The Endangered Species Act (“ESA”) restricts activities that may affect federally identified endangered and threatened species or their habitatsthrough the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas. Pursuant to the ESA, if a species is listed asthreatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. We may conduct operations under oil andnatural gas leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species that potentially couldbe listed as threatened or endangered under the ESA may exist. The U.S. Fish and Wildlife Service (“FWS”) may designate critical habitat and suitable habitatareas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in furthermaterial restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. Similar protections are offered tomigratory birds under the Migratory Bird Treaty Act. The federal government has issued indictments under the Migratory Bird Treaty Act to several oil andgas companies after dead migratory birds were found near reserve pits associated with drilling activities. The identification or designation of previouslyunprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arisingfrom species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our abilityto 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 ourleases. NEPA Additionally, significant federal decisions, such as the issuance of federal permits or authorizations for certain oil and gas exploration andproduction activities may be subject to the National Environmental Policy Act (“NEPA”). The NEPA requires federal agencies, including the Department ofInterior, to evaluate major federal agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agencywill prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, willprepare a more detailed Environmental Impact Statement that may be made available for public review and comment. This process has the potential to delayoil and gas development projects. OSHA We are subject to the requirements of the OSHA and comparable state statutes whose purpose is to protect the health and safety of workers. Inaddition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes and anyimplementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that thisinformation be provided to employees, state and local governmental authorities and citizens. We believe that we are in substantial compliance with allapplicable 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 thoselaws and regulations are discussed above. They relate to, among other things, requirements to remediate spills of deleterious substances associated with oiland gas activities, the conduct of salt water disposal operations, and the methods of plugging and abandonment of oil and gas wells which have beenunproductive. Numerous state laws and regulations also relate to air and water quality. In General We do not believe that our environmental risks will be materially different from those of comparable companies in the oil and gas industry. Webelieve our present activities substantially comply, in all material respects, with existing environmental laws and regulations. Nevertheless, environmentallaws may result in a curtailment of production or material increase in the cost of production, development or exploration and may otherwise adversely affectour financial condition and results of operations. Although we maintain liability insurance coverage for liabilities from pollution, environmental risks,generally are not fully insurable. In addition, because we have acquired and may acquire interests in properties that have been operated in the past by others, we may be liable forenvironmental damage, including historical contamination, caused by such former operators. Additional liabilities could also arise from continuingviolations or contamination not discovered during our assessment of the acquired properties. 16  Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produceand the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce bynatural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted whichhave resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales ofour own production. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas marketsand enforce its rules and orders, including the ability to assess substantial civil penalties. FERC also regulates interstate natural gas transportation rates andservice conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas thatwe produce, as well as the revenues we receive for sales of our natural gas and release of our natural gas pipeline capacity. Commencing in 1985, FERCpromulgated a series of orders, regulations and rule makings that significantly fostered 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 ofwhether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open accessmarket for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However,the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currentlypursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have onour natural gas related activities. Under FERC’s current regulatory regime, transmission services are provided on an open-access, non-discriminatory basis at cost-based rates ornegotiated 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. Oil Sales and Transportation. Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices.Nevertheless, Congress could reenact price controls in the future. Our crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is alsosubject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipelinetransportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatoryoversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicableto all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than suchregulation will affect the operations of our competitors. 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 transportationservices generally will be available to us to the same extent as to our competitors. Federal Income Tax. 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 developmentcosts” 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 suchproperties (up to an aggregate of 1,000 barrels per day of domestic crude oil and/or equivalent units of domestic natural gas). Federal Leases. For those operations on federal oil and natural gas leases, such operations must comply with numerous regulatory restrictions,including various non-discrimination statutes, and certain of such operations must be conducted pursuant to certain on-site security regulations and otherpermits issued by various federal agencies. In addition, on federal lands in the United States, the Office of Natural Resources Revenue (“ONRR”) prescribes orseverely limits the types of costs that are deductible transportation costs for purposes of royalty valuation of production sold off the lease. In particular,ONRR prohibits deduction of costs associated with marketer fees, cash out and other pipeline imbalance penalties, or long-term storage fees. Further, theONRR has been engaged in a process of promulgating new rules and procedures for determining the value of crude oil produced from federal lands forpurposes of calculating royalties owed to the government. The natural gas and crude oil industry as a whole has resisted the proposed rules under anassumption that royalty burdens will substantially increase. We cannot predict what, if any, effect any new rule will have on our operations. 17  Some of our operations are conducted on federal lands pursuant to oil and gas leases administered by the BLM. These leases contain relativelystandardized terms and require compliance with detailed regulations and orders, which are subject to change. In addition to permits required from otherregulatory agencies, lessees must obtain a permit from the BLM before drilling and comply with regulations governing, among other things, engineering andconstruction specifications for production facilities, safety procedures, the valuation of production and payment of royalties, the removal of facilities, and theposting of bonds to ensure that lessee obligations are met. Under certain circumstances, the BLM may require our operations on federal leases to besuspended or terminated. Other Laws and Regulations. Various laws and regulations require permits for drilling wells and also cover spacing of wells, the prevention of wasteof natural gas and oil including maintenance of certain gas/oil ratios, rates of production and other matters. The effect of these laws and regulations, as well asother regulations that could be promulgated by the jurisdictions, in which we have production, could be to limit the number of wells that could be drilled onour properties and to limit the allowable production from the successful wells completed on our properties, thereby limiting our revenues. To date we have not experienced any material adverse effect on our operations from obligations under environmental, health, and safety laws andregulations. We believe that we are in substantial compliance with currently applicable environmental, health, and safety laws and regulations, and thatcontinued compliance with existing requirements will not have a materially adverse impact on us. Seasonal Nature of Business Generally, the demand for oil and natural gas fluctuates depending on the time of year. Seasonal anomalies such as mild winters or hot summers maysometimes lessen this fluctuation. Further, pipelines, utilities, local distribution companies, and industrial end users utilize oil and natural gas storagefacilities and purchase some of their anticipated winter requirements during the summer, which can also lessen seasonal demand. Operational Hazards and Insurance The oil business involves a variety of operating risks, including the risk of fire, explosions, blow outs, pipe failures and, in some cases, abnormallyhigh pressure formations which could lead to environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. If any of theseshould occur, we could incur legal defense costs and could be required to pay amounts due to injury, loss of life, damage or destruction to property, naturalresources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations. In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to which ourbusiness is exposed. Current Employees As of December 31, 2017, we had 27 full-time employees, and intend to continue to add additional personnel as our operational requirements grow.Our employees are not represented by any labor union. We consider our relations with our employees to be satisfactory and have never experienced a workstoppage or strike. 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 Our principal executive offices are located 300 E. Sonterra Blvd., Suite No. 1220, San Antonio, Texas 78258, and our telephone number is (210)999-5400. Our Internet website can be found at https://www.lilisenergy.com/. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, currentreports 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 availablethrough our Internet website as soon as reasonably practical after we electronically file such material with, or furnish it to, the SEC. The information on, orthat 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. 18  Item 1A. Risk Factors Investing in our shares of common stock involves significant risks, including the potential loss of all or part of your investment. These risks couldmaterially affect our business, financial condition and results of operations and cause a decline in the market price of our common stock. You shouldcarefully consider all of the risks described in this Annual Report, in addition to the other information contained in this Annual Report, before you make aninvestment in our common stock. Additional risks not presently known to us or that we currently deem immaterial may also adversely affect our business. Inaddition to other matters identified or described by us from time to time in filings with the SEC, there are several important factors that could cause ourfuture results to differ materially from historical results or trends, results anticipated or planned by us, or results that are reflected from time to time in anyforward-looking statement. Some of these important factors, but not necessarily all important factors include the following: Risks Relating to Our Business 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 operatingactivities, and net proceeds from the issuance of Series A preferred, Series B preferred and Series C preferred shares. Our capital program may requireadditional financing above the level of cash generated by our operations to fund growth. If our expected cash flow from operations decreases as a result oflower commodity prices or otherwise, our ability to expend the capital necessary to replace our proved reserves, maintain our leasehold acreage or maintainproduction 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. Ourcash 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 other capital resources may not provide cash in sufficient amounts to maintain planned or future levels of capital expenditures.Further, our actual capital expenditures in 2018 could exceed our capital expenditure budget. In the event our capital expenditure requirements at any timeare greater than the amount of capital we have available, we could be required to seek additional sources of capital, which may include refinancing existingdebt, joint venture partnerships, production payment financings, offerings of debt or equity securities or other means. We may not be able to obtain debt orequity financing on terms favorable, or at all. Oil, natural gas and NGL prices are highly volatile. If commodity prices experience substantial decline, our operations, financial condition, and level ofexpenditures for the development of our oil, natural gas and NGL reserves may 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 widefluctuations 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. If the prices of oil,natural gas, and NGLs experience a substantial decline, our operations, financial condition and level of expenditures for the development of our oil, naturalgas and NGL reserves may be materially and adversely affected. The prices we receive for our production, and the levels of our production, depend onnumerous factors beyond our control and include the following: ·changes in global supply and demand for oil and natural gas;·the actions of the Organization of Petroleum Exporting Countries, or OPEC;·the price and quantity of imports of foreign oil and natural gas;·political conditions, including embargoes, in or affecting other oil-producing activity;·the level of global oil and natural gas exploration and production activity;·the level of global oil and natural gas inventories; 19  ·weather conditions;·technological advances affecting energy consumption; and·the price and availability of alternative fuels. Volatile oil and natural gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in themarket for oil and natural gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult tobudget for and project the return on acquisitions and development and exploitation projects. 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 additionalcapital. In addition, we may need to record asset carrying value write-downs if prices fall. A significant decline in the prices of natural gas or oil couldadversely affect our financial position, financial results, cash flows, access to capital and ability to grow. 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 theeconomy or our industry and prevent us from meeting our obligations under our indebtedness. We entered into the First Lien Credit Agreement in 2016, the Second Lien Credit Agreement in 2017 and the Riverstone First Lien Credit Agreementin 2018 (as such terms are hereinafter defined and as described in more detail herein). As of December 31, 2017, $30.8 million was outstanding under our FirstLien Credit Agreement (which was subsequently paid off with loan proceeds of the Riverstone First Lien Credit Agreement) and $155.8 million wasoutstanding on under our Second Lien Credit Agreement. If we further utilize our credit facilities in the future or obtain additional financing, our level of indebtedness could affect our operations in severalways, including the following: ·it may limit our ability to obtain additional debt or equity financing for working capital, capital expenditures, further exploration, debt servicerequirements, acquisitions and general corporate or other purposes;·a substantial portion of our cash flows from operations will be dedicated to the payment of principal and interest on our indebtedness and will not beavailable for other purposes, including our operations, capital expenditures and future business opportunities;·the debt service requirements of other indebtedness in the future could make it more difficult for us to satisfy our financial obligations;·we could be vulnerable to any downturn in general economic conditions and in our business, and we could be unable to carry out capital spendingand exploration activities that are currently planned; and·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,which may be difficult to obtain. We may incur additional debt, including secured indebtedness, or issue preferred stock in order to maintain adequate liquidity and develop andacquire properties to the extent desired. A higher level of indebtedness and/or preferred stock increases the risk that we may default on our obligations. The Riverstone First Lien Credit Agreement and Second Lien Credit Agreement, guaranteed and further secured by substantially all our assets, containrestrictive covenants that may limit our ability to respond to changes in market conditions or pursue business opportunities. Our Riverstone First Lien Credit Agreement and Second Lien Credit Agreement contain restrictive covenants that limit our ability to, among otherthings: ·incur additional indebtedness;·create additional liens;·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 materially adversely affect our ability to react to changes in market conditions, takeadvantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or futuredownturn in our business. 20  We may from time to time enter into alternative or additional debt agreements that contain covenant restrictions that may prevent us from takingactions that we believe would be in the best interest of our business, may require us to sell assets or take other actions to reduce indebtedness to meet suchcovenants, and may make it difficult for us to successfully execute our business strategy or effectively compete with companies that are not similarlyrestricted. Värde Partners, Inc. and its affiliates (collectively, “Värde”) beneficially own a significant portion of our common stock. Värde is not limited in theirability to compete with us, and the waiver of the corporate opportunity provisions in the certificate of designation relating to our Series C 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 futurebetween us and Värde, including their portfolio companies 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 rightsavailable to them under the Second Lien Credit Agreement and the Series C Preferred Stock (as hereinafter defined and described), and it has investments inother companies in the energy industry. The Series C Preferred Stock was issued on January 30, 2018. As a result, Värde may, from time to time, acquireinterests in businesses that directly or indirectly compete with our business, as well as businesses that are our customers or suppliers. As such, Värde or itsportfolio companies may acquire or seek to acquire the same assets that we seek to acquire and, as a result, those acquisition opportunities may not beavailable to us or may be more expensive for us to pursue. Any actual or perceived conflicts of interest with respect to the foregoing could have an adverseimpact on the trading price of our common stock. The certificate of designation governing the preferences, rights and limitations of the Series C Preferred Stock, provides that Värde (includingportfolio investments of Värde) is not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. In particular, subjectto the limitations of applicable law, if Värde, or any agent, shareholder, member, partner, director, officer, employee, investment manager or investmentadvisor 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 noduty to communicate or offer that opportunity to us. Värde may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunitiesto other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity.Furthermore, such businesses may choose to compete with us for these opportunities, possibly causing these opportunities to not be available to us or causingthem to be more expensive for us to pursue. As a result, our renouncing our interest and expectancy in any business opportunity that may be from time to timepresented to Värde could adversely impact our business or prospects if attractive business opportunities are procured by such parties for their own benefitrather than for ours. 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 wellconceived and operated, can provide only reasonable assurance that the objectives of the control system are being met. In addition, the design of a controlsystem must reflect the fact that there are resource constraints, and the benefits of controls are evaluated relative to their costs. Because of the inherentlimitations in all control systems, no evaluation of our controls can provide absolute assurance that all control issues and instances of fraud, if any, have beendetected. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur without detection, which couldhave 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, ourmanagement is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is aprocess designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for externalpurposes in accordance with generally accepted accounting principles. Under the supervision and with the participation of our management, including theChief Executive Officer and the Chief Financial Officer, we are required to conduct an evaluation of the effectiveness of our internal control over financialreporting based on framework of internal control issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Because ofits inherent limitations, internal controls over financial reporting may not prevent or detect misstatements. In addition, projections of any evaluationeffectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliancewith the policies and procedures may deteriorate. A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonablepossibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis. Duringthe audit of our internal control over financial reporting for the year ended December 31, 2017, errors were identified in the Company’s computation of thefull cost ceiling test limitation. For a discussion of our internal control over financial reporting and a description of the identified material weakness, see"Management's Report on Internal Control Over Financial Reporting" included in Item 9A of this report. 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 beharmed. Internal control over financial reporting may not prevent or detect misstatements because of its inherent limitations, including the possibility ofhuman error, the circumvention or overriding of controls, or fraud. Further, the complexities of our quarter-end and year-end closing processes increase therisk that a weakness in internal controls over financial reporting may go undetected. Therefore, even effective internal controls can provide only reasonableassurance with respect to the preparation and fair presentation of financial statements. In addition, projections of any evaluation of effectiveness of internalcontrol over financial reporting to future periods are subject to the risk that the control may become inadequate because of changes in conditions, or that thedegree of compliance with the policies or procedures may deteriorate. A material weakness in our internal control over financial reporting could adversely impact our ability to provide timely and accurate financialinformation. We have identified remediation steps, including enhanced analytical analysis and improved management review of the full cost ceiling testcalculation in order to remediate this material weakness. We plan to complete this remediation process as quickly as possible. However, if our remedialmeasures are insufficient to address the material weakness or if additional material weaknesses or significant deficiencies in our internal control over financialreporting are discovered or occur in the future, we may not be able to timely or accurately report our financial condition, results of operations or cash flows ormaintain effective disclosure controls and procedures. 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, including adelisting from the NYSE, securities litigation, debt rating agency downgrades or rating withdrawals, any one of which could adversely affect the valuation ofour 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, potentiallyrequiring earlier than anticipated debt repayment and negatively impacting the trading value of our securities. Accounting rules require that we review periodically the carrying value of our oil and natural gas properties for possible impairment through theperformance of a ceiling test. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuingevaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and naturalgas 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 animpairment expense. We recognized an impairment expense of approximately $10.5 million and approximately $4.7 million for the years ended December31, 2017 and 2016, respectively. Future write-downs could occur for numerous reasons, including, but not limited to continued reductions in oil and natural gas prices that lower theestimate of future net revenues from proved oil and natural gas reserves, revisions to reserve estimates, or from the addition of non-productive capitalizedcosts to the full cost pool that do not result in corresponding increase in oil and natural gas reserves. Impairments of plugging and abandonment of wells inprogress are other areas where costs may be capitalized into the full cost pool, without any corresponding increase in reserve values. As such, these situationscould result in future additional impairment expenses. If commodity prices decline, we could incur full cost ceiling impairments in future quarters.Impairment charges would not affect cash flow from operating activities, but could have a material adverse effect our net income and stockholders’ equity. 21  Our estimated reserves are based on many assumptions that may prove inaccurate. Any significant inaccuracies in these reserve estimates or underlyingassumptions will materially affect the quantities and present value of our reserves. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptionsconcerning future oil and natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves andprojections of future production rates and the timing of development expenditures may prove to be inaccurate. Any material inaccuracies in these reserveestimates or underlying assumptions could materially affect the quantities and present value of our reserves which could adversely affect our business, resultsof 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 assumptionsabout matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Although the reserveinformation 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.In accordance with SEC requirements, we based the estimated discounted future net cash flows from proved reserves on the 12-month unweighted average offirst-day-of-the-month oil and natural gas benchmark prices, adjusted for marketing and other differentials and costs in effect on the date of the estimate,holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the netpresent value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. If our reserve estimates or the underlying assumptions prove inaccurate, it could have a negative impact on our earnings and net income, and mostlikely the trading price of our securities. Hedging transactions may limit our potential gains or result in losses. In order to manage our exposure to price risks in the marketing of our oil and natural gas, from time to time, we may enter into derivative contractsthat economically hedge our oil and gas price on a portion of our production. These contracts may limit our potential gains if oil and natural gas prices wereto rise substantially over the price established by the contract. In addition, such transactions may expose us to the risk of financial loss in certaincircumstances, 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 we may enter into may not adequately protect us from declines in the prices of oil and natural gas. In addition, thecounterparties under any future derivatives contracts may fail to fulfill their contractual obligations to us. As of December 31, 2017, we had hedgingagreements in place on approximately 1,000 Bbl per day, or 83% of our expected production from proved developed producing reserves for the period fromJanuary 1, 2018 through June 30, 2018, as forecast under the reserve report prepared by our independent reserve engineers dated December 31, 2017. Our identified drilling locations are scheduled to be drilled over a period of several years, making them susceptible to uncertainties that could materiallyalter 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 existingacreage. These scheduled drilling locations represent a significant component of our growth strategy. Our ability to drill and develop these locations dependson a number of uncertainties, including oil and natural gas prices, the availability of capital, costs, drilling results, regulatory approvals and other factors.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 oilor natural gas from these or any other 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 couldadversely 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 particularprospect 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 andother 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 willbe present or, if present, whether oil or natural gas will be present in commercial quantities as such studies are merely an interpretive tool. 22  Drilling for oil and natural gas involves numerous risks, including the risk that no commercially productive natural gas or oil reservoirs will bediscovered. The cost of drilling, completing, and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed, or canceledas 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. Additionally, the budgeted costs of planning, drilling, completing and operating wells are often exceeded and such costs can increase significantlydue to various complications that may arise during the drilling and operating processes. Before a well is spud, we may incur significant geological andgeophysical (seismic) costs, which are incurred whether a well eventually produces commercial quantities of hydrocarbons, or is drilled at all. Explorationwells endure a much greater risk of loss than development wells. If actual drilling and development costs are significantly more than the current estimatedcosts, we may not be able to continue operations as proposed and could be forced to modify drilling plans accordingly. If we decide to drill a certain location, there is a risk that no commercially productive oil or natural gas reservoirs will be found or produced, or wemay drill or participate in new wells that are not productive or drill wells that are productive, but that do not produce sufficient net revenues to return a profitafter drilling, operating and other costs. A productive well may become uneconomical if water or other deleterious substances are encountered which impairor prevent the production of oil and/or natural gas from the well. Unsuccessful drilling activities could result in a significant decline in production andrevenues and materially harm 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 fromoperations 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 marketingcompanies and mid-stream companies. Any delays in payments from such purchasers caused by financial problems encountered by them will have animmediate 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-operatedproperties 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 theirshare 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 ofthe 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 oiland natural gas include: leasehold prospects under which oil and natural gas reserves may be discovered; drilling rigs and related equipment to explore forsuch reserves; and knowledgeable personnel to conduct all phases of oil and natural gas operations. We must compete for such resources with both major oiland natural gas companies and independent operators. Many of our competitors have financial and other resources substantially greater than ours. Such capital, materials and resources may not beavailable when needed. If we are unable to access capital, material and resources when needed, we risk suffering numerous consequences, including, thebreach of our obligations under the oil and natural gas leases by which we hold our prospects and the potential loss of those leasehold interests; loss ofreputation in the oil and gas community; inability to retain personnel or attract capital, a slowdown in our operations and decline in revenue; and a decline inthe 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 reserve potential, identify liabilitiesassociated with the properties or obtain protection from sellers against them, which could cause us to incur losses. One of our growth strategies is to pursue selective acquisitions of undeveloped acreage potentially containing oil and natural gas reserves. If wechoose to pursue an acquisition, we will perform a review of the target properties. However, these reviews are inherently incomplete as they are based on thequality, availability and interpretation of the reviewed data and the acumen and the assumptions of the evaluation personnel. Generally, it is not feasible toreview in depth every individual property, well, facility and/or file involved in each acquisition. Even a detailed review of records and properties may notnecessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficienciesand potential. We may not perform an inspection on every well, and environmental problems, such as groundwater contamination, are not necessarilyobservable even when an inspection is undertaken. Even when problems are identified, we may not be able to obtain effective contractual protection againstall or part of those problems, and we may assume environmental and other risks and liabilities in connection with the acquired properties. If we acquireproperties with risks or liabilities that were unknown or not assessed correctly, financial condition, results of operations and cash flows could be adverselyaffected as claims are settled and cleanup costs related to these liabilities are incurred. 23  We may incur losses or costs as a result of title deficiencies in the properties in which we invest. If an examination of the title history of a property that we purchased reveals an oil and natural gas lease has been purchased in error from a personwho is not the owner of the mineral interest desired, our interest would be worthless. In such an instance, the amount paid for such oil and natural gas lease aswell as any royalties paid pursuant to the terms of the lease prior to the discovery of the title defect would be lost. Prior to the drilling of an oil and natural gas well, however, it is the normal practice in the oil and natural gas industry for the operator of the well toobtain 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 obviousdeficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability ofthe title, and such curative work entails expense. Failure to cure any title defects may adversely impact our ability in the future to increase production andreserves. In the future, we may suffer a monetary loss from title defects or title failure. Additionally, unproved and unevaluated acreage has greater risk of titledefects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we willsuffer a financial loss which could adversely affect our financial condition, results of operations and cash flows. Our producing properties are located in the Delaware Basin, making us vulnerable to risks associated with operating in one major geographic area. All of our estimated proved reserves at December 31, 2017, were located in the Delaware Basin in Winkler, Loving, and Reeves Counties, Texas andLea County, New Mexico. As a result of this concentration, we may be disproportionately exposed to the impact of delays or interruptions of production fromthese wells caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significantgovernmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil ornatural 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 producingareas, which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Due to the concentrated nature of ourportfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact onour results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions couldhave 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 90% of our acreage. As we carry out our exploration and development programs, we may enter intoarrangements with respect to existing or future drilling locations that result in wells being operated by others. As a result, we may have limited ability toexercise influence over the operations of the drilling locations operated by our partners. Dependence on the operator could prevent us from realizing targetreturns for those locations. The success and timing of exploration and development activities operated by our partners will depend on a number of factors thatwill be largely outside of our control, including: ·the timing and amount of capital expenditures;·the operator’s expertise and financial resources;·approval of other participants in drilling wells;·selection of technology; and·the rate of production of reserves, if any. Our limited ability to exercise control over the operations of any drilling locations operated by other operators may cause a material adverse effecton results of operations and financial condition. 24  The marketability of our production is dependent upon transportation and processing facilities and third parties over which or whom we may have nocontrol. The marketability of our production depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems, railservice, and processing facilities in addition to competing oil and natural gas production available to third-party purchasers. We deliver our produced crudeoil and natural gas through trucking, gathering systems and pipelines, some of which we do not own. The lack of availability of capacity on third-partysystems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of ourdevelopment plans. Although we have some 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 reliability or other reasons, including adverse weatherconditions or work-loads. Any significant change in market factors or other conditions affecting these infrastructure systems and facilities, as well as anydelays in constructing new infrastructure systems and facilities, could delay production, thereby harming our business and, in turn, our results of operations,cash flows, and financial condition. On August 10, 2017, we entered into a long-term agreement with Lucid relating to gas gathering, processing and associated services to support ourdrilling program. Pursuant to the agreement, Lucid will receive, gather and process our gas production from certain production areas located in Lea County,New Mexico and in Loving and Winkler Counties, Texas. The agreement secures incremental midstream capacity for us in the production areas committed tothe new agreement. We commenced services with Lucid on our New Mexico properties in November 2017 and expect to commence services on our Texasproperties in early 2018. 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). Thelack of availability of capacity on third-party systems and facilities (see "Risk Factors-Risks Relating to Our Business-The marketability of our production isdependent upon transportation and processing facilities and third parties over which or whom we may have no control.”) or the shut-in of an oil field’sproduction, among other reasons, could result in the shut-in of our wells. As of December 31, 2017, we had 3 gross (2.60 net) wells shut in awaitinginfrastructure. If we experience low oil production volumes due to the shut-in of our wells, we would experience a reduction in our available liquidity and we maynot have the ability to generate sufficient cash flows from operations and, therefore, sufficient liquidity to meet our anticipated working capital, debt service,and other liquidity needs. A significant decline in oil production due to the shut-in of our wells could adversely affect our financial position, financialresults, cash flows, access to capital and ability to grow. Unless we find new oil and natural gas reserves to replace actual production, our reserves and production will decline, which would materially andadversely 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 reservoircharacteristics subsurface and surface pressures and other factors. Thus, our future oil and natural gas reserves and production and, therefore, our cash flowand revenue are highly dependent on our success in efficiently obtaining additional reserves. We may not be able to develop, find or acquire reserves toreplace 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 ofoperations would be materially and adversely affected. The results of our planned exploratory and development drilling are subject to drilling and completion execution risks, and drilling results may not meetour 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 facewhile drilling include, but are not limited to, not reaching the desired objective due to drilling problems, not landing our wellbore in the desired drillingzone or specific target, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of thewellbore and being able to run tools and other equipment consistently through the horizontal wellbore. Risks that we face while completing our wellsinclude, but are not limited to, mechanical integrity, being able to hydraulic fracture stimulate the planned number of stages, being able to run tools theentire length of the wellbore during completion operations, proper design and engineering versus reservoir parameters, and successfully cleaning out thewellbore after completion of the final fracture stimulation stage. Our experience with horizontal well applications utilizing the latest drilling and completion techniques specifically in the formations where we arecurrently operating is limited; however, we contract with local experts in the area to design, plan and conduct our drilling and completion operations.Ultimately, the success of these drilling and completion techniques can only be developed over time as more wells are drilled and production profiles areestablished. 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 and limited takeaway capacity or otherwise, the return on our investment in these areas may not be as attractive as we anticipateand we could incur material write-downs of undeveloped properties and the value of our undeveloped acreage could decline in the future. 25  The unavailability or high cost of drilling rigs, equipment supplies, or personnel could adversely affect our ability to execute our exploration anddevelopment plans. The oil and gas industry is cyclical and, from time to time, there are shortages of drilling rigs, equipment, supplies or qualified personnel. Duringthese periods, the costs of and demand for rigs, equipment and supplies may increase substantially and their availability may be limited. In addition, thedemand for, and wage rates of, qualified personnel, including drilling rig crews, may rise as the number of rigs in service increases. The higher prices of oiland natural gas during the last several years have increased activity which has resulted in shortages of drilling rigs, equipment and personnel, which haveresulted in increased costs and delays in the areas where we operate. If drilling rigs, equipment, supplies or qualified personnel are unavailable to us due toexcessive costs or demand or otherwise, our ability to execute our exploration and development plans could be materially and adversely affected and, as aresult, 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 inprices 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 issuedwarnings that energy assets may be a future target of terrorist organizations. These developments have subjected oil and natural gas operations to increasedrisks. Any future terrorist attack on our facilities, customer facilities, the infrastructure depended upon for transportation of products, and, in some cases, thoseof 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 all of the operating risks associated with drilling for and producing oiland natural gas, including the risk of: ·fire, explosions and blowouts;·negligence of personnel;·inclement weather;·pipe or equipment failure; ·abnormally pressured formations; ·environmental accidents such as oil spills; and ·natural gas environment (including groundwater contamination). Oil and natural gas operations are subject to particular hazards incident to the drilling and production of oil and natural gas, such as blowouts,cratering, explosions, uncontrollable flows of oil, natural gas or well fluids, fires and pollution and other environmental risks. These hazards can causepersonal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension ofoperation. These events may result in substantial losses to our company from: ·injury or loss of life;·significantly increased costs;·severe damage to or destruction of property, natural resources and equipment;·pollution or other environmental damage;·clean-up responsibilities;·regulatory investigation;·penalties and suspension of operations; or·attorney’s fees and other expenses incurred in the prosecution or defense of litigation. In accordance with customary industry practices, we maintain insurance against some, but not all, of these risks. Our insurance may not be adequateto cover these losses or liabilities. We do not carry business interruption insurance. We may elect not to carry insurance if management believes that the costof available insurance is excessive relative to the risks presented. In addition, we cannot insure fully against pollution and environmental risks. Theoccurrence of an event not fully covered by insurance could have a material adverse effect on our financial condition and results of operations. The impact ofnatural disasters or weather events in the areas where we operate has resulted in escalating insurance costs and less favorable coverage terms. Losses andliabilities arising from uninsured or underinsured events may have a material adverse effect on our financial condition and operations, including the loss ofour total investment in a particular prospect. The producing wells in which we have an interest occasionally experience reduced or terminated production. These curtailments can result frommechanical failures, contract terms, pipeline and processing plant interruptions, market conditions, operator priorities, and weather conditions. Thesecurtailments can last from a few days to many months, any of which could have an adverse effect on our results of operations. 26  A failure of technology systems, data breach or cyberattack could materially affect our operations. Information technology solution failures, network disruptions, breaches of data security and cyberattacks could disrupt our operations by causingdelays or cancellation of customer orders, impeding processing of transactions and reporting financial results, resulting in the unintentional disclosure ofcustomer, employee or our information, or damaging our reputation. A system failure, data security breach or cyberattack could have a material adverse effecton our financial condition, results of operations or cash flows. Our information technology systems may be vulnerable to security breaches beyond our control, including those involving cyberattacks usingviruses, worms or other destructive software, process breakdowns, phishing or other malicious activities, or any combination of the foregoing. Such breachescould result in unauthorized access to information, including customer, employee, or other company confidential data. We do not carry insurance againstthese risks, although we do invest in security technology, perform penetration tests from time to time, and design our business processes to attempt tomitigate the risk of such breaches. However, there can be no assurance that security breaches will not occur. Moreover, the development and maintenance ofthese measures requires continuous monitoring as technologies change and efforts to overcome security measures evolve. We have experienced, and expectto continue to experience, cyber security threats and incidents, none of which has been material to us to date. However, a successful breach or attack couldhave a material negative impact on our operations or business reputation and subject us to consequences such as litigation and direct costs associated withincident response. 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 andservices using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or competitive pressures mayforce us to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical, andpersonnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we are in aposition 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. Ifone 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 availabletechnology, 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, 2017, we had 27 full-time employees. We leverage the services of independent consultants and contractors to perform variousprofessional services, including engineering, oil and natural gas well planning and supervision, and land, legal, environmental and tax services. We alsopursue 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 suchthird parties may not be available to us as and when needed and the risk that we may not be able to properly control the timing and quality of workconducted 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. We depend to a large extent on the services of certain key management personnel, including Ron Ormand, our Executive Chairman of the Board,James (Jim) Linville, our Chief Executive Officer, Joseph Daches, our Chief Financial Officer, and other executive officers and key employees. Theseindividuals have extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizingproduction from oil and natural gas properties, marketing oil and natural gas production and developing and executing financing and hedging strategies. Theloss 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 ouremployees. 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 determinationof various operational strategies. Members of our board of directors work closely with management to identify potential prospects, acquisitions and areas forfurther development. If any directors resign or become unable to continue in their present role, it may be difficult to find replacements with the sameknowledge 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. Significantacquisitions and other strategic transactions may involve other 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 ofours 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 otherbenefits anticipated from an acquisition, or to realize these benefits within the expected time frame. 27  The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our seniormanagement and other staff may be required to devote considerable amounts of time to this integration process, which will decrease the time they will haveto manage our business. If our senior management and staff are not able to effectively manage the integration process, or if any significant business activitiesare interrupted as a result of the integration process, our business could suffer. We may have difficulty managing growth in our business, which could adversely affect our financial condition and results of operations. Significant growth in the size and scope of our operations could place a strain on our financial, technical, operational and management resources.The failure to continue to upgrade our technical, administrative, operating and financial staff and control systems or the occurrences of unexpectedexpansion difficulties, including the failure to recruit and retain experienced managers, geologists, engineers and other professionals in the oil and gasindustry could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our businessplan. 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 interestgroups, regulatory agencies and other governmental entities. As a result, we may face significant opposition to, or increased regulation of, our operations, thatmay make it difficult or impossible to obtain permits and other needed authorizations to drill, complete or operate, result in operational delays, or otherwisemake oil and natural gas exploration more costly or difficult than in other countries. Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on ourfinancial 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 conditionsover the past several years. These drought conditions have led governmental authorities to restrict the use of water subject to their jurisdiction for hydraulicfracturing 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 andnatural gas economically, which could have an adverse effect on our financial condition, results of operations and cash flows. Risks Relating to the Oil and Natural Gas Industry Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for oiland natural gas. In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to publichealth and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climaticchanges. Based on these findings, the EPA, under the Clean Air Act, has begun adopting and implementing regulations to restrict emissions of greenhousegases. Relatively recently, the EPA adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, one of which requires a reductionin emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources.The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the UnitedStates on an annual basis, including petroleum refineries, as well as certain onshore oil and natural gas production facilities. Also, on May 12, 2016, EPA issued regulations (effective August 2, 2016) that build on the 40 C.F.R. Part 60, Subpart OOOO (NSPS OOOO)standards by directly regulating methane and VOC emissions from various types of new and modified oil and natural gas sources. Some of those sources arealready regulated under NSPS OOOO, while others, like hydraulically fractured oil wells, pneumatic pumps, and certain equipment and components atcompressor stations, are covered for the first time. On March 10, 2016, moreover, the EPA announced that it is moving towards issuing performance standardsfor methane emissions from existing oil and natural gas sources. The agency said that it will “begin with a formal process (i.e, an Information CollectionRequest) to require companies operating existing oil and natural gas sources to provide information to assist in the development of comprehensiveregulations to reduce methane emissions.” On November 10, 2016, the EPA issued the Information Collection Request (“ICR”) and explained that“[r]ecipients of the operator survey (also referred to as Part 1) will have 60 days after receiving the ICR to complete the survey and submit it to EPA.Recipients of the more detailed facility survey (also referred to as Part 2) will have 180 days after receiving the ICR to complete that survey and submit it tothe agency.” 28  In June 2014, the United States Supreme Court’s holding in Utility Air Regulatory Group v. EPA upheld a portion of EPA’s greenhouse gas (“GHG”)stationary source permitting program, but also invalidated a portion of it. The Court held that stationary sources already subject to the Prevention ofSignificant Deterioration (“PSD”) or Title V permitting programs for non-GHG criteria pollutants remain subject to GHG Best Available Control Technologyand major source permitting requirements, but ruled that sources cannot be subject to the PSD or Title V major source permitting programs based solely onGHG emission levels. As a result, on August 12, 2015, the EPA eliminated from its PSD and Title V regulations the provisions that subjected sources to thePSD or Title V programs based solely on GHG emission levels. The EPA likewise said that it will “further revise the PSD and Title V regulations in a separaterulemaking to fully implement” the Utility Air Regulatory Group judgment. On October 3, 2016, EPA published a proposed rulemaking for that purpose. TheUtility Air Regulatory Group judgment does not prevent states from considering and adopting state-only major source permitting requirements based solelyon GHG emission levels. 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 havealready taken legal measures to reduce GHG emissions, primarily through the planned development of GHG emission inventories and/or regional GHG capand trade programs. Most of these GHG cap and trade programs work by requiring major sources of emissions, such as electric power plants, or majorproducers of fuels, such as refineries and natural gas processing plants, to acquire and surrender emission allowances. The number of allowances available forpurchase 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 topurchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any suchlegislation 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, financial condition and results ofoperations. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHG in the Earth’s atmosphere may produceclimate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. Ifany such effects were to occur, they could have an adverse effect on our financial condition and results of operations. Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operatingrestrictions 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 rockformations. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulateproduction by providing and linking up induced flow paths for the oil and/or natural gas contained in the rocks. We routinely use hydraulic fracturingtechniques in many of our drilling and completion programs. The process is typically regulated by state oil and natural gas commissions, but the EPA, underthe federal Safe Drinking Water Act, has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel. In addition, on June 13, 2016, under the Clean Water Act, the EPA finalized a rule (effective August 29, 2016) that prohibits the discharge of oil andgas wastewaters to publicly-owned treatment works. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and wellconstruction requirements on hydraulic fracturing activities. For example in May 2013, the RRC adopted new rules governing well casing, cementing andother standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. Local government also may seek to adoptordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular orprohibit the performance of well drilling in general or hydraulic fracturing in particular. We believe that we follow applicable standard industry practices andlegal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legalrestrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to complywith such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precludedfrom drilling wells. While these state and local land use restrictions generally cover areas with little recent or ongoing oil and natural gas development, they could leadopponents of hydraulic fracturing to push for similar statewide regimes. If new or more stringent federal, state, or local legal restrictions relating to thehydraulic 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. 29  A number of federal agencies are analyzing, or have been requested to review, environmental issues associated with hydraulic fracturing. The EPA,for example, recently completed a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. In June of 2015,the EPA released an “external review draft” of the study and, in it, said that shale development had not led to “widespread, systemic” problems withgroundwater. On August 11, 2016, however, the EPA Science Advisory Board issued comments on the external review draft, finding that “the EPA did notsupport quantitatively its conclusion about lack of evidence for widespread, systemic impacts of hydraulic fracturing on drinking water resources, and didnot clearly describe the system(s) of interest (e.g., groundwater, surface water), the scale of impacts (i.e., local or regional), nor the definitions of ‘systemic’and ‘widespread.’” In December of 2016, the EPA released the final version of the study, finding, among other things, that there are “certain conditions underwhich impacts from hydraulic fracturing activities can be more frequent or severe,” including “[i]njection of hydraulic fracturing fluids into wells withinadequate mechanical integrity, allowing gases or liquids to move to groundwater resources.” These types of studies, depending on their degree of pursuitand any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms. The EPA also issued an advance notice of proposed rulemaking and undertook a public participation process under the Toxic Substances ControlAct to seek comment on the information that should be reported or disclosed for hydraulic fracturing chemical substances and mixtures and the mechanismsfor obtaining this information. Additionally, on January 7, 2015, several national environmental advocacy groups filed a lawsuit requesting that the EPA addthe oil and natural gas extraction industry to the list of industries required to report releases of certain “toxic chemicals” under the Emergency Planning andCommunity Right-to-Know Act’s Toxics Release Inventory, or TRI, program. On October 22, 2015, the EPA took action on the Environmental IntegrityProject’s October 24, 2012 petition to impose TRI reporting requirements on various oil and natural gas facilities. The EPA granted the petition in part, byagreeing to propose to add natural gas processing facilities to the scope of the TRI program, but rejected the rest of the petition. On December 15, 2015, inlight of that decision, the environmental advocacy groups that had commenced the lawsuit opted to voluntarily dismiss it. On January 6, 2017, EPA issued aproposed rulemaking that would add natural gas processing facilities to the scope of the TRI program. Current water regulation relating to hydraulic fracturing, particularly water source and groundwater regulation, could result in increased operationalcosts, operating restrictions and delays. Hydraulic fracturing uses large amounts of water. It can require between three to five million gallons of water per horizontal well. We may faceregulatory concerns in both the sourcing and the discharge of water used in hydraulic fracturing. In addition, hydraulic fracturing produces water dischargesthat must be treated and disposed of in accordance with applicable regulatory requirements. First, as to sourcing water for hydraulic fracturing, we will need to secure water from the local water supply or make alternative arrangements. Inorder 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 areabecomes subject to water restrictions. We may also seek water from alternative providers supporting the hydraulic fracturing industry. If we have aninsufficient water supply, we will be unable to engage in hydraulic fracturing until such supply is located. Second, 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 increaseoperating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverseeffect on operations and financial performance. Our ability to remove and dispose of water will affect production, and the cost of water treatment and disposalmay affect profitability. The imposition of new environmental initiatives and regulations could also include restrictions on our ability to conduct hydraulicfracturing or disposal of produced water, drilling fluids and other substances associated with the exploration, development and production of oil and naturalgas. We are subject to numerous U.S. federal, state, local and other laws and regulations that can adversely affect the cost, manner or feasibility of doingbusiness. Our operations are subject to extensive federal, state and local laws and regulations relating to the exploration, production and sale of oil and naturalgas, and operating safety. Future laws or regulations, any adverse change in the interpretation of existing laws and regulations or our failure to comply withexisting legal requirements may result in substantial penalties and harm to our business, results of operations and financial condition. We may be required tomake large and unanticipated capital expenditures to comply with governmental regulations, such as: ·land use restrictions;·lease permit restrictions;·drilling bonds and other financial responsibility requirements, such as plugging and abandonment bonds;·spacing of wells;·unitization and pooling of properties; 30  ·safety precautions;·operational reporting; and·taxation. Under these laws and regulations, we could be liable for: ·personal injuries;·property and natural resource damages;·well reclamation cost; and·governmental sanctions, such as fines and penalties. Our operations could be significantly delayed or curtailed and our cost of operations could significantly increase as a result of regulatoryrequirements or restrictions. It is also possible that a portion of our oil and natural gas properties could be subject to eminent domain proceedings or othergovernment takings for which we may not be adequately compensated. See “Business-Regulation of the Oil and Natural Gas Industry” for a more detaileddescription of regulatory laws covering our business. Our operations may incur substantial expenses and resulting liabilities from 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 the release or disposal of materialsinto the environment or otherwise relating to environmental protection. These laws and regulations: ·require the acquisition of a permit before drilling or facility mobilization and commissioning, or injection or disposal commences;·restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and productionand processing activities, including environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessaryfor hydraulic fracturing of wells;·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. Failure to comply with these laws and regulations may result in: ·the assessment of administrative, civil and criminal penalties;·incurrence of investigatory or remedial obligations; and·the imposition of injunctive relief. 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 amaterial adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Under theseenvironmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or propertycontamination regardless of whether we were responsible for the release or contamination or if our operations met previous standards in the industry at thetime they were performed. Our permits require that we report any incidents that cause or could cause environmental damages. See “Business- Regulation ofthe Oil and Natural Gas Industry” for a more detailed description of the environmental laws covering our business. Should we fail to comply with all applicable regulatory agency administered statutes, rules, regulations and orders, we could be subject to substantialpenalties and fines. Under the Domenici-Barton Energy Policy Act of 2005, the FERC has civil penalty authority under Natural Gas Act (the "NGA") to impose penaltiesfor current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our operations have notbeen regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERCjurisdictional facilities to FERC annual reporting requirements. We also must comply with the anti-market manipulation rules enforced by FERC. Additionalrules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Additionally, the Federal TradeCommission has regulations intended to prohibit market manipulation in the petroleum industry with authority to fine violators of the regulations civilpenalties of up to $1 million per day, and U.S. Commodity Futures Trading Commission (the "CFTC") prohibits market manipulation in the marketsregulated by the CFTC, including similar anti-manipulation authority with respect to crude oil swaps and futures contracts as that granted to the CFTC withrespect to crude oil purchases and sales. The CFTC rules subject violators to a civil penalty of up to the greater of $1 million or triple the monetary gain tothe person for each violation. Failure to comply with those regulations in the future could subject us to civil penalty liability, as described in “Business-Regulation of the Oil and Natural Gas Industry.” 31  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 ifthey 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 selltheir 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 negativenews 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;·actions by our stockholders;·changes in our cash flow from operations or earnings estimates;·changes in market valuations of similar companies;·our capital commitments; and·the loss of any of our key management personnel. In addition, market prices of the securities of energy companies, particularly companies like ours without consistent revenues and earnings, havebeen highly volatile and may continue to be highly volatile in the future, some of which may be unrelated to the operating performance of particularcompanies. Additionally, the sale or attempted sale of a large amount of common stock into the market may also have a significant impact on the tradingprice of our common stock. Many of these factors are beyond our control and may decrease the market price of our common stock, regardless of our operating performance. Inthe past, securities class action litigation has often been brought against companies that experience high volatility in the market price of their securities.Whether or not meritorious, litigation brought against us could result in substantial costs, divert management’s attention and resources and harm ourfinancial condition and results of operations. 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 stockwithout 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 one series of preferred stock issued and outstanding, which ranks senior to our common stock withrespect 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 ourcommon stock. To the extent outstanding restricted stock units, warrants or options to purchase our common stock under our 2016 Omnibus Incentive Plan orour 2012 Equity Incentive Plan are exercised, the price vesting triggers under the performance shares granted to our executive officers are satisfied, oradditional shares of restricted stock are issued to our employees, holders of our common stock will experience dilution. Furthermore, if we sell additionalequity or convertible debt securities, such sales could result in further dilution to our existing stockholders and cause the price of our outstanding securitiesto 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 foreseeablefuture. 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. Inthe future, we may agree to further restrictions. Any return to stockholders will therefore be limited to the appreciation of their stock. 32  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 mayadversely 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 publishabout 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 ormore 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 todecline. Further, because of our small market capitalization, it may be difficult for us to attract securities analysts to cover our Company, which couldsignificantly 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 theprice of our common stock. Additionally, Nevada law imposes certain restrictions on mergers and other business combinations between us and any holder of10% or more of our outstanding common stock. Item 1B. Unresolved Staff Comments Not applicable. 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 anycurrently 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. 33  PART II Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Recent Market Prices On July 24, 2017, our common stock commenced trading on the NYSE American under its symbol “LLEX.” From May 9, 2017 to July 23, 2017, ourcommon stock traded on the NYSE MKT under its current symbol “LLEX.” Prior to trading on the NYSE markets, from March 4, 2017 to May 8, 2017, our common stock traded on the NASDAQ Stock Market LLC under thesymbol “LLEX”. From May 27, 2016 to March 13, 2017, our common stock was listed on the OTCQB Venture Marketplace under the symbol “LLEX”. FromFebruary 11, 2016 to May 26, 2016, our common stock traded on The Nasdaq Capital Market (“Nasdaq”) under the symbol “LLEX.” Prior to February 11,2016, our common stock traded on the Nasdaq Global Market under the symbol “LLEX.” The following table shows the high and low reported sales prices of our common stock for the periods indicated. The prices reported in this tablehave been adjusted to reflect the 1-for-10 reverse split of our issued and outstanding common stock, which took effect on June 23, 2016. High Low 2018 First Quarter (through March 5, 2018) $5.44 $3.10 2017 Fourth Quarter $5.50 $4.14 Third Quarter $5.25 $2.96 Second Quarter $5.69 $3.41 First Quarter $5.22 $2.90 2016 Fourth Quarter $3.75 $2.10 Third Quarter $3.51 $1.08 Second Quarter $2.33 $0.50 First Quarter $3.70 $1.00 As of March 5, 2018, there were 158 owners of record of our common stock. We estimate that there are approximately 1,705 beneficial holders of ourcommon stock. Dividend Policy We have never paid cash dividends on our common stock and do not anticipate paying dividends in the foreseeable future. Our current businessplan 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 thediscretion of our Board of Directors, and will be dependent upon our financial condition, results of operations, capital requirements and other factors as ourBoard of Directors may deem relevant at that time. We are currently restricted from declaring any dividends pursuant to the terms of our Riverstone First Lien Credit Agreement, Second Lien CreditAgreement and outstanding preferred stock. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations -“Liquidity and Capital Resources” for further information. Recent Sales of Unregistered Securities We have previously disclosed by way of Quarterly Reports on Form 10-Q and Current Reports on Form 8-K filed with the SEC all sales by us of ourunregistered securities during the year ended December 31, 2017. 34  Equity Compensation Plans Information regarding equity compensation plans is set forth in Item 11 of this Annual Report and is incorporated herein by reference. Item 6. Selected Financial Data Not applicable. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations The following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes includedelsewhere in this Annual Report. The following discussion includes forward-looking statements, including, without limitation, statements relating to ourplans, strategies, objectives, expectations, intentions and resources. Our actual results could differ materially from those discussed in these forward-lookingstatements as a result of many factors, including those discussed under “Risk Factors” and elsewhere in this Annual Report. Overview Lilis is an independent oil and natural gas company focused on the acquisition, development, and production of conventional and unconventionaloil and natural gas properties in the core of the Delaware Basin in Winkler, Loving, and Reeves Counties, Texas and Lea County, New Mexico. Our Business and Strategy We believe our significant inventory of oil and liquids-rich drilling opportunities in the Delaware Basin provide us with a platform for continuedfuture growth. As of December 31, 2017, we had accumulated approximately 35,200 gross (15,700 net) acres in the core of the Delaware Basin in Winkler,Loving, and Reeves Counties, Texas and Lea County, New Mexico, with approximately 33,080 gross (14,430 net) acres in Winkler, Loving, and ReevesCounties, Texas and approximately 2,120 gross (1,270 net) acres in Lea County, New Mexico. Our leasehold position is largely contiguous, which webelieve will enable us to maximize development efficiency and manage our costs. As of December 31, 2017, our proved reserves were approximately 11,453 MBOE (million barrels of oil equivalent). Our proved reserves consist of63% oil, 23% natural gas and 14% NGL. Of those reserves, 37% of our proved reserves are classified as proved developed and approximately 63% areclassified as proved undeveloped. In addition, 34% of our net acreage position was held by production at December 31, 2017, and we operated approximately 90% of our acreage,which we believe gives us significant control over the pace of our development and the ability to design a more efficient and profitable drilling program tomaximize recovery of oil and natural gas. In 2017, we also entered into a long-term gas gathering, processing and purchase agreement with an affiliate of Lucid Energy Group (“Lucid”) tosupport our active drilling program in the Delaware Basin. Lucid will receive, gather and process our gas production from certain production areas located inLea County, New Mexico and in Loving and Winkler Counties, Texas. The agreement secures sufficient term and capacity for Lilis during our developmentand exploitation life cycle of the production areas committed to the new agreement. Our focus is on the development of our oil and natural gas properties in the Delaware Basin, primarily through the drilling of horizontal wells, whichwe believe will provide attractive returns on a majority of our acreage positions. Our drilling program utilizes the development of new horizontal wells acrossseveral potentially productive formations in the Delaware Basin, but initially targeting the Wolfcamp formation. We completed our first horizontal well inJanuary 2017, and have completed six additional wells since that time. On March 31, 2017, we completed the divestiture of all our oil and natural gasproperties located in the DJ Basin to complete our transformation to a pure play Permian Basin oil and natural gas company. As of March 1, 2018, we have accumulated approximately 35,800 gross (16,200 net) acres in what we believe to be the core of the Delaware Basin inWinkler, Loving, and Reeves Counties, Texas and Lea County, New Mexico. Our leasehold position is largely contiguous, allowing us to maximizedevelopment efficiency and manage full cycle finding costs. Approximately 35% of our acreage position is held by production, and we are the namedoperator on nearly 100% of our producing acreage, which gives us significant control over the pace of our development and our ability to design a moreefficient and profitable drilling program that maximizes recovery of hydrocarbons. We expect that substantially all of our estimated 2018 capital expenditure budget will be focused on the development and expansion of ourDelaware Basin acreage and operations. We also plan to continue selectively and opportunistically pursuing strategic acreage acquisitions and organicleasing prospects in the Delaware Basin. Our business objective is to increase stockholder value by growing our Delaware Basin leasehold position, reserves, production and cash flows atattractive rates of return on invested capital. We continue to focus on developing our existing acreage position, gaining additional operational control andexpanding our core assets in the Delaware Basin. We plan to achieve our business objective by implementing a business strategy focused on the following: ·Execute our Operated, Horizontal Drilling Program to Grow Production from our Delaware Basin Leasehold . We plan to drill and develop ourexisting acreage base of approximately 35,800 gross (16,200 net) acres in the Delaware Basin, which we believe will maximize our resourcepotential and value to our stockholders. Through the development of our properties, we seek to de-risk our acreage position and substantiallyincrease our production and cash flow, thereby increasing the value of our properties. Our current leasehold position in the Delaware Basin hassignificant stacked-pay potential, which we believe includes at least seven productive zones. We estimate that all productive zones within ourproperties may support approximately 900 future drilling locations, including over 400 longer lateral locations, and we expect that inventory toincrease with the closing of our pending acquisition from OneEnergy Partners Operating, LLC. We focused our horizontal development in 2017 onthe Wolfcamp B formation but intend to expand our target zones to the Wolfcamp A, Wolfcamp XY and 2nd Bone Spring during 2018. Our long-term gas gathering, processing and purchase agreement with Lucid will support our active drilling program and alleviate production constraints wehave experienced.  ·Focus on Delineation of our Existing Acreage. We plan to focus on the delineation and de-risking of our existing acreage. We expect that ourdrilling activity will also grow our drilling inventory and the identified resource potential of our Delaware Basin properties. We believe that ourcurrent reserves represent only a small portion of the resource potential within our acreage. Our development plan for 2018 contemplates thecontinued delineation of our acreage both geographically and geologically by testing our eastern acreage and by drilling and completing wellswithin additional prospective benches, including the Wolfcamp A, Wolfcamp XY and the 2nd Bone Spring. 35  ·Leverage our Extensive Operational Expertise to Reduce Costs and Enhance Returns. As of December 31, 2017, we operated approximately 90%of our acreage position, giving us significant control over the pace of our development and allowing us to increase value through operational andcost efficiencies. We intend to obtain the highest possible returns on the capital we expend on our development projects using results from the wellswe have completed and the operational expertise of our management team. We also plan to focus on operational efficiencies, including salt waterdisposal and midstream costs, and capital costs of our development wells in order to maximize returns to our stockholders. ·Pursue Selective Acquisitions and Organic Leasing to Grow Our Leasehold Position. Since entering the Delaware Basin in June 2016, we havegrown our net acreage position approximately 376% from 3,400 net (7,200 gross) acres to approximately 16,200 net (35,800 gross) acres as of March1, 2018. On January 30, 2018, we announced our entry into a pending Purchase and Sale Agreement with OneEnergy Partners Operating, LLC toacquire 2,798 net acres in New Mexico, which are largely overlapping or contiguous with our existing properties, for approximately $70 million (the“OEP Acquisition”). Pro forma for the closing of the OEP Acquisition, we expect we expect our acreage position to approximately 19,000 netacres. Our most significant acquisition in 2017 included approximately 4,400 net acres, approximately 92% of which overlapped our existingacreage position. Our acquisitions to date have added approximately 600 drilling locations with multiple stacked pay zones. In addition to ourcontinued evaluation of strategic acquisition opportunities in the Delaware Basin, we will continue to expand our leasehold position through ourorganic leasing program. ·Maintain Fiscal Discipline and Financial Liquidity. We actively manage the level of our development, leasing and acquisition activity in responseto commodity prices, access to capital, and to the performance of our wells. We hold significant control over the pace of our drilling activity as aresult of our operatorship on approximately 90% of our properties. During 2017, we commenced an active hedging program to provide certaintyregarding our cash flow and protect returns from our development activity in the event of decreases in the prices received for our production. Inaddition, we have structured our balance sheet with the intent to reduce our leverage profile over time. The Second Lien Term Loan (as hereinafterdefined) that we primarily relied upon to finance our capital spending and operations in 2017 is convertible, and we announced the issuance of $100million in convertible, perpetual Series C preferred stock on January 31, 2018. In addition, the closing of our recently announced OEP Acquisition,which carries a purchase price of approximately $70 million, will be funded in part with $30 million of common stock to be issued to the seller. We expect that our 2018 capital expenditure budget will be focused on the development and expansion of our Delaware Basin acreage andoperations. We also plan to continue to selectively and opportunistically pursue strategic acreage acquisitions in the Delaware Basin. 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 oneconomically attractive terms. We generate the majority of our revenues from sales of oil, natural gas and NGLs. The prices of these products are criticalfactors to our success and volatility in the prices of oil and natural gas could impact our results of operations. In addition, our business requires substantialcapital to acquire properties and develop our non-producing properties. Declines in these prices would reduce our revenues and result in lower cash inflowwhich would make it more difficult for us to pursue our plans to acquire new properties and develop existing properties. Declines in oil, natural gas, and NGLprices may also adversely affect our ability to obtain additional funding on favorable terms. We believe our long-term agreement with Lucid relating to gas gathering, processing and associated services to support our production operationswill enable us to avoid many potential issues relating to the transportation of our production. Pursuant to our agreement, Lucid will receive, gather andprocess our natural gas production from certain production areas located in Lea County, New Mexico and in Loving and Winkler Counties, Texas. Theagreement secures incremental midstream capacity for us in the production areas committed. We believe we are well-positioned to manage the challenges presented in a lower pricing environment, and we can execute our planned 2018development program and capital expenditures with a combination of cash, cash flow, and proceeds from the exercise of outstanding warrants. Impact of New Tax Reform The New Tax Cuts and Jobs Act (the “Act”) was signed into law on December 22, 2017. The Act makes broad and complex changes to the U.S. taxcode applicable to certain items in 2017 as well as those applicable to 2018 and subsequent years. The applicable items that will affect 2017 include but are not limited to (1) bonus depreciation that will allow for full (100%) expensing of qualifiedproperty acquired and placed in service after September 27, 2017 and (2) limitations on the deductibility of certain executive compensation under IRC Sec.162(m) related to plans after November 2, 2017. The Act also establishes new tax laws that will affect 2018, including but not limited to, (1) reduction of U.S. federal corporate tax rate to twenty onepercent; (2) the elimination of the corporate alternative minimum tax (AMT); (3) limitation on the deduction of interest expense; (4) the repeal of the of thedomestic production activity deduction (DPAD); and (5) limitations on net operating losses (NOL’s) generated after December 31, 2017 to eighty percent oftaxable income. The NOL’s generated in 2018 and beyond are to be carried forward indefinitely with no carryback. The Act preserved the deductibility of Intangible Drilling Costs (IDC’s) for federal income tax purposes. The IDC’s have recently been capitalizedand amortized for tax purposes to avoid negative AMT consequences which would result in the reduction of AMT NOL’s. The Act eliminates AMT for taxyears beginning on or after January 1, 2018 which provides the company latitude in its tax treatment of IDC’s for both current year and future tax planningpurposes. ASC 740 requires the recognition of the tax effects of the Act for annual periods that include December 22, 2017. At December 31, 2017, theCompany has made reasonable estimates of the effects on its existing deferred tax balances. The Company has remeasured certain federal deferred tax assetsand liabilities based on the rates at which they are expected to reverse in the future, which is generally twenty one percent. The provisional amountrecognized related to the remeasurement of its federal deferred tax balance was $9.5 million, which was subject to a valuation allowance at December 31,2017. We will continue to analyze the Act and future IRS regulations, refine its calculations and gain a more thorough understanding of how individualstates are implementing this new law. This further analysis could potentially affect the measurement of deferred tax balances or potentially give rise to newdeferred tax amounts. 36  Results of Operations During the year ended December 31, 2017, we worked actively to increase our natural gas production takeaway and processing capacity for ourexpanding production. We successfully brought online our fifth Wolfcamp B horizontal well located in Lea County, New Mexico. This well is our mostgeologically eastern well and is the closest well to the Central Basin Platform in our current acreage position. As of December 31, 2017, we have productionflowing from our 10 horizontal wells and 14 legacy vertical wells with an estimated productive capacity of approximately 2,494 net BOE per day, on acombined equivalent oil, natural gas and NGL basis. Our production for the year ended December 31, 2017, was temporarily impacted by curtailments resulting from operational and equipment issueswith our current gathering and processing service provider. Primarily as a result of this curtailment of approximately 39.5% of our productive capacity, ouraverage realized production was approximately 1,576 BOE per day for the year ended December 31, 2017. This temporary curtailment is expected to beresolved with expanded available natural gas takeaway and processing capacity under our new contract with Lucid. Production takeaway under the Lucidcontract began in November 2017 from our New Mexico properties and in December 2017 from a portion of our Texas properties. The results of operations of Brushy Resources are included with those of Lilis commencing June 23, 2016. As a result, results of operations for theyear ended December 31, 2017 are not necessarily comparable to the twelve-month period in 2016. Additionally, all discussion related to historicalrepresentations of common stock, unless otherwise noted, gives retroactive effect to the reverse split on June 23, 2016 for all periods presented. Year Ended December 31, 2017 Compared to Year Ended December 31, 2016 The following sets forth selected revenue and production data for the years ended December 31, 2017 and 2016: For the Year Ended December 31, 2017 2016 Change %Change Net production: Oil (Bbls) 371,993 61,088 310,905 509%Natural gas (Mcf) 776,164 332,643 443,521 133%NGL (Bbl) 73,875 11,357 62,518 550%Total (BOE) 575,229 127,863 447,366 350%Average daily production (BOE/d) 1,576 350 1,226 350% Average realized sales price: Oil (Bbl) $47.92 $39.59 $8.33 21%Natural gas (Mcf) 2.74 2.54 0.20 8%NGL (Bbl) 22.49 15.22 7.27 48%Total (BOE) $37.57 $26.87 $10.70 40% Oil, natural gas and NGL revenues (in thousands): Oil revenue $17,826 $2,418 $15,408 637%Natural gas revenue 2,125 844 1,281 152%NGL revenue 1,661 173 1,488 860%Total $21,612 $3,435 $18,177 529% Revenues Total revenue was $21.6 million for the year ended December 31, 2017, as compared to $3.4 million for the year ended December 31, 2016,representing an increase of $18.2 million or 529%. Our increase in revenue was associated primarily with an increase in production and sales of productionfrom our seven Delaware Basin wells placed on production during 2017. Oil revenues increased 637% due to an increase in oil sales volume of 509% and an increase in the average realized per barrel oil price of 21%.Natural gas revenues increased 152% due to an increase in natural gas sales volumes of 133% and an increase in the average realized per Mcf natural gasprice of 8%. NGL revenues increased 860% due to an increase in NGL sales volumes of 551%, and an increase in NGL realized price of 48%. Oil and Natural Gas Production Costs, Production Taxes, Depreciation, Depletion, and Amortization Our production during the year ended December 31, 2017, increased from 127,863 BOE in 2016 to 575,229 BOE in 2017, an increase of 350%. Thisincrease in production was primarily attributable to seven additional wells being completed and placed on production. 37  The following table shows a comparison of production costs for the years ended December 31, 2017 and 2016: For the Year Ended December 31, 2017 2016 Change % Change Production Costs per BOE: Production costs $12.21 $12.43 $(0.22) -2%Production taxes 2.06 (1.30) 3.36 -258%Depreciation, depletion, amortization and accretion 12.21 12.25 (0.04) -0%Total (BOE) $26.48 $23.38 $3.10 13% Operating Expenses Production costs $7,023 $1,590 $5,433 342%Production taxes 1,187 (167) 1,354 -811%General and administrative 49,851 14,227 35,624 250%Depreciation, depletion, amortization and accretion 7,025 1,698 5,327 314%Impairment of evaluated oil and natural gas properties 10,505 4,718 5,787 123%Total Operating Expenses $75,591 $22,066 $53,525 243% Production Costs Production costs were $7.0 million for the year ended December 31, 2017, compared to $1.6 million for the year ended December 31, 2016, anincrease of $5.4 million, or 342%. The increase in production costs was primarily due to increased production volumes associated with the addition of sevenwells placed on production in the Delaware Basin during the year ended December 31, 2017. Production costs per BOE decreased to $12.21 for the yearended December 31, 2017, from $12.43 for the year ended December 31, 2016, a decrease of $0.22 per BOE, or -2%. The ratio change in production volumefrom year ended December 31, 2016 to year ended December 31, 2017 was almost the same as the ratio change in production cost for same periods resultingin the low variance of $0.22 in production cost per BOE and the high production cost per BOE despite significant increase in production during 2017. Production Taxes Production taxes were $1.2 million for the year ended December 31, 2017, compared to $(0.2) million for the year ended December 31, 2016, anincrease of $1.4 million. Currently, ad valorem, severance and conservation taxes range from 1% to 13% based on the state and county from whichproduction is derived. Production taxes per BOE increased to $2.06 per BOE during the year ended December 31, 2017 from $(1.30) per BOE during the yearended December 31, 2016. As discussed above, the increase in production taxes corresponds to the increase in production revenues during the year endedDecember 31, 2017. These taxes are likely to vary in the future depending on the production volumes we generate from various states, and on the possibilitythat any state may raise its production tax rate. The $(0.2) million in production taxes during the year ended December 31, 2016 was due to certain advalorem and severance tax estimates that were higher than the actual amount billed, thus resulting in a tax benefit to us. General and Administrative Expenses General and administrative expenses (“G&A”) were $49.9 million during the year ended December 31, 2017, compared to $14.2 million during theyear ended December 31, 2016, an increase of $35.6 million or 250%. The increase in G&A was primarily due to an increase in payroll of $15.6 million, anapproximate $15.4 million increase in stock-based compensation and an increase of approximately $4.6 million in other G&A during the year endedDecember 31, 2017. The increase of $15.6 million in payroll was primarily attributable to added employees, severance pay and bonuses. The $15.3 millionincrease in stock-based compensation during 2017 was caused in part by added employees and higher average prices of the Company’s stock. 38  Depreciation, Depletion, and Amortization Depreciation, depletion, and amortization (“DD&A”) was $7.0 million during the year ended December 31, 2017, compared to $1.7 million duringthe year ended December 31, 2016, an increase of $5.3 million, or 314%. Our DD&A rate decreased to $12.21 per BOE during the year ended December 31,2017 from $12.25 per BOE during the year ended December 31, 2016. The DD&A expense increased due to an increase in volumes produced by 447,366BOE or 350%, from 127,863 BOE during the year ended December 31, 2016 to 575,229 BOE during the year ended December 31, 2017. Impairment of Evaluated Oil and Natural Gas Properties We recorded impairment charges of $10.5 million and $4.7 million during the years ended December 31, 2017 and 2016, respectively. Under the fullcost method of accounting, we are required on a quarterly basis to determine whether the book value of our oil and natural gas properties is less than or equalto the “ceiling,” based upon the expected after tax present value of the future net cash flows discounted at 10% from our proved reserves. Any excess of thenet book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense. For the year ended December 31,2017, higher capital expenditures with slower than expected development of proved reserves contributed to the excess of net book value of our oil andnatural gas properties over the ceiling resulting in the recognition of an impairment charge of $10.5 million. For the year ended December 31, 2016, theimpairment charge of $4.7 million resulted from the impact of less favorable commodity prices which adversely affected estimated proved reserve volumesand future estimated revenues. Years Ended December 31, 2017 2016 Variance % (In Thousands) Other income (expenses): Other income $18 $90 $(72) -80%Inducement expense - (8,307) 8,307 100%Gain on extinguishment of debt and modification of convertibledebentures - 852 (852) -100%Loss from commodity derivatives, net (1,063) - (1,063) -%Loss from fair value changes of debt conversion and warrant derivatives (6,260) (1,222) (5,038) -100%Loss in fair value changes of conditionally redeemable 6% preferred stock (41) (701) 660 94%Interest expense (18,757) (4,924) (13,833) -281%Total other income (expenses) $(26,103) $(14,212) $(11,891) -84% 39  Inducement Expense During the year ended December 31, 2016, inducement expense of $8.3 million was incurred as a result of debt and equity restructuring inconnection with the Brushy Resources merger. There was no inducement expense incurred during the year ended December 31, 2017. Loss from Commodity Derivatives During the fourth quarter of 2017, oil price derivatives were entered into with counterparties. Upon entering into the derivative transactions, oilprices increased. As a result, for the year ended December 31, 2017, we recorded a loss of $0.2 million on settlements and a loss of $0.9 million on theunsettled position as a result of the changes in fair value of the oil commodity derivatives. During the year ended December 31, 2016, we did not participatein any commodity derivative transactions. Loss from Fair Value Changes of Debt Conversion and Warrant Derivative The change in fair values of derivative instruments comprised a loss of $6.3 million during the year ended December 31, 2017, as compared to a lossof $1.2 million during the year ended December 31, 2016. ·Second Lien Term Loan Derivative Liability. On April 26, 2017, we entered into the Second Lien Credit Agreement (as hereinafter defined). TheSecond Lien Term Loan and the Delayed Draw Term Loans (as such terms are hereinafter defined) funded thereunder during the fourth quarter of2017 included a make-whole premium and a conversion feature, which is required to be recorded as an embedded derivative and bifurcated from itshost contract. These features are therefore recorded as derivative liabilities at fair value for each reporting period based upon values determinedthrough the use of the discounted lattice model. The embedded derivatives were recorded at closing as a derivative liability with a fair value of$65.6 million. At December 31, 2017, the fair value of the derivative liabilities associated with the loan conversion features was $72.7 million. As aresult, we recorded an unrealized loss of $7.1 million on the change in fair value of derivative liabilities associated with the loan conversionfeatures. ·SOS Warrant Liability. On June 23, 2016, in conjunction with the merger with Brushy Resources, we issued to SOS Investment LLC (“SOS”) awarrant to purchase up to 200,000 shares of our common stock at an exercise price of $25.00. The warrant contains a price protection feature thatwill automatically reduce the exercise price if we enter into another agreement pursuant to which warrants are issued with a lower exercise price. Forthe years ended December 31, 2017 and 2016, we incurred an unrealized loss of $0.04 million and an unrealized gain of $0.02 million, respectivelyon the SOS warrant liability. ·Heartland Warrant Liability. On January 8, 2015, we entered into a credit agreement with Heartland Bank (the “Heartland Credit Agreement”). Inconnection with the Heartland Credit Agreement, we issued to Heartland Bank a warrant to purchase up to 22,500 shares of our common stock at anexercise price of $25.00. The warrant contained a price protection feature that would have automatically reduced the exercise price if we entered intoanother agreement pursuant to which warrants were issued with a lower exercise price and would also have triggered an adjustment to the number ofunderlying shares of common stock. On June 14, 2017, we executed an amended and restated warrant agreement with Heartland Bank whereby weissued a warrant to purchase 160,714 of common stock at an exercise price of $3.50 to replace the original warrant to purchase 22,500 shares ofcommon stock to settle a disagreement regarding the fair value change pursuant to the anti-dilution provisions in the original warrant. The amendedand restated warrant agreement no longer contains the same anti-dilution provisions. As a result of the reissuance of the warrants, we recorded $0.04million realized gain and $0.03 million unrealized gain in fair value of the derivative liability related to such warrants during the years endedDecember 31, 2017 and 2016, respectively. ·Bristol Warrant Liability. On September 2, 2014, we entered into a consulting agreement with Bristol Capital, LLC (“Bristol”), pursuant to which weissued Bristol a warrant to purchase up to 100,000 shares of our common stock at an exercise price of $20.00 (or, in the alternative, optionsexercisable for 100,000 shares of common stock, but in no case, both). The agreement had a price protection feature that automatically reduced theexercise price of the warrant if we entered into another consulting agreement pursuant to which warrants were issued with a lower exercise price,which was triggered in year 2016. On March 14, 2017, we issued 77,131 shares of common stock to Bristol pursuant to a settlement agreement for acashless exercise of the warrant. The Bristol warrant was also revalued on March 14, 2017 resulting in a realized gain in fair value of $0.8 millionand decreasing the Bristol derivative liability to $0.4 million. As a result of the cashless exercise, we reclassified the $0.4 million of Bristolderivative liability to additional paid-in capital as of March 31, 2017. For the years ended December 31, 2017 and 2016, we recorded $0.8 millionof realized gain and $0.2 million of unrealized loss on the Bristol warrant, respectively. 40  Interest Expense Interest expense for the year ended December 31, 2017, was $18.8 million, compared to $4.9 million for the year ended December 31, 2016. For theyear ended December 31, 2017, we incurred interest expense of $1.9 million for quarterly interest payments on notes payable and term loans, $6.6 million ofpaid-in-kind interest, $8.5 million related to amortized debt discount on our Second Lien Term Loans and $1.8 million of amortized debt issuance costs, ascompared to the year ended December 31, 2016, when we incurred $1.7 million of interest expense and $3.2 million of non-cash interest relating to amortizeddebt issuance costs on debentures, convertible notes and non-convertible notes. Liquidity and Capital Resources Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions and investors, the sale ofequity and equity derivative securities, and asset dispositions. Our primary uses of capital have been for the acquisition, development, exploration, andexploitation of oil and natural gas properties, in addition to refinancing of debt instruments. Based upon current commodity price expectations for 2018, we believe that with the net proceeds received on January 31, 2018, we will be able tofund our currently planned development program and operations, including our working capital requirements, with a combination of cash and cash flow. Asof March 2, 2018, we have a total cash balance of approximately $83.7 million. Our Board has approved a drilling and completion capital expenditureprogram of $103.2 million for the year ending December 31, 2018, and a total operational capital expenditure program of $115.5 million, excluding capitalexpenditures for leasing activity and acquisitions. In addition, future cash flows are subject to a number of variables, including uncertainty in forecastedproduction volumes and commodity prices. We are the operator for 100% of our 2018 operational capital program, and as a result, the amount and timing of asubstantial portion of our capital expenditures is discretionary. Accordingly, we may determine it prudent to curtail drilling and completion operations in theevent of capital constraints or reduced returns on investment as a result of commodity price weakness. Over the long term, we expect growth in our production as a result of our development program to allow us to fund an increasing portion of ourcapital expenditures from cash flow. We expect that we will fund the remaining portion of our capital expenditures using proceeds from a combination ofdebt, preferred stock, and equity issuance. Information about our cash flows for the year ended December 31, 2017, are presented in the following table (in thousands): Year ended December 31, 2017 2016 Cash provided by (used in): Operating activities $(7,243) $(6,309)Investing activities (147,502) (19,130)Financing activities 160,469 37,067 Net change in cash $5,724 $11,628 Operating activities. For the year ended December 31, 2017, net cash used in operating activities was $7.2 million, compared to $6.3 million for theyear ended December 31, 2016. The increase of $0.9 million in cash used in operating activities was primarily attributable to higher general andadministrative costs as a result of our increased operational activity during 2017. Investing activities. For the year ended December 31, 2017, net cash used in investing activities was $147.5 million compared to $19.1 million forthe year ended December 31, 2016. The $147.5 million in cash used in investing activities was primarily attributable to the following: ·An increase of $68.5 million in drilling and completion costs, including six Delaware Basin wells of which five were completed during the yearended December 31, 2017 compared to one well drilled during the prior year. There were minimal drilling activities in the DJ Basin during the yearended December 31, 2016; ·An increase of $2.2 million in workover costs associated with vertical wells to increase proved reserves; ·An increase of $78.1 million attributable to the acquisition of additional working interests in oil and natural gas leases of which $20.8 million arerelated to oil and natural gas leases in Winkler and Loving Counties, Texas, $49.7 million are related to oil and natural gas leases in Lea County,New Mexico, and $7.6 million are related to oil and leases in Reeves County, Texas; and ·Offset by net proceeds of $1.3 million received from the divestiture of the DJ Basin properties and non-operated properties. Financing activities. For the year ended December 31, 2017, net cash provided by financing activities was $160.5 million compared to cashprovided by financing activities of $37.1 million during the year ended December 31, 2016. The $160.5 million in net cash provided by financing activitiesincluded the following: ·An increase of $6.7 million in net proceeds from the exercise of the accordion features of the First Lien Term Loan (as hereinafter defined); ·An increase of $29.3 million in net proceeds from the Bridge Loan under the amended First Lien Term Loan financing transactions, including $15million in net proceeds from the Incremental Bridge Loan (as hereinafter defined); ·An increase of $79.5 million in net proceeds from the Second Lien Term Loan (as hereinafter defined) financing transactions; 41  ·An increase of $70.0 million in net proceeds from the Delayed Draw Term Loan (as hereinafter defined) under the amended Second Lien CreditAgreement financing transactions.·An increase of $0.7 million in proceeds received from the exercise of stock warrants and stock options;·Proceeds of $18.4 million from the March 2017 Private Placement (as hereinafter defined), net of financing costs. These increases in proceeds were offset by the following: ·Repayment of Series B Preferred Stock (including dividends) in the amount of $2.3 million;·Repayment of the First Lien Term Loan in the amount of $38.1 million; and·Payments of $3.7 million relating to payment of taxes withheld on stock-based compensation. First Lien Credit Agreement and Bridge Loans On September 29, 2016, we entered into a first lien credit agreement by and among us and our wholly owned subsidiaries, Brushy Resources,Impetro Operating and Resources, and the lenders party thereto and T.R. Winston & Company, LLC acting as initial collateral agent (the “First Lien CreditAgreement”). The First Lien Credit Agreement provided for a $50 million three-year senior secured term loan with initial commitments of $31 million. OnFebruary 7, 2017, pursuant to the terms of the First Lien Credit Agreement, we exercised the accordion advance feature, increasing the aggregate principalamount outstanding under the term loan from $31 million to $38.1 million (the “First Lien Term Loan”). In connection with the exercise of the accordion advance feature for $7.1 million, we incurred $0.4 million in commitment fees and also amendedcertain warrants held by the lenders to purchase up to approximately 738,638 shares of common stock, such that the exercise price per share was lowered from$2.50 to $0.01. We accounted for these repriced warrants as additional debt discount for $1.0 million, to be accreted, together with the remaining $0.6million debt discount at December 31, 2016, over the remaining term of the loan. On April 26, 2017, we fully paid off the amount outstanding of $38.1million including accrued interest on the First Lien Term Loan. As a result, for the fiscal year ended December 31, 2017, we fully amortized approximately$3.0 million of remaining deferred financing costs and debt discount. This amount was recorded as a non-cash component of interest expense. On April 24, 2017, and subsequently on April 26, 2017, July 25, 2017, and October 19, 2017, we entered into the first, second, third, and fourthamendments (together, the “First Lien Amendments”), respectively, to the First Lien Credit Agreement. The First Lien Amendments, among other things,added Lilis Operating and Hurricane Resources as guarantors, added certain lenders, and extended further credit in the form of an initial bridge loan in anaggregate principal amount of $15.0 million (the “Initial Bridge Loan”). The Initial Bridge Loan was fully drawn on April 24, 2017, and is secured by thesame first priority liens on substantially all of our assets as the First Lien Term Loan. Additionally, pursuant to the First Lien Amendments, the lenders madefurther extensions of credit, in addition to the currently existing loans under the First Lien Credit Agreement (the “Bridge Loans”), in the form of anadditional, incremental bridge loan in an aggregate principal amount of $15.0 million (the “Incremental Bridge Loan”, and together with the Bridge Loans,the “First Lien Loans”). The First Lien Loans, including the Incremental Bridge Loan, were fully drawn as of October 19, 2017. The First Lien Credit Agreement, as amended, (a) provides that, effective as of October 1, 2017, the unpaid principal of the First Lien Loans will bear(i) cash interest at a rate per annum of 10% and (ii) additional interest at a rate per annum of 6%, payable only in-kind by increasing the principal amount ofthe First Lien Loans by the amount of such interest due on each interest payment date and (b) permits the loans under the Second Lien Credit Agreement toequal an increased amount of up to $175.0 million. The First Lien Loans mature on October 21, 2018 and may be repaid in whole or part at any time at ouroption, subject to the payment of certain specified prepayment premiums. Additionally, the First Lien Loans are subject to mandatory prepayment with thenet proceeds of certain asset sales and casualty events, subject to our right to reinvest the net proceeds of asset sales and casualty events within 180 days. 42  Second Lien Credit Agreement On April 26, 2017, we entered into a Second Lien Credit Agreement by and among us and certain of our subsidiaries, as guarantors (the“Guarantors”), Wilmington Trust, National Association, as administrative agent, and the lenders party thereto (the “Second Lien Credit Agreement”),comprised of convertible loans in an aggregate initial principal amount of up to $125 million. The first tranche of an $80 million term loan (the “Second LienTerm Loan”) was fully drawn and funded on April 26, 2017. The second tranche of up to $45 million in delayed-draw term loans (the “Delayed Draw TermLoan” and, together with the Second Lien Term Loan, the “Second Lien Loans”) was funded on October 4, 2017 and an additional $25 million on November10, 2017. Each tranche of Second Lien Loans will bear interest at a rate per annum of 8.25%, compounded quarterly in arrears and payable only in-kind byincreasing the principal amount of the loan by the amount of the interest due on each interest payment date. On October 3, 2017, we entered into a first amendment to the Second Lien Credit Agreement (“Amendment No. 1 to the Second Lien CreditAgreement”). The purpose of Amendment No. 1 to the Second Lien Credit Agreement is to waive certain conditions precedent to the drawing of the DelayedDraw Term Loan under the Second Lien Credit Agreement and to provide for the funding of such Delayed Draw Term Loan upon the signing of the leaseacquisition agreement with KEW Drilling, a Delaware limited partnership. We borrowed the full $45.0 million of the availability under the Delayed DrawTerm Loan on October 4, 2017. On October 19, 2017, we entered into a second amendment to the Second Lien Credit Agreement (“Amendment No. 2 to the Second Lien CreditAgreement”). Amendment No. 2 to the Second Lien Credit Agreement permits us to incur the Incremental Bridge Loan under the First Lien Credit Agreement. On November 10, 2017, we entered into a third amendment to the Second Lien Credit Agreement (“Amendment No. 3 to the Second Lien CreditAgreement”). Amendment No. 3 to the Second Lien Credit Agreement increased by $25 million the amount of Delayed Draw Term Loans available forborrowing under the Second Lien Credit Agreement. The additional $25.0 million of Delayed Draw Term Loan was drawn on November 10, 2017. Proceedsof the additional loans may be used to fund oil and natural gas property acquisitions, subject to certain limitations, drilling and completions costs or for othergeneral corporate purposes. The Second Lien Loans are secured by second priority liens on substantially all of our and our Guarantors’ assets, and all of the obligationsthereunder are unconditionally guaranteed by each of the Guarantors. The Second Lien Loans mature on April 26, 2021. The Second Lien Loans are subjectto mandatory prepayment with the net proceeds of certain asset sales, casualty events and debt incurrences, subject to our right to reinvest the net proceeds ofasset sales and casualty events within 180 days and, in the case of asset sales and casualty events, prepayment of the Bridge Loan. We may not voluntarilyprepay the Second Lien Loans prior to March 31, 2019, except (a) in connection with a Change of Control (as defined in the Second Lien Credit Agreement)or (b) if the closing price of our common stock on the principal exchange on which it is traded has been equal to or greater than 110% of the Conversion Price(as defined below) for at least 20 of the 30 trading days immediately preceding the prepayment. We are required to pay a make-whole premium in connectionwith any mandatory or voluntary prepayment of the Loans. Each tranche of the Second Lien Loans is separately convertible at any time, in full and not in part, at the option of Värde Partners, Inc., the LeadLender, as follows: ·70% of the principal amount of each tranche of Second Lien Loans, together with accrued paid-in-kind interest and a make-whole premium on suchprincipal amount (the “Conversion Sum”), will convert into a number of newly issued shares of common stock determined by dividing the total ofthe Conversion Sum by $5.50 (subject to certain customary adjustments, the “Conversion Price”); and ·30% of the Conversion Sum will convert on a dollar for dollar basis into a new second lien term loan (the “Take Back Loans”). The terms of the Take Back Loans will be substantially the same as the terms of the Second Lien Loans, except that the Take Back Loans will not beconvertible and will bear interest payable in cash at a rate of LIBOR plus 9% (subject to a 1% LIBOR floor). Additionally, we will have the option to convert the Second Lien Loans, in whole or in part, into shares of common stock at any time or from time totime if, at the time of exercise of our conversion option, the closing price of the common stock on the principal exchange on which it is traded has been atleast 150% of the Conversion Price then in effect for at least 20 of the 30 immediately preceding trading days. Conversion at our option will occur on thesame terms as conversion at the lender’s option. As discussed in Note 6 to our consolidated financial statements in Item 8 of this Annual Report, we separately account for the embedded conversionfeatures as a derivative instrument in accordance with accounting guidance relating to recording embedded derivatives at fair value. The initial fair value ofthe embedded derivatives was recorded as a debt discount to the convertible Second Lien Term Loan. The debt discount is amortized over the term of theSecond Lien Term Loan using effective interest rate. Restrictive Covenants As of December 31, 2017, the Company’s First Lien Credit Agreement and Second Lien Credit Agreement contained various covenants, includingrestrictions on additional indebtedness, payment of cash dividends on common stock and preferred stock, and maintenance of certain financial ratios. TheFirst Lien Credit Agreement, as amended, required that, commencing with the testing period ending at December 31, 2018, we satisfy an asset coverage ratio(“ACR”) test by maintaining an ACR of 1.00 to 1.00 or greater. In addition, the Second Lien Credit Agreement requires us to maintain, commencing with thetesting period ending June 30, 2018, an ACR of 1.00 to 1.00. or greater. 43  Private Placement On February 28, 2017, we entered into a Securities Subscription Agreement (the “Subscription Agreement”) with certain institutional and accreditedinvestors in connection with a private placement (the “March 2017 Private Placement”) to sell 5.2 million units, consisting of approximately 5.2 millionshares of common stock and warrants to purchase an additional approximately 2.6 million shares of common stock. Each unit consists of one share ofcommon stock and a warrant to purchase 0.50 shares of common stock, at a price per unit of $3.85. Each warrant has an exercise price of $4.50 and may besubject to redemption by us, upon prior written notice, if the price of our common stock closes at or above $6.30 for 20 trading days during a consecutive 30trading day period. As of December 31, 2017, we received aggregate gross proceeds of $20.0 million and issued 5,194,821 shares of common stock andwarrants to purchase 2,597,420 shares of common stock. Subsequent Events Purchase and Sale Agreement On January 30, 2018, we entered into a Purchase and Sale Agreement (the “Purchase and Sale Agreement”) with OneEnergy Partners Operating, LLC(“OEP”), pursuant to which we agreed to purchase from OEP, and OEP agreed to sell to us, certain oil and gas properties and related assets for a purchase priceof $70 million, subject to customary purchase price adjustments (the “OEP Acquisition”). The unadjusted purchase price for the OEP Acquisition will consist of $40 million in cash and $30 million in shares of our common stock , valued ata price per share equal to (i) the volume-weighted average trading price of the common stock on the NYSE American for the 20 consecutive trading daysending on and including the first trading day preceding the closing date of the OEP Acquisition multiplied by (ii) 1.05, but in no event may such price beless than $4.25 or greater than $5.25. We intend to fund the cash portion of the purchase price with a portion of the net proceeds from the transactiondescribed under “Preferred Stock Issuance” below. The properties to be acquired by us pursuant to the Purchase and Sale Agreement consist of approximately 2,798 net leasehold acres in the DelawareBasin in Lea County, New Mexico, with average daily net production for the year ended December 31, 2017 of approximately 425 barrels of oil equivalent. The Purchase and Sale Agreement contains customary terms and conditions, including title and environmental due diligence provisions,representations and warranties, covenants and indemnification provisions. The Purchase and Sale Agreement also includes registration rights provisionspursuant to which, among other matters, (i) we will be required to file with the SEC a registration statement under the Securities Act, registering for resale theshares of common stock issued to OEP pursuant to the Purchase and Sale Agreement and (ii) OEP will have piggyback rights to include shares of commonstock in certain underwritten offerings. We expect to close the OEP Acquisition in March 2018, subject to the satisfaction of customary closing conditions. Preferred Stock Issuance On January 30, 2018, we entered into a Securities Purchase Agreement (the “Securities Purchase Agreement”) with certain private funds affiliatedwith Värde Partners, Inc. (the “Purchasers”), pursuant to which we agreed to issue and sell to the Purchasers, and the Purchasers agreed to purchase from us,100,000 shares of a newly created series of preferred stock of the Company, designated as “Series C 9.75% Convertible Participating Preferred Stock” (the“Series C Preferred Stock”), for a purchase price of $1,000 per share, or an aggregate of $100 million. Värde Partners, Inc. is the lead lender, and certainprivate funds affiliated with Värde Partners, Inc. are lenders, under our Second Lien Credit Agreement. Closing of the issuance and sale of the shares of Series C Preferred Stock pursuant to the Securities Purchase Agreement occurred on January 31,2018. We intend to use the net proceeds from the sale of the shares of Series C Preferred Stock to fund the cash portion of the consideration for the OEPAcquisition and a portion of our 2018 capital expenditures budget. The terms of the Series C Preferred Stock are set forth in the Certificate of Designation for the Series C Preferred Stock (the “Certificate ofDesignation”) filed by us with the Secretary of State of the State of Nevada on January 31, 2018. The following is a description of the material terms of theSeries C Preferred Stock and the Securities Purchase Agreement. Ranking. The Series C Preferred Stock ranks senior to our common stock with respect to dividends and rights on the liquidation, dissolution orwinding up of the Company. 44  Stated Value. The Series C Preferred Stock has a per share stated value of $1,000, subject to increase in connection with the payment of dividends inkind as described below (the “Stated Value”). Dividends. Holders of shares of Series C Preferred Stock will be entitled to receive cumulative preferential dividends, payable and compoundedquarterly 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 untilApril 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 our 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. We expect topay dividends in kind for the foreseeable future. In addition to these preferential dividends, holders of shares of Series C Preferred Stock will be entitled toparticipate in any dividends paid on the common stock on an as-converted basis. Optional Redemption. We have the right to redeem the Series C Preferred Stock, in whole or in part at any time (subject to certain limitations onpartial 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 redeemedduring 2019 or (c) 130% if redeemed after 2019, plus (ii) accrued and unpaid dividends thereon and any other amounts payable by us in respect thereof (the“Optional Redemption Amount”). The Series C Preferred Stock is perpetual and is not mandatorily redeemable at the option of the holders, except upon theoccurrence of a Change of Control (as defined in the Certificate of Designation) as described below. Conversion. Each share of Series C Preferred Stock is convertible at any time at the option of the holder into a number of shares of common stockequal to (i) the applicable Optional Redemption Amount divided by (ii) a conversion price of $6.15, subject to adjustment (the “Conversion Price”). TheConversion Price will be subject to proportionate adjustment in connection with stock splits and combinations, dividends paid in stock and similar eventsaffecting the outstanding common stock. Additionally, the Conversion Price will be adjusted, based on a broad-based weighted average formula, if we issue,or are deemed to issue, additional shares of common stock for consideration per share that is less than the lesser of (i) $5.25 and (ii) the Conversion Price thenin effect, subject to certain exceptions and to the Share Cap (as defined below). We have the right to force the conversion of any or all of the outstanding shares of Series C Preferred Stock if (i) the volume-weighted average priceper share of the common stock on the principal exchange on which it is then traded has been at least 140% of the Conversion Price then in effect for at least20 of the 30 consecutive trading days immediately preceding the exercise by us of the forced conversion right and (ii) certain trading and other conditionsare satisfied. To comply with rules of the NYSE American, the Certificate of Designation provides that the number of shares of common stock issuable onconversion of a share of Series C Preferred Stock may not exceed (i) the Stated Value divided by (ii) $4.42 (which was the closing price of the common stockon the NYSE American on January 30, 2018) (the “Share Cap”) prior to approval by our stockholders of the issuance of shares of common stock in excess ofthe Share Cap upon conversion of shares of Series C Preferred Stock. The Securities Purchase Agreement requires us to seek such stockholders approval at ournext special or annual meeting of stockholders, which must occur within six months after the initial issuance of the Series C Preferred Stock. We intend toseek such stockholders approval at our 2018 annual meeting of stockholders. Change of Control. Upon the occurrence of a Change of Control (as defined in the Certificate of Designation), each holder of shares of Series CPreferred Stock will have the option to: ·cause us to redeem all of such holder’s shares of Series C Preferred Stock for cash in an amount per share equal to (i) the Optional RedemptionAmount plus (ii) 2.5% of the Stated Value, in each case as in effect immediately prior to the Change of Control; ·convert all of such holder’s shares of Series C Preferred Stock into the number of shares of common stock into which such shares are convertibleimmediately prior to the Change of Control; or ·continue to hold such holder’s shares of Series C Preferred Stock, subject to any adjustments to the Conversion Price or the number and kind ofsecurities or other property issuable upon conversion resulting from the Change of Control and to our or our successor’s optional redemption rightsdescribed above. Liquidation Preference. Upon any liquidation, dissolution or winding up of the Company, holders of shares of Series C Preferred Stock will beentitled to receive, prior to any distributions on our common stock or other capital stock ranking junior to the Series C Preferred Stock, an amount per shareof Series C Preferred Stock equal to the greater of (i) the Optional Redemption Amount then in effect and (ii) the amount such holder would receive in respectof the number of shares of common stock into which a share of Series C Preferred Stock is then convertible. 45  Board Designation Rights. The Certificate of Designation provides that holders of shares of Series C Preferred Stock will have the right, votingseparately as a class, to designate (i) two members of our board of directors (the “Board”) for as long as the shares of common stock issuable on conversion ofthe outstanding shares of Series C Preferred Stock represent at least 15% of the outstanding shares of common stock (giving effect to conversion of alloutstanding shares of Series C Preferred Stock) and (ii) one member of the Board for as long as the shares of common stock issuable on conversion of theoutstanding shares of Series C Preferred Stock represent at least 7.5% of the outstanding shares of common stock (giving effect to conversion of alloutstanding shares of Series C Preferred Stock). The Securities Purchase Agreement separately grants to the Purchasers substantially identical rights to appoint members of the Board as long as thePurchasers and their affiliates beneficially own (as defined in Rule 13d-3 under the Securities Exchange Act of 1934, as amended) shares of common stockissued or issuable upon conversion of shares of Series C Preferred Stock representing the 15% and 7.5% thresholds of the outstanding common stockdescribed above. However, the number of members of the Board the Purchasers have the right to designate under the Securities Purchase Agreement will bereduced by the number of directors holders of shares of Series C Preferred Stock have the right to appoint under the Certificate of Designation. The Board members designated by holders of shares of Series C Preferred Stock pursuant to the Certificate of Designation or by the Purchaserspursuant to the Securities Purchase Agreement must be reasonably acceptable to the Board and its Nominating and Corporate Governance Committee, actingin good faith, but any investment professional of Värde Partners, Inc. or its affiliates will be deemed to be reasonably acceptable. In addition, such Boarddesignees must satisfy applicable SEC and stock exchange requirements and comply with our corporate governance guidelines. In accordance with our bylaws, the Board has increased the number of directors constituting the entire Board from seven to nine to allow for theappointment of the Board members designated by the holders of shares of Series C Preferred Stock. We are required to appoint the two Board membersinitially designated by the holders of shares of Series C Preferred Stock within ten business days after notice to the us from the holders of the identity of suchdesignees, subject to confirmation that such designees meet the qualifications described above. Pursuant to the terms of the Securities Purchase Agreement,Markus Specks and John Johanning were designated by the Purchasers for appointment to the Board. Mr. Specks and Mr. Johanning serve as managingdirectors and technical director, respectively, of Värde Partners, Inc. and/or its affiliates. On March 1, 2018, the Board approved the appointments of Mr.Specks and Mr. Johanning to the Board. Voting Rights; Negative Covenants. In addition to the Board designation rights described above, holders of shares of Series C Preferred Stock will beentitled to vote with the holders of shares of our common stock, as a single class, on all matters submitted for a vote of holders of shares of common stock.When voting together with the common stock, each share of Series C Preferred Stock will entitle the holder to a number of votes equal to (i) the Stated Valueas of the applicable record date or other determination date divided by (ii) $4.42 (the closing price of the common stock on the NYSE American on January30, 2018). The Certificate of Designation provides that, as long as any shares of Series C Preferred Stock are outstanding, we may not, without the prioraffirmative vote or prior written consent of the holders of a majority of the outstanding shares of Series C Preferred Stock: ·amend our articles of incorporation or bylaws in any manner that materially and adversely affects any rights, preferences, privileges or votingpowers of the Series C Preferred Stock or holders of shares of Series C Preferred Stock; ·issue, authorize or create, or increase the issued or authorized amount of, the Series C Preferred Stock, any class or series of capital stock rankingsenior to or in parity with the Series C Preferred Stock, or any security convertible into or evidencing the right to purchase any shares of Series CPreferred Stock or any such senior or parity stock, other than equity, the proceeds of which, are used to immediately redeem all of the outstandingshares of Series C Preferred Stock pursuant to our 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 subsidiariesto redeem or repurchase, shares of our common stock or any other shares of our capital stock ranking junior to the Series C Preferred Stock, subjectto certain exceptions; ·authorize, issue or transfer, or permit any of our controlled subsidiaries to authorize, issue or transfer, any equity (including any obligation orsecurity convertible into, exchangeable for or evidencing the right to purchase any such equity) in any of our subsidiaries other than (i) equityissued or transferred to us or one of our wholly-owned subsidiaries or (ii) equity, the proceeds of which, are used to immediately redeem all of theoutstanding shares of Series C Preferred Stock pursuant to the our optional redemption rights described above; or ·subject to certain exceptions, modify the number of directors constituting the entire Board at any time when holders of shares of Series C PreferredStock have the right to designate a member of the Board. 46  The Certificate of Designation further provides that, as long as shares of Series C Preferred Stock having an aggregate Optional Redemption Amountof at least $50,000,000 are outstanding, we may not, and may not permit any of our controlled subsidiaries to, without the prior affirmative vote or priorwritten consent of the holders of a majority of the outstanding shares of Series C Preferred Stock: ·subject to certain exceptions, incur indebtedness or permit to exist any liens on our or our subsidiaries’ assets or properties; ·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 Series C Preferred Stock under any credit facility, indenture or other similar instrument that would be more restrictive on the payment ofdividends on, or redemption of, shares of Series C Preferred Stock than those existing as of the date on which shares of Series C Preferred Stock werefirst issued; ·liquidate or dissolve the Company; ·enter into any material new line of business or fundamentally change the nature of our business, including any acquisition of oil and gas propertiesoutside the Permian Basin; or ·enter into certain transactions with our affiliates unless made on an arm’s-length basis and approved by a majority of the disinterested members ofthe Board. Transfer Restrictions. The Certificate of Designation provides that shares of Series C Preferred Stock and shares of common stock issued onconversion of shares of Series C Preferred Stock may not be transferred by the holder of such shares, other than to an affiliate of such holder, prior to July 31,2018. On and after July 31, 2018, such shares will be freely transferable, subject to applicable securities laws. Standstill. The Securities Purchase Agreement includes a customary standstill provision pursuant to which the Purchasers agreed that they will not,directly or indirectly, take certain actions with respect to us or our securities until the earlier of (i) the date on which the Purchasers and their affiliates are nolonger entitled to designate any member of the Board pursuant to the Certificate of Designation or the Securities Purchase Agreement and (ii) our failure topay dividends on the Series C Preferred Stock in full in cash on any dividend payment date occurring after April 26, 2021. Other Terms. The Securities Purchase Agreement contains other terms, including representations, warranties and covenants, that are customary for atransaction of this sort. Registration Rights Agreement On January 31, 2018, in connection with the closing of the issuance of shares of Series C Preferred Stock pursuant to the Securities PurchaseAgreement, we entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with the Purchasers pursuant to which, among othermatters, we will be required to file with the SEC a registration statement under the Securities Act registering for resale the shares of common stock issuableupon conversion of shares of Series C Preferred Stock. The Registration Rights Agreement also grants to the Purchasers demand and piggyback rights withrespect to certain underwritten offerings of our common stock and contains customary covenants and indemnification and contribution provisions. Riverstone First Lien Credit Agreement On January 30, 2018, we entered into an Amended and Restated Senior Secured Term Loan Credit Agreement (the “Riverstone First Lien CreditAgreement”) by and among us, our subsidiaries party thereto as guarantors, Riverstone Credit Management LLC, as administrative agent and collateral agent,and the lenders party thereto. Effective at closing under the Riverstone First Lien Credit Agreement, which occurred on January 31, 2018, the Riverstone FirstLien Credit Agreement amended and restated the First Lien Credit Agreement. Pursuant to the Riverstone First Lien Credit Agreement, the lenders thereunder agreed to make term loans to us in the aggregate principal amount of$50 million (the “Riverstone First Lien Loans”), all of which were funded in full at closing at an original issue discount of 1.0% of the principal amount. TheRiverstone First Lien Credit Agreement provides the potential for additional term loans of up to $30 million, as requested by us and subject to certainconditions, which additional loans were uncommitted at closing. 47  We used approximately $31.5 million of the proceeds of the Riverstone First Lien Loans to repay in full our obligations under and retire the FirstLien Credit Agreement, which was scheduled to mature in October 2018. We may use the remaining proceeds for capital expenditures, acquisitions and othergeneral corporate purposes, including payment of transaction expenses. Amendment to Second Lien Credit Agreement On January 31, 2018, we entered into a fourth amendment to the Second Lien Credit Agreement (“Amendment No. 4 to the Second Lien CreditAgreement”). The purpose of Amendment No. 4 to the Second Lien Credit Agreement was to, among other matters: ·permit us to enter the Riverstone First Lien Credit Agreement and incur the Riverstone First Lien Loans and related liens; ·permit us to issue the Series C Preferred Stock; and ·after the issuance of the Series C Preferred Stock pursuant to the Securities Purchase Agreement, reduce from two to one the maximum number ofmembers of the Board the lenders under the Second Lien Credit Agreement will have the right to appoint following the conversion of theconvertible loans under the Second Lien Credit Agreement. Amendments to Riverstone First Lien Credit Agreement and Second Lien Credit Agreement On February 20, 2018, we entered into the following amendments to our existing credit agreements: (i) Amendment No. 1 to the Riverstone FirstLien Credit Agreement and (ii) Amendment No. 5 to the Second Lien Credit Agreement. Pursuant to these amendments and a consent letter received from thePurchasers, in their capacity as the holders of all of the issued and outstanding shares of Series C Preferred Stock, we have been granted the right to repurchaseshares of our common stock for an aggregate purchase price up to $10 million (subject to certain exceptions and conditions). The commencement of any repurchase of shares of our common stock will be subject to compliance with applicable law, Board approval, and marketconditions. Departure of Executive Officers On February 16, 2018, Ariella Fuchs ceased serving as our Executive Vice President, General Counsel, and Secretary. We entered into an agreementwith Ms. Fuchs pursuant to which she will receive severance and other consideration pursuant to the terms of her employment agreement and the acceleratedvesting of 247,500 stock options and 198,000 shares of restricted stock under stock award agreements plus additional nominal consideration. On March 6, 2018, Brennan Short ceased serving as our Chief Operating Officer. His responsibilities have been assumed by our current managementand our existing consultants. 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 theindustry puts pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do allassociated costs. Material changes in prices impact the current revenue stream, estimates of future reserves, borrowing base calculations of bank loans and thevalue of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and their ability toraise capital, borrow money and retain personnel. We anticipate business costs will vary in accordance with commodity prices for oil and natural gas, and theassociated increase or decrease in demand for services related to production and exploration. Off-Balance Sheet Arrangements As of December 31, 2017, we did not have any off-balance sheet arrangements, and it is not anticipated that we will enter into any off-balance sheetarrangements. 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 thedisclosure of contingent assets and liabilities at the date of our financial statements and the reported amounts of revenues and expenses during the reportingperiod. 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 financialcondition and results of operation. We consider an accounting estimate or judgment to be critical if (i) it requires assumptions to be made that were uncertainat 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 ourresults of operations or financial condition. Use of Estimates The preparation of financial statements in conformity with GAAP requires us to make a number of estimates and assumptions relating to the reportedamounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts ofrevenues and expenses during the reporting period. Actual results could differ significantly from those estimates. Management evaluates estimates andassumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. 48  Our most significant financial estimates are associated with our estimated proved oil and natural gas reserves, assessments of impairment in thecarrying value of undeveloped acreage and proven properties. There are also significant financial estimates associated with the valuation of our options andwarrants, inducement transactions, and estimated derivative liabilities. 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 costsrelated 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 ofexploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimatedproved oil and natural gas reserves. Under the full cost method of accounting, capitalized oil and natural gas property costs less accumulated depletion andnet 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 andnatural gas reserves less the future cash outflows associated with the asset retirement obligations that have been accrued on the balance sheet plus the cost, orestimated fair value if lower, of unproved properties. Should capitalized costs exceed this ceiling, impairment would be recognized. Under the SEC rules, weprepared our oil and natural gas reserve estimates as of December 31, 2017, using the average, first-day-of-the-month price during the 12-month period endedDecember 31, 2017. Estimating accumulations of oil and natural gas is complex and is not exact because of the numerous uncertainties inherent in the process. Theprocess relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technicaldata can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as oil and natural gas prices, drillingand operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of the quality and quantity ofavailable data; the interpretation of that data, the accuracy of various mandated economic assumptions; and the judgment of the persons preparing theestimate. We believe estimated reserve quantities and the related estimates of future net cash flows are among the most important estimates made by anexploration 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, naturalgas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from knownreservoirs under existing economic and operating conditions. We determine anticipated future cash inflows and future production and development costs byapplying benchmark prices and costs, including transportation, quality and basis differentials, in effect at the end of each quarter to the estimated quantitiesof 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 thatdepends upon the purpose for which the reserve estimates will be used. For example, the standardized measure calculation requires us to apply a 10%discount rate. Although reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than thoseof established proved producing oil and natural gas properties, we make considerable effort to estimate our reserves, including through the use ofindependent reserves engineering consultants. We expect that quarterly reserve estimates will change in the future as additional information becomesavailable 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 reserve quantities at all quarterly periods for theestimated impact of acquisitions and dispositions. Changes in depletion, depreciation or impairment calculations caused by changes in reserve quantities ornet 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 arecapitalized into a single cost center referred to as a full cost pool. These costs include land acquisition costs, geological and geophysical expenses, carryingcharges 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 theestimated gross proved reserves as determined by independent petroleum engineers. For this purpose, we convert our petroleum products and reserves to acommon unit of measurement. Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. This undeveloped acreage is assessedquarterly to ascertain whether impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of theproperty or the amount of the impairment is added to the amortization base and becomes subject to the depletion calculation. 49  Proceeds from the sale of oil and natural gas properties are applied against capitalized costs, with no gain or loss recognized, unless the sale wouldalter 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 incometaxes, 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,plus the cost, or estimated fair value if lower, of unproved properties. Should capitalized costs exceed this ceiling, we would recognize impairment. 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 valuerecognized currently in earnings. Although derivative instruments are used by the Company to manage the price risk attributable to its expected oil andnatural gas production, those derivative instruments have not been designated as accounting hedges under the accounting guidance. All of our derivativesare accounted for as mark-to-market activities. Under ASC Topic 815, “Derivatives and Hedging,” these instruments are recorded on the consolidated balancesheets at fair value as either short term or long-term assets or liabilities based on their anticipated settlement date. The Company nets derivative assets andliabilities by commodity for counterparties where a legal right to such offset exists. Changes in the derivatives' fair values are recognized in current earningssince 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 fromthe Loan, as defined in Note 4 to our consolidated financial statements in Item 8 of this Annual Report on Form 10-K, and accounted for separately from thedebt. Additionally, warrants issued to SOSV Investment LLC (“SOS”) to purchase up to 200,000 shares of the Company’s common stock contain a priceprotection feature that will automatically reduce the exercise price should the Company enter into another agreement pursuant to which warrants are issued ata lower exercise price. The price protection feature has been recognized as an embedded derivative and accounted for separately. Revenue Recognition We recognize revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasiveevidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller’s price to the buyer is fixed or determinable, and(iv) collectability is reasonably assured. We use the entitlements method of accounting for oil, natural gas, and NGL revenues. Sales proceeds in excess of the Company’s entitlement areincluded in other liabilities, and the Company’s share of sales taken by others is included in other assets in the accompanying consolidated balance sheets.We had no material oil, or NGL entitlement assets or liabilities as of December 31, 2017 or 2016. Recently Issued Accounting Pronouncements For a discussion of recently adopted accounting standards and recent accounting standards not yet adopted, see “Note 1 - Summary of SignificantAccounting Policies” to our consolidated financial statements in Item 15 of this Annual Report. Item 7A.Quantitative and Qualitative Disclosures About Market Risk Not applicable. Item 8.Financial Statements and Supplementary Data Our financial statements appear immediately after the signature page of this Annual Report, which are incorporated herein by reference. See “Indexto Financial Statements” included in this Annual Report. Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 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 disclosurecontrols and procedures pursuant to Rule 13a-15 under the Exchange Act. Based on that evaluation, and as described below, management identified amaterial weakness in the Company’s internal control over financial reporting further discussed below. Internal control over financial reporting is an integralcomponent of the Company’s disclosure controls and procedures. As a result of this material weakness, the Company’s Chief Executive Officer and ChiefFinancial Officer concluded that, as of the end of the period covered by this Annual Report, the Company’s disclosure controls and procedures were noteffective as of December 31, 2017. Management concluded that the consolidated financial statements included in this Annual Report fairly present, in all material respects, thefinancial position of the Company at December 31, 2017 and 2016, and the consolidated results of operations and cash flows for each of the two years in theperiod ended December 31, 2017 in conformity with U.S. GAAP. 50  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). Even an effective system of internal control over financial reporting, no matter how well designed, hasinherent limitations, including the possibility of human error, circumvention of controls or overriding of controls and, therefore, can provide only reasonableassurance with respect to reliable financial reporting. Furthermore, the effectiveness of a system of internal control over financial reporting in future periodscan change as conditions change. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting such thatthere is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. Our management, with the participation of our Chief Executive Officer and Chief Financial Officer assessed the effectiveness of our internal controlover financial reporting, as of December 31, 2017, 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 andthose criteria, our management determined that our internal control over financial reporting was not effective as of December 31, 2017 as a result of thematerial weakness discussed below. A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonablepossibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis. Duringthe audit of our internal control over financial reporting for the year ended December 31, 2017, errors were identified in the Company’s computation of thefull cost ceiling test limitation. Design and operating effectiveness deficiencies failed to identify the computational errors which primarily related to thetreatment of wells-in-process and future income tax effects. Management has concluded these deficiencies in internal control over financial reportingconstituted a material weakness. The errors did not affect the reported results of operations or disclosures in any interim or annual period. BDO USA, LLP, an independent registered public accounting firm, has audited our internal control over financial reporting as of December 31,2017, as stated in their attestation report set forth under the caption “Report of Independent Registered Public Accounting Firm on Internal Control overFinancial Reporting.” Changes in Internal Control Over Financial Reporting The Company identified a material weakness during the quarter ending June 30, 2017, as described in our Form 10-Q. The Company took measuresto remediate the material weakness during the quarters ended September 30, 2017 and December 31, 2017, which included the use of comprehensivechecklists to identify and review complex accounting issues, additional guidance obtained from expert accounting technical consultant with respect to theappropriate application of GAAP on non-routine and complex transactions. Management believes that the measures described above have remediated the material weakness identified in our June 30, 2017 Form 10-Q. There has been no other change in our internal control over financial reporting during the three months ended December 31, 2017 that hasmaterially affected, or is reasonably likely to materially affect, our internal control over financial reporting. Plan of Remediation of Material Weakness Management has identified remediation steps, including enhanced analytical analysis and improved management review of the full cost ceiling testcalculation in order to remediate this material weakness. Item 9B. Other Information None. PART III Item 10. Directors, Executive Officers and Corporate Governance The following table sets forth information regarding our executive officers, certain other officers and directors as of March 7, 2018. The Boardbelieves that all the directors named below are highly qualified and have the skills and experience required for effective service on the Board. The directors’and officers’ individual biographies below contain information about their experience, qualifications and skills that led the Board to nominate, elect orappoint them. Name Age Director Since Position Ronald D. Ormand 59 2015 Executive Chairman of the Board of DirectorsNuno Brandolini 64 2014 DirectorR. Glenn Dawson 61 2016 DirectorGeneral Merrill McPeak 82 2015 DirectorPeter Benz 57 2016 DirectorMark Christensen 49 2017 DirectorG. Tyler Runnels 62 2017 DirectorJohn Johanning 32 2018 DirectorMarkus Specks 33 2018 DirectorJames Linville 52 Chief Executive OfficerJoseph C. Daches 51 Executive Vice President, Chief Financial Officer and TreasurerSeth Blackwell 30 Executive Vice President of Land and Business Development  51  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 isduly elected and qualified. Officers are elected by, and serve at the discretion of, our Board of Directors (our “Board”). None of the above individuals has anyfamily relationship with any other. It is expected that our Board of Directors will elect officers annually following each annual meeting of stockholders. The following biographies describe the business experience of our directors and executive officers: Ronald D. Ormand: Executive Chairman of the Board of Directors. Mr. Ormand joined our Board of Directors in February 2015, bringing withhim more than 33 years of experience as a senior executive and investment banker in energy, including extensive financing and mergers and acquisitionsexpertise in the oil and gas industry. During his career, he has completed more than $25 billion of capital markets and financial advisory transactions, both asa principal and as a banker. Prior to joining Lilis, Mr. Ormand served as the Chairman and Head of the Investment Banking Group at MLV & Co. (“MLV”),which is now owned by FBR & Co., after it acquired MLV in September of 2015. After the acquisition, Mr. Ormand served as Senior Managing Director andSenior Advisor at FBR & Co. until May 2016, where he focused on investment banking and principal investments in the energy sector. Prior to joining MLVin November 2013, from 2009 to 2013, Mr. Ormand was a senior executive at Magnum Hunter Resources Corporation, or MHR (NYSE:MHR), an explorationand production company engaged in unconventional resource plays, as well as midstream and oilfield services operations. He was part of the managementteam that took over prior management and grew MHR from approximately $35 million enterprise value to over $2.5 billion enterprise value at the time heleft in 2013. Mr. Ormand served on the Board of Directors and in several senior management positions for MHR, including Executive Vice President, ChiefFinancial Officer and Executive Vice President of Capital Markets. On March 10, 2016, in connection with his prior position as Chief Financial Officer ofMHR, Mr. Ormand, without admitting or denying any of the allegations, settled with the SEC in connection with an investigation of MHR’s books andrecords and internal controls for financial reporting. Specifically, Mr. Ormand agreed to cease and desist from violating Sections 13(a) and 13(b)(2)(A) and(B) of the Exchange Act and Rules 13a-1, 13a-13 and 13-15(a) thereunder. He has also paid a penalty of $25,000. The SEC did not allege any anti-fraudviolations, intentional misrepresentations or willful conduct on the part of Mr. Ormand. Mr. Ormand’s career also includes serving as Managing Director andGroup Head of U.S. Oil and Gas Investment Banking at CIBC World Markets and Oppenheimer (1988-2004); Head Of North American Oil and GasInvestment Banking at West LB A.G. (2005-2007), and President and CFO of Tremisis Energy Acquisition Corp. II, an energy special purpose acquisitioncompany from 2007-2009. Mr. Ormand has previously served as a Director of Greenhunter Resources, Inc. (2011-2013), Tremisis (2007-2009), and EurekaHunter Holdings, Inc., a private midstream company (2010-2013). Mr. Ormand holds a B.A. in Economics, an M.B.A. in Finance and Accounting from UCLAand studied Economics at Cambridge University, England. Mr. Ormand’s qualifications to serve as the Executive Chairman of the Board of Directors include extensive leadership and industry experience,including as a Senior Executive at Magnum Hunter Resources Corporation, Chairman and Head of Investment Banking at MLV, and Head of US Oil and Gasfor CIBC. Nuno Brandolini: Director. Mr. Brandolini joined our Board of Directors in February 2014, and became Chairman in April 2014. On January 13,2016, Mr. Brandolini was replaced as Chairman of our Board of Directors by Ronald D. Ormand. Since 2014, Mr. Brandolini has served as Managing Memberand Chief Executive Officer of Scorpion Capital, LLC, a private investment company. From 2004 to 2014, Mr. Brandolini served as a member of the generalpartner of Scorpion Capital Partners, L.P., a private equity firm organized as a small business investment company. Prior to forming Scorpion Capital and itspredecessor 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 principalwith 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 MKT: LNG), a Houston-based company primarily engaged in LNG related businesses. Mr. Brandolinireceived a law degree from the University of Paris and an M.B.A. from the Wharton School. As a result of his experience holding executive positions with several private equity firms and his experience as a member of the board of directors ofCheniere Energy, Inc., Mr. Brandolini possesses particular knowledge and experience working with oil and gas companies that strengthen the Board’scollective qualifications, skills, and experience 52  R. Glenn Dawson: Director. Mr. Dawson joined our Board of Directors on January 13, 2016. Mr. Dawson has over 36 years of experience in oil andgas exploration in North America and since March 2016, has served as President and Chief Executive Officer of Cuda Energy, Inc., a private Canadian-basedexploration and production company. Mr. Dawson’s career includes serving as President of Bakken Hunter, a division of MHR, where he managed operationsand development of Bakken assets in the United States and Canada from 2011 to 2014. His principal responsibilities have involved the generation andevaluation of drilling prospects and production acquisition opportunities. In the early stages of his career, Mr. Dawson was employed as an explorationgeologist by Sundance Oil and Gas, Inc., a public company located in Denver, Colorado, concentrating on its Canadian operations. From December 1985 toSeptember 1998, Mr. Dawson held a variety of managerial and technical positions with Summit Resources, a then-public Canadian oil and gas explorationand production company, including Vice President of Exploration, Exploration Manager and Chief Geologist. He served as Vice President of Explorationwith PanAtlas Energy Inc., a then-public Canadian oil and gas exploration and production company from 1999 until its acquisition by Velvet ExplorationLtd. in July 2000. Mr. Dawson was a co-founder and Vice President of Exploration of TriLoch Resources Inc., a then-public Canadian oil and gas explorationcompany from 2001 to 2005, until it was acquired by Enerplus Resources Fund. As a result of the sale of TriLoch Resources Inc. to Enerplus Resources Fund,Mr. Dawson founded and served as President and CEO of NuLoch Resources, Inc. in 2005, which was acquired by MHR in 2012. Mr. Dawson graduated in1980 from Weber State University of Utah with a Bachelor’s degree in Geology and attended the University of Calgary from 1980 to 1982 in the MastersProgram for Geology. As a result of Mr. Dawson’s professional experience as the President and Chief Executive Officer of Cuda Energy, Inc. and former President ofBakken Hunter, along with his extensive experience in the oil and gas industry, he possesses particular knowledge and experience in the operations of oiland gas companies that strengthen the Board’s collective qualifications, skills, and experience. General Merrill McPeak: Director. General McPeak joined our Board of Directors in January 2015. He served as the fourteenth chief of staff of theU.S. Air Force and flew 269 combat missions in Vietnam during his 37-year military career. Following retirement from active service in 1994, GeneralMcPeak launched a second career in business. He was a founding investor and chairman of Ethics Point, an ethics and compliance software and servicescompany, which was subsequently restyled as industry leader, Navex Global, and acquired in 2011 by a private equity firm. General McPeak co-invested andremained a board member of Nava Global, which was sold again in 2014. From 2012 to 2014, General McPeak was Chairman of Coast Plating, Inc., a LosAngeles-based, privately held provider of metal processing and finishing services, primarily to the aerospace industry, which was also acquired in a privateequity buyout. He remains a director of that company, now called Valence Surface Technologies. He also currently serves as a director of AerojetRocketdyne, Loyance Biotherapeutics and Research Solutions, Inc. Formerly, he was a director of Tektronix, TWA and ECC International, a defensesubcontractor, where he served for many years as chairman of the Board. From 2010 through 2017, General McPeak served as Chairman of the AmericanBattle Monuments Commission, an agency of the executive branch of the federal government, responsible for operating and maintaining Americancemeteries in foreign countries holding the remains of 125,000 US servicemen. General McPeak has a B.A. degree in Economics from San Diego StateCollege and an M.S. in International Relations from George Washington University. He is a graduate of the National War College and of the ExecutiveDevelopment Program of the University of Michigan Graduate School of Business. He spent an academic year as Military Fellow at the Council on ForeignRelations. As a result of his professional experience, General McPeak possesses particular knowledge and experience, including, without limitation, his serviceas Chief of Staff of the U.S. Air Force and position as founding investor and chairman of Ethicspoint (subsequently Navex Global), that strengthen theBoard’s collective qualifications, skills, and experience. Peter Benz: Director. Mr. Benz joined our Board of Directors on June 23, 2016, in connection with the completion of the merger with BrushyResources. Mr. Benz served on Brushy Resource’s Board of Directors since January 20, 2012. Mr. Benz serves as the Chairman and Chief Executive Officer ofViking Asset Management, LLC, and is a member of its Investment Committee. He has been affiliated with Viking Asset Management, LLC, since 2001. Hisresponsibilities include assuring a steady flow of candidate deals, making asset allocation and risk management decisions and overseeing all business andinvestment operations. He has more than 25 years of experience specializing in investment banking and corporate advisory services for small growthcompanies in the areas of financing, merger/acquisition, funding strategy and general corporate development. Prior to founding Viking in 2001, Mr. Benzfounded Bi Coastal Consulting Company where he advised hundreds of companies regarding private placements, initial public offerings, secondary publicofferings and acquisitions. He has founded three public companies and served as a director for four other public companies. Prior to founding Bi CoastalConsulting, Mr. Benz was responsible for private placements and investment banking activities at Gilford Securities in New York, NY. Mr. Benz became adirector of usell.com, Inc. on May 15, 2014. Mr. Benz is a graduate of Notre Dame University. As a result of his professional experiences, Mr. Benz possesses particular knowledge and experience in developing companies and capital marketsthat strengthen our Board of Director’s collective qualifications, skills, and experience. G. Tyler Runnels: Director. Mr. Runnels was appointed to the Board of Directors in September 2017. He is the Chairman and Chief ExecutiveOfficer of T.R. Winston & Company (“TRW”). Mr. Runnels has been with TRW since 1990 and became its Chairman and Chief Executive Officer in 2003when he acquired control of the firm. He has over 30 years of investment banking experience and has led over $2 billion of debt and equity financings,mergers and acquisitions, initial public offerings, bridge financings, and financial restructurings across a variety of industries, including healthcare, oil andgas, business services, manufacturing, and technology. Mr. Runnels serves on the Pepperdine University President’s Campaign Cabinet. Mr. Runnelsreceived a B.S. and MBA from Pepperdine University, and he holds FINRA Series 7, 24, 55, 63 and 79 licenses. 53  As a result of his professional experience, Mr. Runnels possesses particular knowledge and experience in financing and financial services thatstrengthen our Board of Director’s collective qualifications, skills, and experience. Mark Christensen: Director. Mr. Christensen was appointed to the Board of Directors in September 2017. Mr. Christensen is the Founder, Presidentand CEO of KES 7 Capital Inc. in Toronto, Canada, and a registrant of the Ontario Securities Commission (OSC). Prior to founding KES 7, Mr. Christensenwas Vice Chairman, Head of Global Sales and Trading at GMP Securities, one of Canada’s largest independent investment banks, where he served as amember of the Executive Committee, Compensation Committee and New Names Committee. Mr. Christensen has experience in a broad range of corporateand capital market transactions, from mergers and acquisitions to public and private financings, that total in the tens of billions of dollars. His background ingeology and geophysics has provided him with valuable insight into the energy industry, enabling him to advise both institutional investors and energycompanies from around the globe. Mr. Christensen holds a Master of Science degree from the University of Windsor in Canada and a Bachelor of ScienceDegree from the University of Hull in the United Kingdom. As a result of his professional experience, Mr. Christensen possesses particular knowledge and experience in providing advisory services tonumerous institutional investors and companies active in the oil and gas industry strengthen our Board of Director’s collective qualifications, skills, andexperience. John Johanning: Director. Mr. Johanning was appointed to the Board of Directors in March 2018. Mr. Johanning is the Technical Director of VärdePartners, Inc.’s (“Värde”) energy business. Mr. Johanning joined Värde in May 2017 and presides over the Petroleum Engineering and Geoscience aspects ofVärde’s investments in energy. Mr. Johanning is involved in the performance of current Varde investments across active onshore US basins as well as newbusiness 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, where he was influential in numerous transactions totaling over $10 billion intransaction 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 divestures of assets, corporate mergers, andcapital raises. Mr. Johanning also worked across all oilfield sectors, gaining transactional experience in the upstream, midstream, downstream and oil fieldservice 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 gasassets across several US Basins, including the Permian of West Texas and Southeast New Mexico and the Texas Gulf Coast Basin, among others. While in theSouth Texas Reservoir Management team, Mr. Johanning was responsible for the resource appraisal of a 400,000+ gross acre Eagle Ford Shale position thatwas deeply rooted in geological and well completion data. While at BP, Mr. Johanning gained a detailed technical understanding of oil and gas assetsthrough the various facets of the business, including Production Engineering, Reservoir Engineering, Drilling and Completions, Geology and Geophysics, aswell 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. As a result of his professional experience, Mr. Johanning possesses particular knowledge and experience in the operations of oil and gas companiesthat strengthen our Board of Director’s collective qualifications, skills and experience. Markus Specks: Director. Mr. Specks was appointed to the Board of Directors 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-levelinvestments across the energy sector. He serves on Värde 's Investment Committee, as well as several boards of private energy companies. Prior to joiningVärde 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 fromLawrence University in Wisconsin. As a result of his professional experience, Mr. Specks possesses particular knowledge and experience in developing companies and capital markets,particularly with oil and gas companies, that strengthen our Board of Director’s collective qualifications, skills, and experience. James (“Jim”) Linville: Chief Executive Officer. Effective August 4, 2017, our Board appointed James Linville to the position of Chief ExecutiveOfficer. Mr. Linville was the Company’s President since June 26, 2017 until his appointment to Chief Executive Officer. Mr. Linville most recently held theposition of Senior Director of Operations and Development for US Energy Development Corporation (“US Energy”) from January 2016 to June 2017, wherehe was a senior technical engineering, operational and resource development professional in the company. During his time at US Energy, Mr. Linville led ateam of field and office staff consisting of drilling, completions, operations, engineering, reservoir, regulatory and environmental safety professionals.Additionally, Mr. Linville was a member of the Capital Committee at US Energy, tasked with deploying up to approximately $200 million annually in aportfolio of energy related investments, primarily within the Delaware Basin and Eagle Ford. Prior to US Energy, Mr. Linville was Director of Operations atAmerican Energy Permian Basin (“AEPB”) from January 2015 to July 2015, where he managed field operations, completions, production and facilitiesengineering for a large Midland Basin Wolfcamp shale horizontal development program. Prior to moving into his position as Director of Operations at AEPB,Mr. Linville was Director of Acquisitions at American Energy Partners, LP (“AELP”) from February 2014 to January 2015, where he assembled and led theacquisitions team, consisting of numerous petro-professionals (Reservoir, Operations, Geoscience, Land), who were responsible for screening over 400acquisition opportunities. While at AELP, Mr. Linville participated in and managed over 100 acquisition evaluations with aggregate value greater than $12billion. Previously, Mr. Linville was employed at Devon Energy Corporation from January 2001 to January 2014, where he held various engineering andmanagement roles. Prior to Devon Energy Corporation, Mr. Linville held various leadership and engineering (reservoir, production, drilling) and operationalroles at Eastern American Energy, Consolidated Oil & Gas, Hallwood Petroleum, Unocal and his own firm Derrick Engineering Corporation. Mr. Linvilleearned his Bachelor of Science in Petroleum Engineering from New Mexico Tech and his Master of Science in Environmental Engineering from MarshallUniversity. Throughout his career, he has held numerous leadership roles within the Society of Petroleum Engineers (SPE) and was an Industry AdvisoryBoard member at New Mexico Tech and the Oklahoma City SPE Chapter. In addition, Mr. Linville is a Registered Professional Engineer. Joseph C. Daches: Executive Vice President, Chief Financial Officer and Treasurer. On January 23, 2017, our Board appointed Joseph Daches tothe position of Executive Vice President, Chief Financial Officer and Treasurer. Prior to joining our company, Mr. Daches most recently held the position ofChief Financial Officer and Senior Vice President of Magnum Hunter Resources Corp. (“MHR”) from July 2013 to June 2016, where he finished his tenure bysuccessfully guiding MHR through a restructuring, and upon emergence was appointed Co-CEO by MHR’s new board of directors until his departure. Mr.Daches has over 20 years of experience and expertise in directing strategy, accounting and finance in primarily small and mid-size oil and gas companies andhas helped guide several of those companies through financial strategy, capital raises and private and public offerings. Prior to joining MHR, Mr. Dachesserved as Executive Vice President, Chief Accounting Officer and Treasurer of Energy & Exploration Partners, Inc. from September 2012 until June 2013 andas a director of that company from April 2013 through June 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 SiriusSolutions, LLC, where he was primarily responsible for financial reporting, technical and oil and gas accounting and the overall management of the E&PAdvisory 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. 54  Seth Blackwell: Executive Vice President of Land and Business Development. Seth Blackwell joined Lilis in December 2016. Mr. Blackwell is aCertified Professional Landman with extensive knowledge and experience in all facets of land management. Prior to joining Lilis, from October 2012 toDecember 2016, Mr. Blackwell held the position of Vice President of Land for XOG Resources where he managed all land and business development effortsfor the company. Mr. Blackwell also gained extensive experience in a wide variety of major US oil and gas plays while working for Occidental Petroleum.Mr. Blackwell started his career blocking together large acreage positions in excess of 30,000 acres throughout Central and East Texas. Mr. Blackwell is anactive member of the American Association of Professional Landmen, North Houston Association of Professional Landmen and the Houston Association ofProfessional Landmen. Mr. Blackwell holds a bachelor’s degree in Business Management from Fort Hays State University and is currently pursuing his MBAin Energy from the University of Tulsa. Section 16(a) Beneficial Ownership Reporting Compliance Our executive officers and directors and persons who own more than 10% of our common stock are required to file reports with the SEC, disclosingthe 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 andwritten representations that we have received, we believe that all required reports were timely filed during 2017 and through the date of this Annual Report,except as follows: ·Brennan Short, our former COO, filed his Form 3 and one Form 4, reporting two transactions, subsequent to the time prescribed by Section 16(a) ofthe Exchange Act.·R. Glenn Dawson filed one Form 4, reporting one transaction, subsequent to the time prescribed by Section 16(a) of the Exchange Act.·Vertex Fund filed its Form 3 and one Form 4, reporting one transaction, subsequent to the time prescribed by Section 16(a) of the Exchange Act.·Ronald Ormand filed one Form 4, reporting one transaction, subsequent to the time prescribed by Section 16(a) of the Exchange Act. Board of Directors and Board Committees Our Board of Directors conducts its business through meetings and through its committees. Our Board of Directors held eighteen meetings in 2017and took action by unanimous written consent on twelve occasions. Each director attended at least 75% of (i) the meetings of the Board held after suchdirector’s appointment and (ii) the meetings of the committees on which such director served, after being appointed to such committee. Our policy regardingdirectors’ attendance at the annual meetings of stockholders is that all directors are expected to attend, absent extenuating circumstances. Affirmative Determinations Regarding Director Independence and Other Matters Our Board of Directors follows the standards of independence established in accordance with the standards for companies listed on the New YorkStock Exchange, or the NYSE and the rules and regulations promulgated by the SEC, as well as our Corporate Governance Guidelines on DirectorIndependence, which was amended on December 10, 2015, a copy of which is available on our website at www.lilisenergy.com under “Investors-CorporateGovernance-Highlights” in determining the independence of its directors. The Board has determined that six of our current directors, Mr. Brandolini, GeneralMcPeak, Mr. Benz, Mr. Dawson, Mr. Specks and Mr. Johanning are “independent directors” under the NYSE standards and SEC rules and regulationsreferenced above. No independent director receives, or has received, any fees or compensation directly as an individual from us other than compensation received inhis or her capacity as a director or indirectly through their respective companies, except as described below. See “Certain Relationships and RelatedTransactions, and Director Independence”. There were no transactions, relationships or arrangements not otherwise disclosed that were considered by theBoard of Directors in determining whether any of the directors were independent. 55  Committees of the Board of Directors Pursuant to our amended and restated bylaws, our Board of Directors 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 of Directors has established anaudit committee, a compensation committee, a nominating and corporate governance committee and a reserves committee. The membership and function ofthese committees are described below. Audit Committee During the year ended December 31, 2017, each of Mr. Brandolini, General McPeak and Mr. Benz served on the audit committee, who are allcurrently serving on the audit committee. Mr. Benz is the acting as chairman of the audit committee and meets the definition of an audit committee financialexpert. Our Board of Directors has determined that each of Mr. Brandolini, General McPeak and Mr. Benz meet the independence requirements of the SECand NYSE rules and the financial literacy requirements of the NYSE. The audit committee met five times during the year ended December 31, 2017, and acted by written consent once. The audit committee also metseparately on several occasions in connection with meetings of the full Board. The audit committee is governed by a written charter that is reviewed, andamended, if necessary, on an annual basis. A copy of the charter is available on our website at www.lilisenergy.com under “Investors-Corporate Governance-Highlights.” Compensation Committee Our compensation committee currently consists of Mr. Brandolini and Mr. Dawson. Mr. Dawson is the chairman of the compensation committee. The compensation committee met seven times during the year ended December 31, 2017, and acted by written consent six times. The compensationcommittee also met separately on several occasions in connection with meetings of the full Board. Consistent with the listing requirements of the NYSE, theCompensation Committee is composed entirely of independent members of our Board of Directors, as each member meets the independence requirements setby the NYSE and applicable federal securities laws. The compensation committee reviews, approves and modifies our executive compensation programs, plans and awards provided to our directors,executive officers and key associates. The compensation committee also reviews and approves short-term and long-term incentive plans and other stock orstock-based incentive plans. In addition, the committee reviews our compensation and benefit philosophy, plans and programs on an as-needed basis. Inreviewing our compensation and benefits policies, the compensation committee may consider the recruitment, development, promotion, retention, andcompensation of our executive and senior officers, trends in management compensation and any other factors that it deems appropriate. Under its charter, the compensation committee may create and delegate such tasks to such standing or ad hoc subcommittees as it may determine tobe necessary or appropriate for the discharge of its responsibilities, as long as the subcommittee has at least the minimum number of directors necessary tomeet any regulatory requirements. The compensation committee may engage consultants in determining or recommending the amount of compensation paidto our directors and executive officers. The compensation committee is governed by a written charter that is reviewed, and amended if necessary, on anannual basis. A copy of the charter is available on our website at www.lilisenergy.com under “Investors-Corporate Governance-Highlights.” Nominating and Corporate Governance Committee Our nominating and corporate governance committee currently consists of Mr. Benz, General McPeak and Mr. Brandolini, who is the chairman ofthe nominating and corporate governance committee. The nominating and corporate governance committee met twice during the year ended December 31,2017, but met separately on several occasions in connection with meetings of the full Board. The primary responsibilities of the nominating and corporate governance committee include identifying, evaluating and recommending, for theapproval 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 ofsuch policies, and assisting in the identification, evaluation and recommendation of potential candidates to become officers of our Company. Thenominating and corporate governance committee will review our code of business conduct and ethics and its enforcement, and reviews and recommends toour Board whether a mitigation plan is appropriate with respect to any exception to such code. A copy of the nominating and corporate governancecommittee charter may be found on our website at www.lilisenergy.com under “Investor Relations-Corporate Governance-Highlights.” During fiscal year2017, there have been no material changes to the procedures by which security holders may recommend nominees to our Board of Directors. 56  Reserves Committee Our reserves committee currently consists of Mr. Ormand and Mr. Dawson, who is the chairman of the reserves committee. The primary responsibilities of the reserves committee include retaining and terminating independent petroleum engineering consultants (the“IPEC”) retained to assist the Company in the annual and quarterly review of hydrocarbon reserves and approving their compensation and terms of theirengagement, establishing expectations of the IPEC and their accountability to the reserves committee, ensuring that the IPEC are independent, and reviewingthe Company’s significant reserve engineering principles, policies, internal procedures and assumptions relating to the Company’s reserve estimates anddisclosure. Additionally, at the request of our Board, the reserves committee chairperson currently performs certain technical responsibilities with respect to theoperational activities of the Company. Communications with our Board of Directors Stockholders may communicate with our Board of Directors or any of the directors by sending written communications addressed to the Board ofDirectors or any of the directors, Lilis Energy, Inc., 300 E. Sonterra Blvd., Suite No. 1220, San Antonio, Texas 78258, Attention: Chief Financial Officer. Allcommunications are compiled by the chief financial officer and forwarded to our Board of Directors or the individual director(s) accordingly. Code of Ethics Our Board of Directors has adopted a code of business conduct and ethics that applies to all of our officers and employees, including our chiefexecutive officer, chief financial officer or controller, and persons performing similar functions. Our code of business conduct and ethics codifies the businessand ethical principles that govern all aspects of our business. A copy of our code of business conduct and ethics is available on our website atwww.lilisenergy.com under “Investors-Corporate Governance-Highlights.” We undertake to provide a copy of our code of business conduct and ethics to anyperson, at no charge, upon a written request. All written requests should be directed to: Lilis Energy, Inc., 300 E. Sonterra Blvd., Suite No. 1220, San Antonio,Texas 78258, Attention: Chief Financial Officer. If any substantive amendments are made to our code of business conduct and ethics, or if any waiver(including any implicit waiver) is granted from any provision of the code of business conduct and ethics to our chief executive officer, chief financial officeror controller, we will disclose the nature of such amendment or waiver on our website at www.lilisenergy.com under “Investors-Corporate Governance-Highlights.” or, if required, in a Current Report on Form 8-K. Item 11. Executive Compensation COMPENSATION DISCUSSION AND ANALYSIS Below is a discussion and analysis of our compensation programs as they applied to our named executive officers—or NEOs—for 2017. Our fiscalyear is the calendar year. Our NEOs for 2017 were: (1) James Linville, Chief Executive Officer; (2) Abraham “Avi” Mirman, former Chief Executive Officer; (3) Joseph C.Daches, Chief Financial Officer, Executive Vice President, and Treasurer; (4) Kevin Nanke, former Chief Financial Officer; (5) Ariella Fuchs, former ExecutiveVice President, General Counsel, and Secretary; (6) Brennan Short, former Chief Operating Officer; and (7) Ronald D. Ormand, Executive Chairman. Compensation Philosophy and Objectives Our compensation programs are designed to motivate our executives and employees and enable them to participate in the growth of our business,while also driving the creation of long-term stockholder value. We provide our executive officers with both variable and fixed compensation, including basesalaries, short-term cash incentive compensation, and long-term equity incentive compensation. We strive to balance short-term awards, such as annualperformance-based bonuses, with longer-term performance awards, such as equity awards, in order to provide incentives for both short- and long-termperformance. 57  Role of Our Compensation Committee Our compensation committee is appointed by our Board of Directors—or our Board—to discharge the Board’s responsibilities relating to thecompensation of our Chief Executive Officer—or our CEO—and our other executive officers. The compensation committee has overall responsibility forapproving and evaluating all compensation plans, policies, and programs of the Company as they affect our executive officers. During 2017, our compensation committee consisted of Nuno Brandolini, R. Glenn Dawson, and General Merrill A. McPeak (Chair). At leastannually, the compensation committee: (1) reviews and approves the corporate goals and objectives applicable to the compensation of our CEO; (2)evaluates our CEO’s performance in light of those goals and objectives; and (3) determines and approves our CEO’s compensation level based on thisevaluation. The compensation committee also, on at least an annual basis, reviews and approves the annual base salaries and annual incentive opportunitiesof our executive officers other than our CEO. The compensation committee also, periodically and as and when appropriate, reviews and approves thefollowing as they affect our executive officers: (1) all other incentive awards and opportunities, including both cash-based and equity-based awards andopportunities; (2) any employment agreements and severance arrangements; (3) any change in control agreements and severance protection plans and changein control provisions affecting any elements of compensation and benefits; and (4) any special or supplemental compensation and benefits for our executiveofficers and former executive officers. Our compensation committee is governed by a written charter, a copy of which is available on the Investor Relations section of our website at:http://investors.lilisenergy.com/. Role of Our Compensation Consultant Our compensation committee has sole authority over the selection, use, and retention of any compensation consultant or any other experts engagedto assist the compensation committee in discharging its responsibilities. In February 2017, the compensation committee engaged Longnecker & Associates(“Longnecker”) to assist with its overall compensation review and decision-making. In May 2017, Longnecker conducted an independent, comprehensive,broad-based analysis of our executive compensation program, and the compensation committee used this analysis as one of several reference points inmaking decisions regarding 2017 compensation. Longnecker’s objectives were to: ·review the total direct compensation (base salary, annual incentives, and long-term incentives) for the NEOs; ·assess the competitiveness of executive compensation, based on revenue size, asset size, enterprise value and market capitalization, as compared tothe peer group and published survey companies in the oil and gas industry; and ·provide conclusions and recommend considerations for total direct compensation. Longnecker also provides guidance on industry best practices. This information assists us in developing and implementing compensation programsgenerally competitive with those of other companies in our industry and other companies with which we generally compete for executive talent. Longnecker performed services solely on behalf of the compensation committee. In accordance with the rules and regulations of the SEC and theNYSE, the compensation committee assessed the independence of Longnecker and concluded that no conflicts of interest exist that would preventLongnecker from providing independent and objective advice. The companies used for the executive compensation comparisons in May 2017 included the following: SM Energy CompanyRSP Permian, Inc.Laredo Petroleum, Inc.Matador Resources CompanyParsley Energy, Inc.Callon Petroleum CompanyCarrizo Oil & Gas, Inc.Resolute Energy CorporationSanchez Energy CorporationSRC Energy Inc.Gulfport Energy CorporationCentennial Resource Development, Inc.PDC Energy, Inc.Jagged Peak Energy Inc. 58  Longnecker also reviewed survey data as a reference point to compare the compensation of our executives to those of a broad range of companies.The published surveys utilized by Longnecker included the following: ·Economic Research Institute, Executive Compensation Assessor; ·Mercer, Inc., 2016 Mercer Total Compensation Survey for the Energy Sector; ·Towers Watson, 2016 CSR General Industry Top Management Compensation Survey Report; and ·Longnecker & Associates, Energy Industry Long-Term Incentive Compensation Survey. Elements of Compensation The compensation earned by our NEOs for 2017 consisted of base salary, short-term cash incentive compensation, long-term equity incentivecompensation consisting of awards of restricted shares and stock options, and miscellaneous employee benefits. We pay each of our NEOs a base salary, which is reviewed annually and not considered to be “at risk,” as it does not vary with the performance of theCompany. This base salary is designed to compensate the NEOs for the performance of their duties and responsibilities. Our NEOs are also eligible for annualperformance cash bonuses, including certain NEOs being eligible for cash bonuses pursuant to their employment agreements, as described further belowunder Employment Agreements. Historically, we have provided our NEOs with both short-term and long-term incentive compensation through our 2012 Equity Incentive Plan—or2012 EIP—and our 2016 Omnibus Incentive Plan—or 2016 Plan—both of which are described in detail below. These plans have been designed to align ameaningful portion of NEO compensation with the financial performance of the Company. Upon our 2016 Plan becoming effective, we stopped grantingawards under our 2012 EIP. Our NEOs generally participate in the same health care, disability, life insurance, and other benefit plans made available to our other employees.However, our executives receive a limited number of additional benefits and perquisites described in more detail in the All Other Compensation column ofthe Summary Compensation Table below. These additional benefits and perquisites generally are provided to our NEOs for their convenience and financialsecurity. Employment Agreements Mr. Linville. We entered into an employment agreement with Mr. Linville dated June 26, 2017, in connection with his appointment as our President.The agreement provides, among other things, that Mr. Linville will receive a base salary of (1) $400,000 from the effective date of the agreement to the one-year anniversary of the effective date and (2) $450,000 from the one-year anniversary of the effective date of his agreement to the two-year anniversary of theeffective date. Mr. Linville also received a lump sum cash signing bonus of $100,000 under the agreement. Additionally, Mr. Linville is eligible to receive alump sum cash retention bonus equal to no less than $200,000 on the one-year anniversary of the effective date of the agreement, subject to his continuedservice. Mr. Linville is also eligible to receive annual bonuses and 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. On August 4, 2017, we amended our employment agreement with Mr. Linville to reflect his removal as our President and appointment as our CEO.All other terms of the employment agreement remained unchanged. 59  The initial term of Mr. Linville’s agreement ended December 31, 2017, and the agreement began to renew automatically for additional one-yearperiods beginning on December 31, 2017. Either party may give notice of non-renewal at least 180 days before the end of the then-current term. On June 26, 2017, Mr. Linville received a grant of 325,000 stock options under our 2016 Plan, with an exercise price of $4.84, which such grant ofstock options was conditioned on stockholders’ approval, which was obtained on July 13, 2017. This grant is scheduled to vest over two years, with 34%vesting on the grant date, 33% vesting on the first anniversary of the grant date and 33% vesting on the second anniversary of the grant date, subject tocontinued service. Also, on June 26, 2017, Mr. Linville received a grant of 175,000 shares of restricted stock under our 2016 Plan, with a fair value of $4.84per share at grant date, which such grant of stock was conditioned on stockholders’ approval, which was obtained on July 13, 2017. This grant is scheduled tovest over two years, with 34% vesting on the grant date, 33% vesting on the first anniversary of the grant date, and 33% vesting on the second anniversary ofthe grant date, subject to his continued service. Under his employment agreement, upon a termination by us without cause or a termination by him for good reason, Mr. Linville will be entitled to(1) a lump sum severance payment equal to 12 months of base salary, (2) 12 months of COBRA premiums, and (3) a lump sum payment equal to $200,000(representing an amount equal to Mr. Linville’s unpaid sign-on retention bonus). Upon a termination by us without cause or a termination by Mr. Linville forgood reason within 12 months after a change in control, he will be entitled to a lump sum severance payment equal to 24 months of base salary and 24months of COBRA premiums. Upon a termination due to disability, Mr. Linville will be entitled to a lump sum severance payment equal to six months ofCOBRA premiums. All severance payments under Mr. Linville’s employment agreement are subject to his execution of a release of claims against us. Theseverance payments are also subject to reduction in order to avoid any excise tax associated with Section 280G of the Internal Revenue Code—or the Code—but only if that reduction would result in Mr. Linville receiving a greater net after tax benefit as a result of the reduction. All payments to Mr. Linville under his employment agreement will be subject to clawback in the event required by applicable law. Further, Mr.Linville is subject to non-competition, non-solicitation, anti-raiding, and confidentiality provisions under his employment agreement. Mr. Daches. We entered into an employment agreement with Mr. Daches dated January 23, 2017, in connection with his appointment as ourExecutive Vice President, Chief Financial Officer, and Treasurer. We amended this agreement on May 5, 2017 to eliminate Mr. Daches’ eligibility to receivecertain “cash incentive bonuses” that had been tied to BOE and EBITDAX production thresholds, and we replaced those bonuses with an immediate bonuspaid out in a mix of cash and stock. The agreement provides, among other things, that Mr. Daches will receive a base salary of (1) $300,000 from the effective date of the agreement tothe one-year anniversary of the effective date; (2) $350,000 from the one-year anniversary of the effective date of the agreement to the two-year anniversary ifthe effective date; and (3) $375,000 after the two-year anniversary. Under his agreement, Mr. Daches’ base salary will be reviewed annually by our Board todetermine whether it should be increased. In 2017, Mr. Daches received a $50,000 cash bonus for our Company’s timely filing of its 2016 Annual Report onForm 10-K, in accordance with his employment agreement. Mr. Daches is also eligible to receive bonuses and awards of equity and non-equity compensationand 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 250,000 shares of restricted stock. The initial term of Mr. Daches’ agreement ended on December 31, 2017, and the agreement began to renew automatically for additional one-yearperiods beginning on December 31, 2017. Either party may give notice of non-renewal at least 180 days before the end of the then-current term. On December 15, 2016, Mr. Daches received a grant of 750,000 stock options under our 2016 Plan, with an exercise price of $2.98. 34% of theoptions vested on the grant date, 33% vested on December 15, 2017, and 33% will vest on the second anniversary of the grant date, subject to continuedservice. On May 5, 2017, Mr. Daches received a grant of 235,000 shares of restricted stock with a fair value of $4.26 per share at grant date. 100% of therestricted stock award vested on the grant date. On October 5, 2017, Mr. Daches received a grant of 400,000 shares of restricted stock with a fair value of$5.00 per share at grant date. This grant is scheduled to vest over two years, with 34% vesting on the grant date, 33% vesting on the first anniversary of thegrant date, and 33% vesting on the second anniversary of the grant date, subject to continued service Under his employment agreement, upon a termination by us without cause or a termination by him for good reason, Mr. Daches will be entitled to alump sum severance payment equal to 12 months of base salary and 12 months of COBRA premiums. Upon a termination by us without cause or atermination by Mr. Daches for good reason within 12 months after a change in control, he will be entitled to a lump sum severance payment equal to 24months of base salary and 24 months of COBRA premiums. Upon a termination due to disability, Mr. Daches will be entitled to a lump sum severancepayment equal to six months of COBRA premiums. All severance payments under Mr. Daches’ employment agreement are subject to his execution of arelease of claims against us. The severance payments are also subject to reduction in order to avoid any excise tax associated with Code Section 280G, butonly if that reduction would result in Mr. Daches receiving a greater net after tax benefit as a result of the reduction. 60  All payments to Mr. Daches under his employment agreement will be subject to clawback in the event required by applicable law. Further, Mr.Daches is subject to non-competition, non-solicitation, anti-raiding, and confidentiality provisions under his employment agreement. Ms. Fuchs. On July 5, 2016, we entered into an employment agreement with Ms. Fuchs under which she served as our General Counsel. Thisagreement became effective June 24, 2016 upon the closing of our merger with Brushy. We amended this agreement on May 5, 2017 to eliminate Ms. Fuchs’eligibility to receive certain “cash incentive bonuses” that had been tied to BOE and EBITDAX production thresholds, and we replaced those bonuses withan immediate bonus paid out in a mix of cash and stock. The initial term of Ms. Fuchs’ agreement ended on December 31, 2017, and the agreement began to renew automatically for additional one-yearperiods beginning on December 31, 2017. Ms. Fuchs’ initial base salary under her agreement was $250,000. Ms. Fuchs was entitled to, and received, a bonus under the agreement equal to$112,500, which was paid in cash on the first regular payroll date after June 24, 2016 (the closing date of the merger with Brushy). Ms. Fuchs was alsoeligible to receive awards of equity and non-equity compensation and to participate in our annual and long-term incentive plans, in each case as determinedby our Board. On June 24, 2016, Ms. Fuchs received a grant of 375,000 stock options under our 2016 Plan, with an exercise price of $1.34. This grant wasscheduled to vest over two years, with 34% vesting on the grant date, 33% vesting on the first anniversary of the grant date, and 33% vesting on the secondanniversary of the grant date, subject to continued service. On December 15, 2016, Ms. Fuchs received an additional grant of 375,000 stock options underour 2016 Plan, with an exercise price of $2.98. This grant was scheduled to vest over two years, with 34% vesting on the grant date, 33% vesting on the firstanniversary of the grant date, and 33% vesting on the second anniversary of the grant date, subject to continued service. On May 5, 2017, Ms. Fuchs received a grant of 150,000 shares of restricted stock with a fair value of $4.26 per share at grant date. 100% of therestricted stock award vested on the grant date. On October 5, 2017, Ms. Fuchs received a grant of 300,000 shares of restricted stock with a fair value of $5.00per share at grant date. This grant was scheduled to vest over two years, with 34% vesting on the grant date, 33% vesting on the first anniversary of the grantdate, and 33% vesting on the second anniversary of the grant date, subject to continued service. Under her employment agreement, Ms. Fuchs’ was entitled to a lump sum severance payment equal to six months of base salary and six months ofCOBRA premiums upon a termination by us without cause or a termination by her for good reason. Upon a termination by us without cause or a terminationby Ms. Fuchs for good reason within 12 months after a change in control, she was entitled to a lump sum severance payment equal to 24 months of basesalary and 24 months of COBRA premiums. Upon a termination due to disability, Ms. Fuchs was entitled to a lump sum severance payment equal to sixmonths of COBRA premiums. All severance payments under Ms. Fuchs’ employment agreement were subject to her execution of a release of claims againstus. The severance payments are also subject to reduction in order to avoid any excise tax associated with Code Section 280G, but only if that reductionwould result in Ms. Fuchs receiving a greater net after tax benefit as a result of the reduction. All payments to Ms. Fuchs under her employment agreement are subject to clawback in the event required by applicable law. Further, Ms. Fuchs issubject to non-competition, non-solicitation, anti-raiding, and confidentiality provisions under her employment agreement. On February 16, 2018, Ariella Fuchs ceased serving as the Executive Vice President, General Counsel, and Secretary of the Company. Upon Ms.Fuchs’ separation, all unvested equity awards held by Ms. Fuchs vested on an accelerated basis. Mr. Short. In connection with his appointment as our Chief Operating Officer, we entered into an employment agreement with Mr. Short datedJanuary 27, 2017. The agreement provides, among other things, that Mr. Short will receive a base salary of $300,000 per year, to be reviewed annually by ourBoard to determine whether the salary should be increased. The agreement also provides for additional bonuses based on our achievement of certainperformance measures. Mr. Short is also eligible to receive bonuses and awards of equity and non-equity compensation and to participate in annual and long-term compensation plans of the Company, in each case as determined by our Board. The initial term of Mr. Short’s agreement ended on December 31, 2017, and the agreement began to renew automatically for additional one-yearperiods beginning on December 31, 2017. Either party may give notice of non-renewal at least 180 days before the end of the then-current term. 61  On January 27, 2017, Mr. Short received a grant of 250,000 stock options under our 2016 Plan, with an exercise price of $4.35. This grant wasscheduled to vest over two years, with 34% of the options vesting on the grant date, 33% vesting on January 27, 2018, and 33% to vest on the secondanniversary of the grant date, subject to his continued service. Also on January 27, 2017, Mr. Short received a grant of 75,000 shares of restricted stock underour 2016 Plan. This grant was scheduled to vest over two years, with 34% of the shares vesting on the grant date, 33% vesting on January 27, 2018, and 33%to vest on the second anniversary of the grant date, subject to continued service. On May 2, 2017, Mr. Short received a grant of 500,000 stock options underour 2016 Plan, with an exercise price of $4.48; 250,000 of these options vested upon the grant date, and the remaining 250,000 options vest based on theachievement of specified performance goals (generally, 50,000 options will vest per completion of one well under our Company’s authorization forexpenditures budget), 50,000 of which have vested as of March 2018. On October 5, 2017, Mr. Short received a grant of 400,000 shares of restricted stockunder our 2016 Plan, with an exercise price of $5.00. This grant was scheduled to vest over two years, with 34% of the options vesting on the grant date, 33%vesting on the first anniversary of the grant date, and 33% vesting on the second anniversary of the grant date, subject to continued service. Under his employment agreement, upon a termination by us without cause or a termination by him for good reason, Mr. Short will be entitled to alump sum severance payment equal to 12 months of base salary and 12 months of COBRA premiums. Upon a termination by us without cause or atermination by Mr. Short for good reason within 12 months after a change in control, he will be entitled to a lump sum severance payment equal to 24 monthsof base salary and 24 months of COBRA premiums. Upon a termination due to disability, Mr. Short will be entitled to a lump sum severance payment equalto six months of COBRA premiums. All severance payments under Mr. Short’s employment agreement are subject to his execution of a release of claimsagainst us. The severance payments are also subject to reduction in order to avoid any excise tax associated with Code Section 280G, but only if thatreduction would result in Mr. Short receiving a greater net after tax benefit as a result of the reduction. All payments to Mr. Short under his employment agreement will be subject to clawback in the event required by applicable law. Further, Mr. Short issubject to non-competition, non-solicitation, anti-raiding, and confidentiality provisions under his employment agreement. On March 6, 2018, Mr. Short ceased serving as our Chief Operating Officer and, as a result of such cessation, all of Mr. Short’s unvested equityawards were relinquished. Mr. Ormand. On July 5, 2016, we entered into an employment agreement with Mr. Ormand, under which he serves as our Executive Chairman. Theinitial term of the agreement ended on December 31, 2017, and the agreement began to renew automatically for additional one-year periods beginning onDecember 31, 2017. Either party may give 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 will be reviewed by our Board for adjustments) was $300,000 for the first year of theagreement, $350,000 for the second year of the agreement, and $400,000 for the third year of the agreement. Mr. Ormand will be eligible to receive a cashbonus 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, andcash on hand performance measures. Mr. Ormand will also be eligible to receive awards of equity and non-equity compensation and to participate in ourannual and long-term incentive plans, in each case as determined by our Board. On July 7, 2016, Mr. Ormand received a grant of restricted stock under our 2016 Plan covering 1.25 million shares of our common stock. Therestricted 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% vestingon the second anniversary of the date of the grant, subject to continued service. On December 15, 2016, Mr. Ormand received an additional grant of 250,000stock options under our 2016 Plan, with an exercise price of $2.98. This grant is scheduled to vest over two years, with 34% vesting on the grant date, 33%vesting on the first anniversary of the grant date, and 33% vesting on the second anniversary of the grant date, subject to continued service. On October 5, 2017, Mr. Ormand received a grant of 500,000 shares of restricted stock with a fair value of $5.00 per share at grant date. This grant isscheduled to vest over 2 years, with 34% vesting on the grant date, 33% vesting on the first anniversary of the grant date, and 33% vesting on the secondanniversary of the grant date, subject to continued service. Under his employment agreement, Mr. Ormand will be entitled to a lump sum severance payment equal to 12 months of base salary and 12 monthsof COBRA premiums upon a termination by us without cause or a termination by him for good reason. Upon a termination by us without cause or atermination by Mr. Ormand for good reason within 12 months after a change in control, he will be entitled to a lump sum severance payment equal to 24months of base salary and 24 months of COBRA premiums. Upon a termination due to disability, Mr. Ormand will be entitled to a lump sum severancepayment equal to six months of COBRA premiums. All severance payments under Mr. Ormand’s employment agreement are subject to his execution of arelease of claims against us. The severance payments are also subject to reduction in order to avoid any excise tax associated with Code Section 280G, butonly if that reduction would result in Mr. Ormand receiving a greater net after tax benefit as a result of the reduction. All payments to Mr. Ormand under his employment agreement will be subject to clawback in the event required by applicable law. Further, Mr.Ormand is subject to non-competition, non-solicitation, anti-raiding, and confidentiality provisions under his employment agreement. 62  Mr. Mirman. On July 5, 2016, we entered into a new employment agreement with Mr. Mirman, under which he served as our CEO. This agreementbecame effective June 24, 2016 upon the closing of our merger with Brushy. The initial term of Mr. Mirman’s agreement was scheduled to end on December31, 2017. We amended this agreement on May 5, 2017 to eliminate Mr. Mirman’s eligibility to receive certain “cash incentive bonuses” that had been tied toBOE and EBITDAX production thresholds, and we replaced those bonuses with an immediate bonus paid out in a mix of cash and stock. Mr. Mirman’s base salary under his agreement was $350,000 for the first year of the agreement, $375,000 for the second year, and $425,000 for thethird year. Mr. Mirman was entitled to a bonus under the agreement equal to $175,000, payable in cash on the first regular payroll date after June 24, 2016(the closing date of the merger with Brushy). Mr. Mirman was also eligible to receive awards of equity and non-equity compensation and to participate in ourannual and long-term incentive plans, in each case as determined by our Board. Mr. Mirman was granted stock options covering 1,250,000 shares on June 24, 2016 and 500,000 shares on December 15, 2016. To satisfy therequirements of Code Section 162(m), our 2016 Plan included an annual limit on grants of stock options and SARs to any individual participant of10,000,000 shares, which was automatically adjusted to 1,000,000 shares as a result of our 1-for-10 reverse stock split effective June 23, 2016. The 2016option grants to Mr. Mirman inadvertently exceeded this award limit. As a result, our compensation committee approved a rescission in June 2017 of 250,000of the options granted in June 2016 and the entire December 2016 option grant. Our compensation committee believed these awards otherwise representedappropriate compensation opportunities for Mr. Mirman and in June 2017, our compensation committee approved options and restricted stock awards toreplace the value of the rescinded option awards. On May 5, 2017, Mr. Mirman received a grant of 280,000 shares of restricted stock with a fair value of $4.26per share at grant date. 100% of the restricted stock award vested on the grant date. Under his employment agreement, Mr. Mirman was entitled to a lump sum severance payment equal to 12 months of base salary and 12 months ofCOBRA premiums upon a termination by us without cause or a termination by him for good reason. Upon a termination by us without cause or a terminationby Mr. Mirman for good reason within 12 months after a change in control, he was entitled to a lump sum severance payment equal to 24 months of basesalary and 24 months of COBRA premiums. Upon a termination due to disability, Mr. Mirman was entitled to a lump sum severance payment equal to sixmonths of COBRA premiums. All severance payments under Mr. Mirman’s employment agreement were subject to his execution of a release of claims againstus. The severance payments were also subject to reduction in order to avoid any excise tax associated with Code Section 280G, but only if that reductionwould result in Mr. Mirman receiving a greater net after tax benefit as a result of the reduction. All payments to Mr. Mirman under his employment agreementwere subject to clawback in the event required by applicable law. Further, Mr. Mirman was subject to non-competition, non-solicitation, anti-raiding, andconfidentiality provisions under his employment agreement. On August 1, 2017, the SEC filed a civil complaint against multiple parties, including our then CEO, Mr. Mirman. The allegations in the complaintare unrelated to the business of the Company, and predate Mr. Mirman’s tenure with the Company. On August 3, 2017, Abraham Mirman notified us of hisresignation as our CEO, and as a member of our Board, effective as of August 4, 2017. Mr. Mirman also resigned from all positions held with our subsidiaries.Mr. Mirman’s decision to resign was not the result of any disagreement with us, our Board, or management, or any matter relating to our operations, policies,or practices. In connection with Mr. Mirman’s resignation, we entered into a Separation and Consulting Agreement with him on August 3, 2017—the MirmanAgreement—setting forth the terms of Mr. Mirman’s separation from the Company and his prospective consulting services. Under the Mirman Agreement, in satisfaction of all of our obligations under his employment agreement, Mr. Mirman received the followingseverance payments: (1) a lump-sum cash payment of $1,000,000; (2) premium payments for continuing COBRA coverage for 18 months; and (3)reimbursement of reasonable attorneys’ fees incurred in connection with his separation. Further, all unvested equity awards held by Mr. Mirman vested onAugust 12, 2017 as a result of his separation. In addition, we engaged Mr. Mirman as an independent consultant to provide services of a consulting or advisory nature as we may reasonablyrequest with respect to our business. Mr. Mirman’s consultancy commenced August 5, 2017 and is scheduled to terminate on August 5, 2018, unlessterminated earlier or extended by mutual agreement in accordance with the terms of the Mirman Agreement. In consideration for his consulting services, wewill pay Mr. Mirman a monthly consulting fee of $41,660.67. The Mirman Agreement also contains restrictive covenants covering confidentiality, non-competition, non-solicitation, and non-disparagement, anda release of claims against us. Mr. Nanke. Effective as of July 5, 2016, we entered into an employment agreement with Mr. Nanke, under which he served as our Executive VicePresident and Chief Financial Officer. The initial term of Mr. Nanke’s agreement was scheduled to end on December 31, 2017. The agreement provided for a$125,000 cash bonus due upon signing and a $275,000 salary per year, to be reviewed annually by our Board. The agreement also provided for additionalbonuses due based on our achievement of certain performance measures. 63  On June 24, 2016, Mr. Nanke received a grant of 625,000 stock options at an exercise price of $1.34. This grant was scheduled to vest over twoyears, with 34% vesting on the grant date, 33% vesting on June 24, 2017, and 33% to vest on June 24, 2018. Under his employment agreement, Mr. Nanke was entitled to a lump sum severance payment equal to 12 months of base salary and 12 months ofCOBRA premiums upon a termination by us without cause or a termination by him for good reason. Upon a termination by us without cause or a terminationby Mr. Nanke for good reason within 12 months after a change in control, he was entitled to a lump sum severance payment equal to 24 months of base salaryand 24 months of COBRA premiums. Upon a termination due to disability, Mr. Nanke was entitled to a lump sum severance payment equal to six months ofCOBRA premiums. All severance payments under Mr. Nanke’s employment agreement were subject to his execution of a release of claims against us. Theseverance payments were also subject to reduction in order to avoid any excise tax associated with Code Section 280G, but only if that reduction wouldresult in Mr. Nanke receiving a greater net after tax benefit as a result of the reduction. All payments to Mr. Nanke under his employment agreement were subject to clawback in the event required by applicable law. Further, Mr. Nankewas subject to non-competition, non-solicitation, anti-raiding, and confidentiality provisions under his employment agreement. On February 13, 2017, we entered into a separation agreement with Mr. Nanke—or the Nanke Agreement—covering his termination from ourCompany. Mr. Nanke acknowledged that his termination was not for “good reason” (as defined in his employment agreement), but that the termination didconstitute an “involuntary termination” (as defined in the employment agreement). Under the Nanke Agreement, Mr. Nanke released all claims against usrelated to his employment. We agreed to provide Mr. Nanke with (1) a lump sum severance payment equal to 24 months of his base salary as in effectimmediately prior to his termination; (2) a lump sum payment equal to 24 months of COBRA premiums; and (3) a lump sum bonus payment of $175,000. Allseverance payments were subject to Mr. Nanke’s execution of release of claims against us. The Nanke Agreement also contains restrictive covenants coveringconfidentiality, non-competition, non-solicitation, and non-disparagement. 2012 Equity Incentive Plan (formerly the Recovery Energy, Inc. 2012 Equity Incentive Plan) Our Board and stockholders approved our 2012 EIP in August 2012. Our 2012 EIP provided for grants of equity incentives, including stock options,stock appreciation rights—or SARs—restricted shares, RSUs, and unrestricted stock awards. Our 2012 EIP is administered by our compensation committee,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 forunder our 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 Plan,awards are no longer made under our 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 2016 annual meeting onMay 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 experiencedindividuals who by their position, ability, and diligence are able to make important contributions to our success. Eligibility. Awards may be granted under our 2016 Plan to our officers, employees, directors, consultants, and advisors and the officers, employees,directors, consultants, and advisors of our affiliates. Tax-qualified incentive stock options may be granted only to our employees. Administration. Our 2016 Plan may be administered by our Board or our compensation committee. Our compensation committee generally selectsthe 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. A maximum of 13,000,000 shares of our common stock are available for grant under our 2016 Plan. In addition, as ofMay 23, 2016, any awards then outstanding under our 2012 EIP remain subject to and will be paid under the 2012 EIP and any shares then subject tooutstanding awards under the 2012 EIP that subsequently expire, terminate, or are surrendered or forfeited for any reason without issuance of shares willautomatically become available for issuance under our 2016 Plan. The shares issuable under our 2016 Plan will consist of authorized and unissued shares,treasury shares or shares purchased on the open market or otherwise. 64  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 andthereafter are forfeited to us, the shares subject to those awards and the forfeited shares will not count against the aggregate number of shares available forgrant 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) thepayment 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 calendaryear to any nonemployee member of our Board, taken together with any cash fees paid to the director during the year, may not exceed $500,000 in totalvalue (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; SARs; restricted shares; RSUs;other types of equity or equity-based awards; and performance awards. No Repricing. Without stockholder approval, our compensation committee is not authorized under our 2016 Plan to (1) lower the exercise or grantprice 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 2016Plan, 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 orSAR 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, RSU, or other equity award, unless the cancellation and exchange occur in connection with a change in capitalization or other similarchange. Clawback. All awards granted under our 2016 Plan will be subject to all applicable laws regarding the recovery of erroneously awardedcompensation, any implementing rules and regulations under such laws, any policies we adopt to implement such requirements, and any other compensationrecovery policies we may adopt from time to time. Transferability. Awards granted under our 2016 Plan are not transferable other than by will or the laws of descent and distribution, except that incertain 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 theapplicable transaction agreement. If no treatment is provided for in the transaction agreement, each award holder will be entitled to receive the sameconsideration that stockholders receive in the change in control for each share of stock subject to the award holder’s awards, upon the exercise, payment, ortransfer of the awards, but the awards will remain subject to the same terms, conditions, and performance criteria applicable to the awards before the change incontrol, unless otherwise determined by our compensation committee. In connection with a change in control, outstanding stock options and SARs can becancelled 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 incontrol. Subject to the terms and conditions of the applicable award agreement, for awards granted to all other service providers, vesting of awards willdepend 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 fully upon the change in control. For performance awards, the amountvesting will be based on the greater of (1) achievement of all performance goals at the “target” level or (2) the actual level of achievement ofperformance goals as of our fiscal quarter end preceding the change in control, and will be prorated based on the portion of the performance periodthat 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, theawards, as adjusted in connection with the transaction, will continue to vest in accordance with their terms and conditions. In addition, the awardswill vest fully if the award recipient has a separation from service within two years after the change in control other than for cause or by the awardrecipient 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 beprorated based on the portion of the performance period that had been completed through the date of the separation from service. 65  Term, Termination and Amendment of 2016 Plan. Unless earlier terminated by our Board, our 2016 Plan will terminate, and no further awards may begranted, 10 years after the date on which it was initially approved by our stockholders. Our Board may amend, suspend, or terminate our 2016 Plan at anytime, except that, if required by applicable law, regulation, or stock exchange rule, stockholder approval will be required for any amendment. Theamendment, 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 2017 During our fiscal year ended December 31, 2017, we granted 4,266,345 shares of restricted common stock and 3,260,000 options to purchase sharesof common stock to our employees and directors. Also, during 2017, 1,606,937 stock options and 696,469 shares of restricted stock previously issued andunvested were forfeited or cancelled in connection with the termination of certain employees, the departure of certain directors and/or shares cancelled tocover tax withholding on vested restricted shares. Options issued to employees and directors generally vest in equal installments over specified time periodsduring the service period or upon achievement of certain performance-based operating thresholds. Stockholder Feedback and Consideration of 2017 Say-on-Pay Vote Our compensation committee and Board considered the results of the “say-on-pay” vote at our annual meeting of stockholders held on July 13,2017, where the compensation of our NEOs was approved by over 99% of the stockholders that voted on the matter (not including broker non-votes). Ourcompensation committee believes that this stockholder vote indicates strong support for our executive compensation program and considered the strongstockholder support in determining our 2017 compensation practices. Our Board encourages stockholders to contact the Board and share any concerns aboutour executive compensation program, but given the strong level of stockholder support for our executive compensation program in 2017, the compensationcommittee did not engage in any formal outreach program to stockholders on executive compensation matters in 2017. We will hold an advisory vote onexecutive compensation every year until the next required advisory vote with respect to the frequency of advisory votes on executive compensation, whichwill occur at our annual meeting of stockholders in 2018. We are and will remain committed to being responsive to stockholder feedback, and the results ofour annual “say on pay” votes inform the compensation committee’s discussions about the executive pay program. Deductibility Code Section 162(m) limits the deductibility of compensation in excess of $1,000,000 paid to any one NEO in any calendar year. Under the taxrules in effect before 2018, compensation that qualified as “performance-based” under Section 162(m) was deductible without regard to this $1 million limit.However, the Tax Cuts and Jobs Act, which was signed into law December 22, 2017, eliminated this performance-based compensation exception effectiveJanuary 1, 2018, subject to a special rule that “grandfathers” certain awards and arrangements that were in effect on or before November 2, 2017. As a result,compensation that our compensation committee structured in 2017 and prior years with the intent of qualifying as performance-based compensation underSection 162(m) that is paid on or after January 1, 2018 may not be fully deductible, depending on the application of the special grandfather rules. Moreover,from and after January 1, 2018, compensation awarded in excess of $1,000,000 to our NEOs generally will not be deductible. While the Tax Cuts and JobsAct will limit the deductibility of compensation paid to our NEOs, our compensation committee will—consistent with its past practice—continue to retainflexibility to design compensation programs that are in the best long-term interests of the Company and our stockholders, with deductibility of compensationbeing one of a variety of considerations taken into account. Risks Relating to our Compensation Policies and Practices We have undertaken an analysis of our compensation policies and practices to assess whether risks arising from such policies and practices arereasonably likely to have a material adverse effect on our Company. The analysis was performed by our management with oversight by our compensationcommittee. We analyzed risks relating to the different components of our compensation structure, to the time horizons of our compensation components, tothe goals and objectives used to determine performance-based compensation, and to any contractual obligations by us to accelerate the payment ofcompensation. Based on that analysis, we have concluded that the risks arising from our compensation policies and practices are not reasonably likely tohave a material adverse effect on the Company. 66  COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION During 2017, none of the members of our compensation committee was an officer or employee of the Company or any of our subsidiaries. Inaddition, during the last fiscal year, none of our executive officers served as a member of the board of directors or compensation committee of any entity inwhich a member of our Board or compensation committee is an executive. 67  COMPENSATION COMMITTEE REPORT Our compensation committee has reviewed and discussed the Compensation Discussion and Analysis above with management. Based on theirreview and discussions with management, the members of our compensation committee recommended to our Board that the Compensation Discussion andAnalysis be included in this Annual Report. Compensation Committee:Nuno BrandoliniR. Glenn Dawson 68  SUMMARY COMPENSATION TABLE The following table provides information regarding compensation paid to our NEOs for the years ended December 31, 2017, 2016, and 2015 (ineach case only for years in which the individual was one of our NEOs). Name and PrincipalPosition Year Salary($)(1) Bonus($)(2) StockAwards($)(3) OptionAwards($)(4) All OtherCompensation($)(5) Total($) James Linville (Chief ExecutiveOfficer) 2017 207,576 100,000 847,000 861,250 12,438 2,028,340 Abraham “Avi”Mirman (Former CEO)(6) 2017 323,782 1,932,200 2,804,313 ─ 1,269,608 6,329,903 2016 350,000 175,000 ─ 4,295,894 22,484 4,843,378 2015 325,466 100,000 90,000 1,397,721 31,504 1,944,691 Joseph C. Daches (Chief FinancialOfficer) 2017 383,333 1,248,900 3,001,100 ─ 25,788 4,659,121 Kevin Nanke (Former CFO)(7) 2017 17,804 ─ ─ ─ 776,179 793,983 2016 257,500 225,000 ─ 815,216 32,373 1,330,089 2015 200,000 200,000 99,000 608,291 24,634 1,131,925 Brennan Short (Former COO) (8) 2017 345,128 637,500 2,326,250 1,880,000 23,638 5,212,516 Ronald D. Ormand (ExecutiveChairman) (9) 2017 379,167 625,000 2,500,000 ─ 25,788 3,529,955 2016 150,000 ─ 1,875,000 533,092 69,502 2,627,594 Ariella Fuchs (Former EVP,General Counsel, &Secretary) (10) 2017 300,000 1,148,500 1,500,000 ─ 17,687 2,966,187 2016 240,000 112,500 ─ 1,288,768 8,417 1,649,685 2015 182,083 ─ 48,000 234,887 10,538 475,508 (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. See Employment Agreements in the Compensation Discussion andAnalysis above for more information on individual bonuses paid for 2017.(3)The amounts in this column represent the aggregate grant date fair value of stock awards granted during the applicable year. The grant date fairvalues for restricted stock awards were computed in accordance with FASB ASC Topic 718. The amounts reported in this column reflect theaccounting cost for the stock awards and do not necessarily correspond to the actual economic value that may be received for the stock awards. Theamounts in this column for 2017 are detailed below under Grants of Plan-Based Awards.(4)The amounts in this column represent the grant date fair value of stock options granted in the applicable year computed in accordance with FASBASC Topic 718. The amounts reported in this column reflect the accounting cost for the options and do not correspond to the actual economic valuethat may be received for the options. The assumptions used to calculate the fair value of options are set forth in the notes to our consolidatedfinancial statements included elsewhere in this Annual Report. The amounts in this column for 2017 are detailed below under Grants of Plan-BasedAwards.(5)The amounts in this column for 2017 consist of the following: Name Reimbursement ofHealth InsurancePremiums($) CompanyContribution to401(k) Plan($) Severance Benefits($) Total($) James Linville 12,438 - - 12,438 Avi Mirman 25,788 - 1,243,820 1,269,608 Joseph Daches 25,788 - - 25,788 Kevin Nanke - - 776,179 776,179 Brennan Short 23,638 - - 23,638 Ronald Ormand 25,788 - - 25,788 Ariella Fuchs 17,687 - - 17,687 (6)Effective August 4, 2017, Mr. Mirman resigned as our CEO, and as a member of our Board. See Employment Agreements in the CompensationDiscussion and Analysis above for more information regarding Mr. Mirman’s resignation.(7)Effective February 13, 2017, we entered into a separation agreement with Mr. Nanke in connection with his termination from our Company. SeeEmployment Agreements in the Compensation Discussion and Analysis above for more information regarding Mr. Nanke’s separation.(8)On March 6, 2018, Brennan Short ceased serving as the Chief Operating Officer of the Company.(9)Effective July 11, 2016, Mr. Ormand began to serve as Executive Chairman of our Board, which is an officer position. Prior to July 11, 2016, Mr.Ormand was a nonemployee director of our Board and his compensation from January 1 to July 10, 2016 is reflected under All Other Compensationfor 2016.(10)On February 16, 2018, Ariella Fuchs ceased serving as the Executive Vice President, General Counsel, and Secretary of the Company.  69  GRANTS OF PLAN-BASED AWARDS The following table provides information regarding awards granted to our NEOs under our 2016 Plan during 2017. Estimated Future Payouts Under Equity Incentive Plan Awards (1) Name Grant Date Threshold(#) Target(#) Maximum(#) All Other Stock Awards:Number ofShares ofStock orUnits(#)(2) All OtherOptionAwards:Number ofSecuritiesUnderlyingOptions(#)(3) Exercise or BasePrice ofOptionAwards($/Sh) Grant Date Fair Valueof Stock and Option Awards($) James Linville 6/26/2017 ─ ─ ─ ─ 325,000 4.84 861,250 6/26/2017 ─ ─ ─ 175,000 ─ ─ 847,000 Avi Mirman 5/5/2017 ─ ─ ─ 280,000 ─ ─ 1,192,800 6/16/2017 ─ ─ ─ 389,657 750,000 5.31 6,051,579 Joseph Daches 5/5/2017 ─ ─ ─ 235,000 ─ ─ 1,001,100 10/5/2017 ─ ─ ─ 400,000 ─ ─ 2,000,000 Kevin Nanke ─ ─ ─ ─ ─ ─ ─ ─ Brennan Short 1/27/2017 ─ ─ ─ ─ 250,000 4.35 1,087,500 1/27/2017 ─ ─ ─ 75,000 ─ 4.35 326,250 5/2/2017 ─ ─ ─ ─ 250,000 4.48 1,120,000 5/2/2017 ─ ─ 250,000 ─ ─ 4.48 1,120,000 10/5/2017 ─ ─ ─ 400,000 ─ 5.00 2,000,000 Ronald Ormand 10/5/2017 ─ ─ ─ 500,000 ─ 5.00 2,500,000 Ariella Fuchs 5/5/2017 ─ ─ ─ 150,000 ─ 4.26 639,000 10/5/2017 ─ ─ ─ 300,000 ─ ─ 1,500,000 (1)For the stock options granted to Mr. Short on May 2, 2017, 250,000 vested immediately and the remainder were scheduled to vest upon theachievement of specified performance goals (50,000 options were scheduled to vest per completion of each well under our Company’s authorizationfor expenditures budget, until all of the options are vested or forfeited). All such unvested options have been relinquished in connection with Mr.Short’s separation of employment with the Company in March 2018.(2)This column shows the number of RSAs granted in 2017 to our NEOs under our 2016 Plan.-For the RSAs granted to Mr. Linville on June 26, 2017, 34% vested and settled immediately and the remainder will vest and settle in two equalinstallments, subject to continued services, on the first two anniversaries of the grant date.-For the RSAs granted to Mr. Mirman, Mr. Daches, and Ms. Fuchs on May 5, 2017, 100% vested and settled immediately.-For the RSAs granted to Mr. Mirman on June 16, 2017, 66% vested and settled immediately and the remainder vested and settled on August 12,2017 on an accelerated basis under the terms of the Mirman Agreement.-For the RSAs granted to Mr. Daches, Mr. Short, Mr. Ormand, and Ms. Fuchs on October 5, 2017, 34% vested and settled immediately and theremainder will vest and settle in two equal installments, subject to acceleration provisions and continued services, on the first two anniversaries ofthe grant date. The unvested RSAs granted to Ms. Fuchs vested and settled in connection with her separation of employment with the Company inFebruary 2018. -For the RSAs granted to Mr. Short on January 27, 2017, 34% vested and settled immediately and the remainder were scheduled to vest and settle intwo equal installments, subject to acceleration provisions and continued services, on the first two anniversaries of the grant date. The unvested RSAsgranted to Mr. Short were relinquished in connection with the separation of his employment with the Company in March 2018.(3)This column shows the number of stock options granted in 2017 to our NEOs under our 2016 Plan.-For the stock options granted to Mr. Linville on June 26, 2017, 34% vested immediately and the remainder will vest in two equal installments,subject to continued services, on the first two anniversaries of the grant date.-All of Mr. Mirman’s stock options vested August 12, 2017 upon his separation under the terms of the Mirman Agreement.-For the stock options granted to Mr. Short on January 27, 2017, 34% vested immediately and the remainder were scheduled to vest in two equalinstallments, subject to acceleration provisions and continued services, on the first two anniversaries of the grant date. The unvested stock optionsgranted to Mr. Short were relinquished in connection with the separation of his employment with the Company in March 2018. 70  OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END The following table provides information regarding all outstanding equity awards held by our NEOs as of December 31, 2017. Option Awards Stock Awards Name Number ofSecuritiesUnderlyingUnexercisedOptions(#)Exercisable Number ofSecurities UnderlyingUnexercisedOptions(#)Unexercisable EquityIncentivePlanAwards:Number of SecuritiesUnderlyingUnexercisedUnearnedOptions(#) OptionExercisePrice($) OptionExpirationDate Number ofShares ofStock ThatHave NotVested(#) Market Valueof Shares ofStock ThatHave NotVested($)(1) JamesLinville 110,500 214,500(2) ─ 4.84 6/26/2027 115,500(3) 590,205 AviMirman(4) 1,000,000 ─ ─ 1.34 6/24/2026 ─ ─ 750,000 ─ ─ 5.31 6/16/2027 ─ ─ JosephDaches 502,500 247,500(5) ─ 2.98 12/15/2026 264,000(6) 1,349,040 KevinNanke(7) 625,000 ─ ─ 1.34 6/24/2026 ─ ─ BrennanShort 85,000 165,000(8) ─ 4.35 1/27/2027 313,500(10) 1,601,985 250,000 ─ 250,000(9) 4.48 5/2/2027 ─ ─ RonaldOrmand 31,667 ─ ─ 16.50 4/20/2025 742,500(11) 3,794,175 167,500 82,500(5) ─ 2.98 12/15/2026 ─ ─ Ariella Fuchs 251,250 123,750(12) ─ 1.34 6/24/2026 198,000(6) 1,011,780 251,250 123,750(5) ─ 2.98 12/15/2026 ─ ─ Vesting of options and stock awards reflected in this table is subject to continuous service with our Company, except that unvested awards may vestupon 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 setforth 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 on December 31, 2017, which was$5.11.(2)Options vest in equal installments on each of June 26, 2018 and 2019, subject to continued service.(3)Restricted stock vests on June 26, 2018 and 2019 in equal installments, subject to continued service.(4)For Mr. Mirman, effective August 12, 2017, all unvested options and restricted stock accelerated under the Mirman Agreement.(5)Options vest on December 15, 2018, subject to acceleration provisions and continued service. The unvested options granted to Ms. Fuchs weresubject to accelerated vesting in connection with her separation from the Company in February 2018. (6)Restricted stock vests on October 5, 2018 and 2019 in equal installments, subject to acceleration provisions and continued service. The unvestedrestricted stock granted to Ms. Fuchs was subject to accelerated vesting in connection with her separation from the Company in February 2018. (7)For Mr. Nanke, effective February 13, 2017, all unvested options and restricted stock accelerated under the Nanke Agreement.(8)Options vest in equal installments on January 27, 2018 and 2019, subject to acceleration provisions and continued service. The unvested optionsgranted to Mr. Short were relinquished in connection with his separation of employment with the Company in March 2018. (9)Options vest upon the achievement of specified performance goals (50,000 options will vest per completion of each well under our Company’sauthorization for expenditures budget, until all options are vested or forfeited). The unvested options granted to Mr. Short were relinquished inconnection with his separation of employment with the Company in March 2018.(10)49,500 shares of restricted stock vest in equal installments on January 27, 2018 and 2019, subject to acceleration provisions and continued service.264,000 shares of restricted stock vest on October 5, 2018 and 2019 in equal installments, subject to acceleration provisions and continued service.The unvested shares of restricted stock granted to Mr. Short were relinquished in connection with his separation of employment with the Companyin March 2018. (11)412,500 shares of restricted stock vest in equal installments on June 24, 2018, subject to acceleration provisions and continued service. 330,000shares of restricted stock vest on October 5, 2018 and 2019 in equal installments, subject to acceleration provisions and continued service.(12)Options vest on June 24, 2018, subject to acceleration provisions and continued service. The unvested options granted to Ms. Fuchs were subject toaccelerated vesting in connection with her separation from the Company in February 2018. 71  OPTION EXERCISES AND STOCK VESTED The following table provides information regarding the exercise of stock options by our NEOs and the vesting of restricted stock during 2017. Option Awards Stock Awards Name Number of SharesAcquired on Exercise(#) Value Realized onExercise($) Number of SharesAcquired on Vesting(#) Value Realized onVesting($) James Linville - - 59,500 287,980 Avi Mirman - - 669,657 3,261,879 Joseph Daches - - 371,000 1,681,100 Kevin Nanke - - - - Brennan Short - - 161,500 764,150 Ronald Ormand - - 170,000 850,000 Ariella Fuchs - - 252,000 1,149,000 72  PENSION BENEFITS We do not maintain any plans that provide for payments or other benefits at, following, or in connection with retirement, of the sort that wouldotherwise require us to include a Pension Benefits table as contemplated by SEC rules. NONQUALIFIED DEFERRED COMPENSATION We do not maintain any defined contribution or other plans that provide for the deferral of compensation on a basis that is not tax-qualified, of thesort that would otherwise require us to include a Nonqualified Deferred Compensation table as contemplated by SEC rules. 73  POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE-IN-CONTROL The following table provides information regarding the payments and benefits to which each of our NEOs would be entitled to in the event oftermination of such executive’s employment with our Company and in the event of a change in control of our Company. Except as otherwise noted, theamounts shown (1) are estimates only and (2) assume that the applicable termination of employment was effective, or that the change in control occurred, asof December 31, 2017. For further information regarding the agreements that provide for payment(s) to our NEOs at, following, or in connection with any servicetermination, or a change in control of the Company, see Employment Agreements in the Compensation Discussion and Analysis section above. Name Cash($) Equity($)(1) Perquisites/Benefits($) Total($) James Linville Death 400,000 677,955 ─ 1,077,955 Disability ─ 677,955 11,400(2) 689,355 By Lilis without Cause or by NEO for Good Reason (No CIC) 600,000(3) 677,955 22,800(4) 1,300,755 CIC with Involuntary Termination 1,000,000(5) 677,955 45,600(6) 1,723,555 Avi Mirman(7) Joseph Daches Death 400,000 2,946,540 ─ 3,346,540 Disability ─ 2,946,540 11,400(2) 2,957,940 By Lilis without Cause or by NEO for Good Reason 400,000(8) 2,946,540 22,800(4) 3,369,340 CIC with Involuntary Termination 800,000(9) 2,946,540 45,600(6) 3,792,140 Kevin Nanke(10) Ariella Fuchs (11) Brennan Short (12) Ronald Ormand Death 500,000 3,675,082 ─ 4,465,988 Disability ─ 3,675,082 11,400(2) 3,977,388 By Lilis without Cause or by NEO for Good Reason 500,000(8) 3,675,082 22,800(4) 4.488,788 CIC with Involuntary Termination 1,000,000(9) 3,670,082 45,600(6) 5,011,588 (1)Represents the value of accelerated vesting of option awards and stock awards. Amounts reflected assume that all applicable performance targets forany performance-vesting awards are achieved.(2)Reflects an amount equal to 6 months of COBRA premiums.(3)Represents a lump sum severance payment equal to 12 months of base salary plus acceleration of a $200,000 sign-on retention bonus.(4)Reflects an amount equal to 12 months of COBRA premiums.(5)Represents a lump sum severance payment equal to 24 months of base salary plus acceleration of a $200,000 sign-on retention bonus.(6)Reflects an amount equal to 24 months of COBRA premiums.(7)Pursuant to his resignation on August 3, 2017, we entered into a separation and consulting agreement with Mr. Mirman. Under the terms of theagreement, Mr. Mirman was provided with (1) a lump sum cash payment of $1,000,000; (2) premium payments for continuing COBRA coverage for18 months with a value of approximately $34,000; and (3) reimbursement of reasonable attorneys’ fees incurred in connection with his separationwith a value of approximately $156,000. In addition, all of Mr. Mirman’s unvested options and restricted stock accelerated pursuant to the terms ofhis separation and consulting agreement, valued at approximately $4.4 million. (8)Represents a lump sum severance payment equal to 12 months of base salary.(9)Represents a lump sum severance payment equal to 24 months of base salary.(10)Pursuant to his termination on February 13, 2017, we entered into a separation agreement with Mr. Nanke. Under the terms of the agreement, he wasprovided with (1) a lump sum severance payment equal to 24 months of his base salary ($275,000); (2) a lump sum payment equal to 24 months ofCOBRA payments ($51,000); and (3) a lump sum payment bonus payment of $175,000. Mr. Nanke also held 418,750 unexercised stock optiongrants with an exercise price of $1.34, which vested at the time of his separation.(11)In connection with her separation from the Company in February 2018, we entered into an agreement with Ms. Fuchs pursuant to which she willreceive severance and other consideration pursuant to the terms of her employment agreement and stock award agreements plus additional nominalconsideration.(12)In connection with his separation of employment with the Company in March 2018, in accordance with the terms of his employment agreement andstock award agreements, Mr. Short did not receive severance or other consideration. 74  DIRECTOR COMPENSATION The following table shows the total compensation for our nonemployee directors for their service to our Board during 2017. All references to“directors” in this Director Compensation section are to nonemployee members of our Board. Name Fees Earnedor Paid inCash($) Stock Awards($)(1) Option Awards($) All OtherCompensation($) Total($) G. Tyler Runnels(2) 19,076 ─ ─ ─ 19,076 Nuno Brandolini(3) 60,000 171,825 ─ ─ 231,825 General Merrill McPeak(4) 85,000 171,825 ─ ─ 256,825 R. Glenn Dawson(5) 85,000 415,000 ─ 500,000 Peter Benz(6) 85,000 171,825 ─ 256,825 Mark Christensen(7) 19,076 ─ ─ ─ 19,076 (1)Represents restricted stock awards. Awards in this column are reported at grant date fair value in accordance with FASB ASC Topic 718. Theamounts 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, 2017, Mr. Brandolini, General McPeak, and Mr. Benz were each granted 15,000 shares of restricted stock and Mr. Dawson wasgranted 103,750 shares of restricted stock. These awards all vested in full immediately. On October 17, 2017, Mr. Brandolini, General McPeak, andMr. Benz were each granted 22,500 shares of restricted stock, which all vested in full immediately.(2)Mr. Runnels was appointed to our Board on September 6, 2017.(3)Mr. Brandolini was appointed to our Board on February 13, 2014.(4)General McPeak was appointed to our Board on January 29, 2015.(5)Mr. Dawson was appointed to our Board on January 13, 2016.(6)Mr. Benz was appointed to our Board on June 23, 2016.(7)Mr. Christensen was appointed to our Board on September 6, 2017. Nonemployee Director Compensation Program. Our nonemployee Board members are paid a base annual cash retainer that is intended tocompensate the directors for (1) attendance at all meetings to which the director has been assigned; (2) voluntary attendance at meetings to which the directorhas not been assigned; (3) time spent by the director to continue to improve industry knowledge and Board skills; and (4) ad hoc discussions and telephonecalls by the director—these include discussions and calls that do not have a formal agenda noticed in accordance with the Company’s Bylaws and for whichminutes are not kept. Our compensation committee administers our director compensation program. In addition to the services Longnecker provided to the compensationcommittee on executive compensation, Longnecker reviewed market data from the Company’s compensation peer group for director compensation,including annual cash retainers, meeting fees and/or equity retainers. The peer group consisted of the same companies utilized to evaluate executivecompensation. Longnecker developed recommendations for the compensation committee to consider that were designed to align the Company near the 50thpercentile of the peer group. Annual Cash Retainers. Directors will be paid an additional annual retainer for holding the position of Board Chairperson (in the case of a non-executive chairperson), Board Committee Chairperson, or Board Committee Member. The base annual cash retainer and committee member annual cashretainers are as follows: Retainer Type Annual Retainer Amount Director $60,000 Board Chair (non-executive) $50,000 Audit Committee Chair $25,000 Audit Committee Member $12,500 Reserves Committee Chair $240,000(1) Compensation Committee Chair $25,000 Compensation Committee Member $10,000 Nominating and Corporate Governance Chair $10,000 Nominating and Corporate Governance Committee Member $7,500 (1)The current annual retainer amount paid to the Reserves Committee Chair is in consideration for additional technical responsibilities currentlybeing performed by such Chair at the request of the Board and is subject to monthly review and termination or reduction by the Board in theevent that it determines that the performance by such Chair of such responsibilities is no longer advisable and in the best interests of theCompany. All cash retainers will be paid in quarterly installments, in the first week of each calendar quarter. All annual cash retainers may be prorated based onactive status of the director. Initial Restricted Stock Grant. Each new director will receive an initial grant of 10,000 restricted shares of common stock, which will be granted onthe first Annual Equity Date (as defined below) for which the director serves on our Board and will vest in the following increments on the specified dates, solong as the director remains a member of our Board through the vesting date: •3,334 shares on the first anniversary of the director’s first Annual Equity Date; 75  •3,333 shares on the second anniversary of the director’s first Annual Equity Date; and•3,333 shares on the third anniversary of the director’s first Annual Equity Date. Initial Option Award Grant. Each new director will receive an initial grant of 45,000 options to purchase shares of common stock, which will begranted on the first Annual Equity Date for which the director serves on our Board and will vest in the following increments on the specified dates, so long asthe director remains a member of our Board through the vesting date: •25,000 options on the date of the grant;•6,667 options on the first anniversary of the director’s first Annual Equity Date;•6,667 options on the second anniversary of the director’s first Annual Equity Date; and•6,666 options on the third anniversary of the director’s first Annual Equity Date. Annual Equity Grants. The “Annual Equity Date” will be the first business day on or after January 31 of each year. On each Annual Equity Date, solong as the director remains a member of our Board on such date, the Company will issue to the director a number of fully vested shares of common stockequal to $150,000 (or, in the event the director has not served a full calendar year by that date, a prorated amount) divided by the most recent per shareclosing price of the common stock. Company Equity Compensation Plans. All director equity awards will be granted under, and subject to the terms and conditions of, the Company’sequity compensation plan in effect at the time the award is granted. Change in Control. In the event of a change in control (as defined in the Company’s equity compensation plan then in effect), the Board willconsider awards to directors for their service from the most recent Annual Equity Date through the change in control, in order to compensate the directors forthe missed opportunity to receive an award on the next scheduled Annual Equity Date. Additional Payments. Any additional cash or equity retainer may be granted by our Board based on active status of assignments of the director. Annual Limits on Awards to Nonemployee Directors. The maximum number of shares subject to Company equity compensation plan awards grantedduring any calendar year to any director, taken together with any cash fees paid to the director during the year, may not exceed $500,000 in total value(calculating the value of any Company equity compensation plan awards based on the grant date fair value of such awards for financial reporting purposes). 76  CEO PAY RATIO As required by applicable SEC rules, we are providing the following information about the relationship of the annual total compensation of ouremployees and the annual total compensation of James Linville, our CEO on December 31, 2017. The pay ratio included in this information is a reasonableestimate calculated in a manner consistent with Item 402(u) of Regulation S-K. For 2017, the median of the annual total compensation of all our employees (other than our CEO) was $0.5 million (inclusive of stock basedcompensation); and the annual total compensation of our CEO, as reported in the Summary Compensation Table included above (adjusted as noted below),and then annualized for purposes of this pay ratio disclosure, was $2.2 million. Based on this information, for 2017 the ratio of the annual total compensationof our CEO to the median of the annual total compensation of all our employees was 4 to 1. We took the following steps to identify the median of the annual total compensation of all our employees, as well as to determine the annual totalcompensation of our median employee and our CEO. 1.We determined that, as of December 31, 2017, our employee population consisted of approximately 27 individuals. This population consisted of ourfull-time, part-time, and temporary employees employed with us as of the determination date.2.To identify the “median employee” from our employee population, we used the amount of “gross wages” for the identified employees as reflected inour payroll records for 2017. For gross wages, we generally used the total amount of compensation the employees were paid before any taxes,deductions, insurance premiums, and other payroll withholding. We did not use any statistical sampling techniques.3.For the annual total compensation of our median employee, we identified and calculated the elements of that employee’s compensation for 2017 inaccordance with the requirements of Item 402(c)(2)(x).4.For the annual total compensation of our CEO, we used the amount reported in the “Total” column of our 2017 Summary Compensation Table,adjusted as follows. a)As noted elsewhere above, Mr. Linville began serving as our CEO effective August 4, 2017, upon the resignation of Abraham “Avi”Mirman, our former CEO. We identified Mr. Linville as our CEO for this pay ratio disclosure because he was serving in that position onDecember 31, 2017, the date that we selected to identify our median employee. b)As Mr. Linville served as our CEO for only a portion of 2017, in accordance with applicable SEC rules, we annualized the amount reportedin the Summary Compensation Table above. This resulted in annual total compensation for purposes of determining the ratio in the amountof $2.2 million, which exceeds the amount reported for Mr. Linville in the Summary Compensation Table by $0.2 million. c)To maintain consistency between the annual total compensation of our CEO and the median employee, we also added the estimated valueof our CEO’s health care benefits on an annualized basis (estimated for our CEO and our CEO’s eligible dependents at $0.02 million) to theamount reported in the Summary Compensation Table, as annualized as described in b) immediately above. 77  EQUITY COMPENSATION PLAN INFORMATION The following table provides information as of December 31, 2017 regarding the number of shares of our common stock that may be issued underour equity compensation plans: Plan category Number of securities to beissued upon exercise ofoutstanding options,warrants and rights(1) Weighted-average exerciseprice of outstanding options,warrants and rights(2) Number of securitiesremaining available forfuture issuance under equitycompensation plans(excluding securitiesreflected in column(1)) Equity compensation plans approved by security holders 7,301,899 $3.74 607,186 Equity compensation plans not approved by securityholders ─ ─ ─ Total 7,301,899 $3.74 607,186 (1)Includes stock options and RSUs outstanding under our 2016 Plan and our 2012 EIP as of December 31, 2017. Does not include shares of restrictedstock issued pursuant to our 2016 Plan or our 2012 EIP. (2)Represents the weighted average exercise price of outstanding options issued pursuant to our 2016 Plan and our 2012 EIP as of December 31, 2017.Does not take into account outstanding RSUs. Other Equity Compensation We have entered into various services agreements for which compensation has been paid with equity securities, including (i) a consulting agreementwith Bristol pursuant to which we issued to Bristol a five year warrant to purchase up to 641,026 shares of common stock at an exercise price of $3.12 pershare (or, in the alternative, 641,026 options, but in no case both), (ii) consulting agreements with Market Development Consulting Group, Inc. pursuant towhich we issued five year warrants to purchase up to an aggregate of 500,000 shares of common stock ,with an exercise price of $2.33 for the warrant topurchase 250,000 shares of common stock and an exercise price of $2.00 for the warrant to purchase 250,000 shares of common stock; (iii) an investmentbanking agreement with TRW pursuant to which we issued 900,000 warrants at an exercise price of $4.25 per share; and (iv) various agreements pursuant towhich issued an aggregate amount of 150,000 and 300,000 five year warrants to purchase shares of common stock at an exercise price of $2.50 and $2.00,respectively. With respect to the warrants awarded to Bristol, we recorded the warrants as a derivative due to the price reset provision encompassed in thewarrants. 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 Securities Authorized for Issuance under Equity Compensation Plans Please see “Item 11 – Equity Compensation Plan Information” above. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The following table sets forth certain information with respect to beneficial ownership of our common stock as of March 5, 2018, by each of ourexecutive 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 March 5, 2018 of 53,496,205. Unless otherwise indicated, the persons andentities named in the table have sole voting and sole investment power with respect to the shares set forth opposite the stockholder’s name. Beneficialownership is determined in accordance with Rule 13d-3 under the Exchange Act. In computing the number of shares beneficially owned by a person or agroup and the percentage ownership of that person or group, shares of our common stock subject to options or warrants currently exercisable or exercisablewithin 60 days after March 5, 2018 are deemed outstanding by such person or group, but are not deemed outstanding for the purpose of computing thepercentage 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 ouroutstanding 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.,300 E. Sonterra Blvd. Ste. 1220, San Antonio, Texas 78258. 78  Series C Preferred Stock Common Stock Name and Address of Beneficial Owner Shared Beneficially Owned % of Class LiliscommonstockHeldDirectly LiliscommonstockAcquirableWithin 60Days(1) TotalBeneficiallyOwned(1) Percent ofClassBeneficiallyOwned(1) Directors and Named Executive Officers Ronald D. Ormand, Executive Chairman of the Board — — 4,002,253(2) 199,167(3) 4,201,420 7.8%(4)James Linville, Chief Executive Officer — — 159,352 110,500(5) 269,852 * Joseph Daches, Chief Financial Officer — — 578,676 502,500(6) 1,081,176 2.0%Peter Benz, Director — — 132,384 31,667(7) 164,051 * Nuno Brandolini, Director — — 499,445 119,575(8) 619,020 1.2%R. Glenn Dawson, Director — — 650,578 183,335(9) 833,913 1.6%General Merrill McPeak, Director — — 466,922 150,157(10) 617,109 1.2%G. Tyler Runnels, Director — — 2,121,790(11) 128,325(12) 2,250,115 4.2%Mark Christensen, Director 1,215,843(13) 1,043,052(14) 2,258,895 4.1%Markus Specks, Director — — — — — * John Johanning, Director — — — — — * Directors and Officers as a Group (12 persons) — — 10,188,207 2,702,308(15) 12,890,335 22.9%(16) 5% Stockholders Abraham Mirman (Former Chief Executive Officer and FormerDirector) 20 Broad Hollow Road, Suite 3011BMelville, NY 11747 — — 2,384,522(17) 1,810,000(18) 4,194,522 7.6%Bryan Ezralow, 23622 Calabasas Road, Suite 200, Calabasas, CA 913012 — — 3,486,676(19) 272,731(20) 3,759,407 7.0%Marc Ezralow, 23622 Calabasas Road, Suite 200, Calabasas, CA 913012 — — 2,783,559(21) 220,783(22) 3,004,342 5.6%J. Steven Emerson, 1522 Ensley Avenue, Los Angeles, CA 90024 — — 4,064,074(23) 324,678(24) 4,388,752 8.2%Rosseau Asset Management Ltd.181 Bay Street, Suite 2920, Box 736Toronto, Ontario M5J 2T3 — — 2,712,334(25) —(26) 2,712,334 5.1%Investor Company 5J5505DVertex One Asset Management1021 West Hastings Street, Suite 3200 Vancouver, BC V6E 0C3 — — 7,189,480(27) — 7,189,480 13.4%Vӓrde Partners, Inc. 901 Marquette Avenue South Suite 330, Minneapolis, MN 55402 100,000 100% — 43,592,196(28) 43,592,196 44.9% *Represents beneficial ownership of less than 1% of the outstanding shares of common stock. (1)Excluding the outstanding warrants issued in connection with our March 2017 Private Placement, the terms of the Company’s outstanding warrants,(the “Blocker Securities”) contain a provision prohibiting the conversion of the exercise of warrants into common stock of the Company if, uponexercise, as applicable, the holder thereof would beneficially own more than a certain percentage of the Company’s then outstanding common stock(the “Blocker Limitation”). This percentage limitation is 4.99%. Accordingly, the share numbers in the above table represent ownership after givingeffect to the beneficial ownership limitations described in this footnote. However, the foregoing restrictions do not prevent such holder fromexercising, as applicable, some of its holdings, selling those shares, and then exercising, as applicable, more of its holdings, while still staying belowthe percentage limitation. As a result, the holder could sell more than any applicable ownership limitation while never actually holding more sharesthan the applicable limitations allow. Thus, while the ownership percentages are also given with regard to this beneficial ownership limitation,specific footnotes indicate what the ownership would be as of August 24, 2017, without giving effect to limitation 79  (2)Consists of: (i) 1,583,555 shares of common stock held directly by Mr. Ormand; (ii) 2,378,698 shares of common stock held by Perugia InvestmentsL.P. (“Perugia”); and (iii) 40,000 shares of common stock held by The Bruin Trust, an irrevocable trust managed by Jerry Ormand, Mr. Ormand’sbrother, as trustee and whose beneficiaries include the adult children of Mr. Ormand. Mr. Ormand is the manager of Perugia and has sole voting anddispositive power over the securities held by Perugia. (3)Represents shares of common stock subject to options exercisable within 60 days. In addition, Mr. Ormand beneficially owns an aggregate of 993,102 additional shares of common stock acquirable within 60 days, each of which issubject to a Blocker Limitation. However, Mr. Ormand’s percentage ownership is currently in excess of such Blocker Limitations, and as a result,such Blocker Securities have been excluded from the table. These Blocker Securities consist of the following: (i) 533,102 shares of common stockissuable upon exercise of warrants held by Perugia; and (ii) 460,000 shares of common stock issuable upon exercise of warrants held by The BruinTrust. (4)Including the Blocker Securities, and ignoring the Blocker Limitation, Mr. Ormand beneficially owns a total of 5,194,522 shares of common stock,which represents 9.5% of our currently issued and outstanding common stock. (5)Represents shares of common stock subject to options exercisable within 60 days. (6)Represents shares of common stock subject to options exercisable within 60 days. (7)Represents shares of common stock subject to options exercisable within 60 days. (8)Represents shares of common stock subject to options exercisable within 60 days. (9)Represents shares of common stock subject to options exercisable within 60 days. (10)Represents shares of common stock subject to options exercisable within 60 days. (11)Consists of: (i) 71,744 shares of common stock held directly by Mr. Runnels; (ii) 267,436 shares of common stock held by T.R. Winston &Company, LLC (“TRW”); (iii) 534,899 shares of common stock held by TRW Capital Growth Fund, LP; (iv) 1,218,005 shares of common stock heldby Runnels Family Trust DTD 1-11-2000 (“Runnels Family Trust”), for which Mr. Runnels acts as trustee with Jasmine N. Runnels, who share votingand dispositive power; (v) 29,300 shares of common stock held by High Tide, LLC (“High Tide”); (vi) 402 shares of common stock held by PangaeaPartners, LLC; and (vii) 3 shares of common stock held by SEP IRA Pershing LLC Custodian (“SEP IRA”). Mr. Runnels is the natural person withultimate voting and dispositive power over the securities held by TRW, TRW Capital Grown Fund, LP, High Tide, Pangaea Partners, LLC and SEPIRA. (12)Represents shares of common stock subject to options and warrants exercisable within 60 days. In addition, Mr. Runnels beneficially owns an aggregate of 1,011,406 additional shares of common stock acquirable within 60 days, each of whichis subject to a Blocker Limitation. However, Mr. Runnels’ percentage ownership is currently in excess of such Blocker Limitations, and as a result,such Blocker Securities have been excluded from the table. These Blocker Securities consist of the following: (i) 636,046 shares of common stockissuable upon exercise of warrants held by TRW; and (ii) 375,360 shares of common stock issuable upon exercise of warrants held by RunnelsFamily Trust. (13)Consists of: (i) 23,954 shares of common stock held directly by Mr. Christensen; (ii) 1,103,362 shares of common stock held by Trace Capital Inc.(“Trace”), for which Mr. Christensen’s wife is the natural person with ultimate voting and dispositive power; and (ii) 88,527 shares of common stockheld by GM&P Holding Corp., for which Mr. Christensen is the natural person with ultimate voting and dispositive power. (14)Represents shares of common stock subject to options and warrants exercisable within 60 days. (15)As indicated in the above footnotes, this amount excludes an aggregate of 2,004,508 additional shares of common stock acquirable within 60 days,which are subject to Blocker Limitations. (16)Including the Blocker Securities, and ignoring the Blocker Limitation, the directors and officers as a group beneficially own a total of 14,894,843shares of common stock, which represents 25.6% of our currently issued and outstanding common stock. 80  (17)Consists of: (i) 1,203,087 shares of common stock held by The Bralina Group, LLC; and (ii) 1,181,435 shares of common stock held directly by Mr.Mirman. Mr. Mirman has shared voting and dispositive power over the securities held by The Bralina Group, LLC with Susan Mirman. (18)Represents shares of common stock subject to options exercisable within 60 days. In addition, Mr. Mirman beneficially owns an aggregate of 850,641 additional shares of common stock acquirable within 60 days, each of which issubject to a Blocker Limitation. However, Mr. Mirman’s percentage ownership is currently in excess of such Blocker Limitations, and as a result,such Blocker Securities have been excluded from the table. These Blocker Securities consist of the following: (i) 545,454 shares of common stockissuable upon exercise of warrants held by the Bralina Group, LLC and (ii) 305,187 shares of common stock issuable upon exercise of warrants helddirectly by Mr. Mirman. (19)Based solely on a Schedule 13G filed by Bryan Ezralow on February 13, 2018. Collectively, the shares of common stock reported herein in whichBryan Ezralow has shared voting and dispositive power over such shares is an aggregate of 2,092,723 shares. Such shares are held directly by (a) theEzralow Family Trust u/t/d 12/9/1980 (the “Family Trust”) in the amount of 94,106 shares, where Bryan Ezralow as a co-trustee of the Family Trustshares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; (b) the Ezralow Marital Trust u/t/d1/12/2002 (the “Marital Trust”) in the amount of 101,571 shares, where Bryan Ezralow as a co-trustee of the Marital Trust shares voting anddispositive power over such shares, and thus, may be deemed to beneficially own such shares; (c) Elevado Investment Company, LLC, a Delawarelimited liability company (“Elevado Investment”), in the amount of 416,252 shares, where Bryan Ezralow as a co-trustee and manager, respectively,of the two trusts and limited liability company that comprise the managing members of Elevado Investment, shares voting and dispositive powerover such shares, and thus, may be deemed to beneficially own such shares; (d) EMSE LLC (“EMSE”), a Delaware limited liability company, in theamount of 495,674 shares, where Bryan Ezralow, as a manager of EMSE, shares voting and dispositive power over such shares, and thus, may bedeemed to beneficially own such shares; (e) EZ Colony Partners, LLC, a Delaware limited liability company (“EZ Colony”), in the amount of985,117 shares, where Bryan Ezralow as the sole trustee of one of the trusts that is a manager of EZ Colony, shares voting and dispositive power oversuch shares, and thus, may be deemed to beneficially own such shares; and (f) EZ MM&B Holdings, LLC, a Delaware limited liability company (“EZMM&B”), in the amount of 3 shares, where Bryan Ezralow as the sole trustee of one of the trusts that is a manager of EZ MM&B, and as a co-trusteeand manager, respectively, of the two trusts and limited liability company that comprise the managing members of one of the other managers of EZMM&B, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares. 81  Collectively, the shares of common stock reported herein in which Bryan Ezralow has sole voting and dispositive power over such shares are1,393,953 shares. Such shares are held directly by (a) the Bryan Ezralow 1994 Trust u/t/d/12/22/1994, Bryan Ezralow, Trustee (the “Bryan Trust”) inthe amount of 1,258,098 shares, where Bryan Ezralow as sole trustee of the Bryan Trust has sole voting and dispositive power over such shares, andthus, may be deemed to beneficially own such shares; and (b) the Marc Ezralow Irrevocable Trust u/t/d 6/1/2004 (the “Irrevocable Trust”) in theamount of 135,855 shares, where Bryan Ezralow as sole trustee of the Irrevocable Trust has sole voting and dispositive power over such shares, andthus, may be deemed to beneficially own such shares. (20)Represents shares of common stock subject to warrants exercisable within 60 days. In addition, Bryan Ezralow beneficially owns an aggregate of 836,712 additional shares of common stock acquirable within 60 days, each of whichis subject to a Blocker Limitation. However, the percentage ownership by Bryan Ezralow is currently in excess of such Blocker Limitations, and as aresult, such Blocker Securities have been excluded from the table. These Blocker Securities consist of the following: (i) 295,455 shares of commonstock issuable upon the exercise of warrants, held by the Bryan Trust; (ii) 43,182 shares of common stock issuable upon the exercise of warrants,held by the Irrevocable Trust; (iii) 125,889 shares of common stock issuable upon the exercise of warrants, held by Elevado; (iv) 266,088 shares ofcommon stock issuable upon the exercise of warrants, held by EZ Colony; (v) 43,912 shares of common stock issuable upon the exercise of warrants,held by the Marital Trust; (vi) 41,285 shares of common stock issuable upon the exercise of warrants, held by the Family Trust; and (vii) 20,899shares of common stock issuable upon the exercise of warrants, held by EMSE. (21)Based solely on a Schedule 13G filed by Marc Ezralow on February 14, 2018. Collectively, the shares of common stock reported herein in whichMarc Ezralow has shared voting and dispositive power over such shares are an aggregate of 2,092,723 shares. Such shares are held directly by (a) theEzralow Family Trust u/t/d 12/9/1980 (the “Family Trust”) in the amount of 94,106 shares, where Marc Ezralow, as a co-trustee of the Family Trust,shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; (b) the Ezralow Marital Trust u/t/d1/12/2002 (the “Marital Trust”) in the amount of 101,571 shares, where Marc Ezralow, as a co-trustee of the Marital Trust, shares voting anddispositive power over such shares, and thus, may be deemed to beneficially own such shares; (c) Elevado Investment Company, LLC, a Delawarelimited liability company (“Elevado Investment”), in the amount of 416,252 shares, where Marc Ezralow as a co-trustee and manager, respectively,of the two trusts and limited liability company that comprise the managing members of Elevado Investment, shares voting and dispositive powerover such shares, and thus, be deemed to beneficially own such shares; (d) EMSE LLC (“EMSE”), a Delaware limited liability company, in theamount of 495,674 shares, where Marc Ezralow, as a manager of EMSE shares voting and dispositive power over such shares, and thus, may bedeemed to beneficially own such shares; (e) EZ Colony Partners, LLC, a Delaware limited liability company (“EZ Colony”), in the amount of985,117 shares, where Marc Ezralow as the sole trustee of one of the trusts that is a manager of EZ Colony, shares voting and dispositive power oversuch shares, and thus, may be deemed to beneficially own such shares; and (f) EZ MM&B Holdings, LLC, a Delaware limited liability company(“EZ MM&B”) in the amount of 3 shares, where Marc Ezralow as the sole trustee of one of the trusts that is a manager of EZ MM&B, and as a co-trustee and manager, respectively, of the two trusts and limited liability company that comprise the managing members of one of the other managersof EZ MM&B, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares. Collectively, the shares of common stock reported herein in which Marc Ezralow has sole voting and dispositive power over said common stock are690,836 shares. Such shares are held directly by (a) the Marc Ezralow 1997 Trust u/t/d/11/26/1997, Marc Ezralow, Trustee (the “Marc Trust”) in theamount of 554,981 shares, where Marc Ezralow as sole trustee of the Marc Trust has sole voting and dispositive power over such shares, and thus,may be deemed to beneficially own such shares; and (b) the SPA Trust u/t/d 9/13/2004 (the “SPA Trust”), in the amount of 135,855 shares, whereMarc Ezralow as sole trustee of the SPA Trust has sole voting and dispositive power over such shares, and thus, may be deemed to beneficially ownsuch shares. (22)Represents shares of common stock subject to warrants exercisable within 60 days. In addition, Marc Ezralow beneficially owns an aggregate of 711,710 additional shares of common stock acquirable within 60 days, each of which issubject to a Blocker Limitation. However, the percentage ownership by Marc Ezralow is currently in excess of such Blocker Limitations, and as aresult, such Blocker Securities have been excluded from the table. These Blocker Securities consist of the following: (i) 43,182 shares of commonstock issuable upon exercise of warrants, held the SPA Trust; (ii) 170,455 shares of common stock issuable upon exercise of warrants, held by the1997 Trust; (iii) 125,889 shares of common stock issuable upon the exercise of warrants, held by Elevado; (iv) 266,088 shares of common stockissuable upon the exercise of warrants, held by EZ Colony; (v) 43,912 shares of common stock issuable upon the exercise of warrants, held by theMarital Trust; (vi) 41,285 shares of common stock issuable upon the exercise of warrants, held by the Family Trust; and (vii) 20,899 shares ofcommon stock issuable upon the exercise of warrants, held by EMSE.. (23)Based on the Schedule 13D filed on May 19, 2017, this consists of: (i) 1,630,652 shares of common stock held by J. Steven Emerson Roth IRAPershing LLC as Custodian (“Roth IRA Pershing”); (ii) 1,371,067 shares of common stock held by J. Steven Emerson IRA Rollover II Pershing LLCas Custodian (“IRA Rollover II Pershing”); (iii) 430,945 shares of common stock held by Emerson Partners (“Emerson”); (iv) 583,237 shares ofcommon stock held directly by J. Steven Emerson; (v) 48,173 shares of common stock held by the Emerson Family Foundation. J. Steven Emerson isthe natural person with ultimate voting or investment control over the shares of common stock held by each of Roth IRA Pershing, IRA Rollover IIPershing, Emerson and the Emerson Family Foundation. (24)Represents shares of common stock subject to warrants exercisable within 60 days. (25)Based on the Schedule 13G/A filed on February 14, 2018. The natural person with ultimate voting or investment control over the shares of commonstock held is Warren Irwin. (26)Rosseau Asset Management (“Rosseau”) beneficially owns an aggregate of 1,136,364 additional shares of common stock acquirable within 60 days,each of which is subject to a Blocker Limitation. However, Rosseau’s percentage ownership is currently in excess of such Blocker Limitations, andas a result, such Blocker Securities have been excluded from the table. These Blocker Securities consist of 1,136,364 shares of common stockissuable upon exercise of warrants. (27)Based on the Schedule 13G filed on February 9, 2018. The natural person with ultimate voting or investment control over the shares of commonstock held is John Thiessen. (28)Based on the Schedule 13D/A filed on February 5, 2018. This represents shares of common stock which may be issued pursuant to the conversion ofterm loans under the Second Lien Credit Agreement and shares of Series C Preferred Stock within 60 days as if such term loans and Series C PreferredStock had been converted on the date of borrowing or issuance, as applicable. 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 VärdeFund XII (Master), L.P.; The Värde Master Skyway Fund, L.P., The Värde Fund VI-A, L.P., Värde Investment Partners, L.P., and Värde InvestmentPartners (Offshore) Master, L.P. (the “Värde Entities”), or of the General Partners’ managing members. Mr. George Hicks is the chief executive officerof Värde Partners, Inc. As such each of Värde Partners, Inc. and Mr. Hicks may be deemed to have beneficial ownership of the shares owned by eachof the Värde Entities. Each of Värde Partners, Inc. and Mr. Hicks disclaims beneficial ownership of the securities held indirectly through the VärdeEntities except to the extent of their pecuniary interest therein, and this disclosure shall not be deemed an admission that any such reporting personis the beneficial owner for purposes of this Annual Report or for any other purpose. 82  To our knowledge, except as noted above, no person or entity is the beneficial owner of 5% or more of our common stock. Item 13.Certain Relationships and Related Transactions, and Director Independence Transactions with Related Parties We describe below transactions and series of similar transactions, since January 1, 2017, 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 twocompleted 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 personsharing the household with, any of the foregoing persons, who had or will have a direct or indirect material interest. All share and per share amounts applicable to our common stock from transactions that occurred prior to the June 23, 2016 reverse split in thefollowing summaries of related party transactions have not been adjusted to reflect the 1-for-10 reverse split of our issued and outstanding common stock,unless specifically described below. Series B Preferred Stock Private Placement On June 15, 2016, we entered into the Series B Purchase Agreement with certain institutional and accredited investors (the “Series B Purchasers”) inconnection with the Series B Preferred Stock offering. On June 6, 2016, we entered into a Transaction Fee Agreement, which was subsequently amended on June 8, 2016, with TRW, a more than 5%stockholder of our Company during the year ended December 31, 2016, in connection with the Series B Preferred Stock offering to act as co-broker dealersalong with KES 7, and as administrative agent. TRW received a cash fee of $500,000 and broker warrants to purchase up to 452,724 shares of common stock,at an exercise price of $1.30, exercisable on or after September 17, 2016, for a period of two years. Of the cash fee paid to TRW, $150,000 was reinvested intothe Series B Preferred Stock offering in exchange for 150 shares of Series B Preferred Stock and the related warrants to purchase 68,182 shares of commonstock at an exercise price of $2.50. These fees were recorded as a reduction to equity. Certain other Series B Purchasers in the Series B Preferred Stock offering include the following related parties: (i) Abraham Mirman, our former ChiefExecutive Officer and director, purchased $1.65 million of Series B Preferred Stock through the Bralina Group, LLC for which Mr. Mirman holds sharedvoting and dispositive power; (ii) Ronald D. Ormand, the Chairman of our Board of Directors, purchased $1.0 million of Series B Preferred Stock throughPerugia Investments LP for which Mr. Ormand holds sole voting and dispositive power; (iii) Kevin Nanke, the Company’s former Executive Vice Presidentand Chief Financial Officer during the year ended December 31, 2016, purchased $200,000 of Series B Preferred Stock through KKN Holdings LLC, forwhich Mr. Nanke holds sole voting and dispositive power; (iv) R. Glenn Dawson, a director of our Company, purchased $125,000 of Series B Preferred Stock;and (v) Bryan Ezralow and Marc Ezralow, who are each a more than 5% stockholder of our Company, purchased $1.3 million of Series B Preferred Stockthrough various entities beneficially owned by them. On April 25, 2017, the Company entered into a Series B 6.0% Convertible Preferred Stock Conversion Agreement (the “Conversion Agreement”),with all of the holders of the outstanding Series B Preferred Stock (the “Series B Holders”) to convert any outstanding shares of Series B Preferred Stockincluding an increase in the stated value of to reflect dividends that would have accrued through December 31, 2017 in the amount of approximately 14.3million shares of common stock. On the same date, the Series B Holders further agreed to adopt the Amended and Restated Certificate of Designation ofPreferences, Rights and Limitations of Series B 6% Convertible Preferred Stock (“A&R COD”) in order to remove certain restrictions contained therein withrespect to beneficial ownership limitations, a condition of the Conversion Agreement. The A&R COD became effective on April 26, 2017, resulting in theautomatic conversion of all outstanding Series B Preferred Stock. As a result of the automatic conversion, certain of our related parties received shares of ourcommon stock: (i) Abraham Mirman received 1,639,000 shares of common stock valued at $8.4 million through the Bralina Group, LLC for which Mr.Mirman holds shared voting and dispositive power; (ii) Ronald D. Ormand received 993,334 shares of common stock valued at $5.1 million through PerugiaInvestments LP for which Mr. Ormand holds sole voting and dispositive power; (iii) Kevin Nanke received 198,667 shares of common stock valued at $1.0million; (iv) R. Glenn Dawson received 117,822 shares of common stock valued at $0.6 million; (v) Bryan Ezralow received 894,001 shares of common stockvalued at $4.6 million through various entities beneficially owned by him; (vi) Marc Ezralow received 745,001 shares of common stock valued at $3.8million through various entities beneficially owned by him; (vii) Rosseau Asset Management Ltd received 1,986,667 shares of common stock valued at$10.2 million; (viii) Investor Company 5J5505D received 3,925,654 shares of common stock valued at $20.1 million; (ix) J. Steven Emerson received1,490,000 shares of common stock valued at $7.6 million through various entities beneficially owned by him; and (x) G. Tyler Runnels received 472,827shares of common stock valued at $2.4 million through various entities beneficially owned by him. 83  For more information on the Series B Preferred Stock offering see Note 11 Stockholders Equity to our consolidated financial statements in Item 8 ofthis Annual Report on Form 10-K. First Lien Credit Agreement, Drawdown, Repayment and Amendment. On September 29, 2016, we entered into the First Lien Credit Agreement. Certain parties to the First Lien Credit Agreement included our relatedparties: (i) TRW, acting as collateral agent, (ii) Bryan Ezralow through certain of his investment entities, (iii) Marc Ezralow through certain of his investmententities, (iv) J. Steven Emerson through certain of his investment entities, and (v) Investor Company 5J5505D. On February 7, 2017, pursuant to the terms of the First Lien Credit Agreement, we exercised the accordion advance feature, increasing the aggregateprincipal amount outstanding under the term loan from $31 million to $38.1 million (the “First Lien Term Loan”). Certain parties that participated in theupsize of the First Lien Term Loan included our related parties: (i) Rosseau Asset Management Ltd ($2 million), (ii) Trace Capital Inc. ($1.6 million), and (iii)LOGiQ Capital 2016 ($1 million). On April 24, 2017, we entered into an amendment to the First Lien Credit Agreement, in which the balance of the first lien credit facility in anaggregate amount of $38.1 million plus accrued and unpaid interest thereon was paid down and we extended further credit in the form of an initial bridgeloan in an aggregate principal amount of $15.0 million. Certain parties that were paid down pursuant to the First Lien Amendments included certain of our related parties such as TRW, acting as collateralagent, Bryan Ezralow and Marc Ezralow, through certain of their investment entities ($2.4 million), J. Steven Emerson through certain of his investmententities ($6.0 million), Rosseau Asset Management Ltd ($2.0 million), LOGiQ Capital 2016 ($1.0 million), and Investor Company 5J5505D ($20.1 million).Certain parties to the bridge loan and the incremental bridge loan included certain of our related parties such as: (i) Investor Company 5J5505D ($3.3million), and (ii) Trace Capital Inc ($2.95 million). In addition, on October 19, 2017, pursuant to the First Lien Amendments, the lenders made further extensions of credit, in addition to the currentlyexisting loans under the First Lien Credit Agreement, in the form of an additional, incremental bridge loan in an aggregate principal amount of $15,000,000. Second Lien Credit Agreement On April 26, 2017, we entered into the Second Lien Credit Agreement with the lenders party thereto. Värde Partners, Inc. is the lead lender under theSecond Lien Credit Agreement and, as a result of its conversion rights thereunder, it beneficially owns over 5% of our securities that are acquirable within 60days. For more information about the Second Lien Credit Agreement, see “Management’s Discussion and Analysis of Financial Condition and Results ofOperations – Liquidity and Capital Resources – Second Lien Credit Agreement” under Item 7 of this report. March 2017 Private Placement On February 28, 2017, we entered into a Securities Purchase Agreement in connection with the March 2017 Private Placement. As of December 31,2017, we received aggregate gross proceeds of $20 million and issued 5,194,821 shares of common stock and warrants to purchase 2,597,420 shares ofcommon stock. 84  The subscribers include the following related parties: (i) Bryan Ezralow, the beneficial owner of 5% or more of our common stock, through the BryanEzralow 1994 Trust u/t/d 12/22/1994, EMSE LLC, Elevado Investment Company, LLC and the Marc Ezralow Irrevocable Trust u/t/d 6/1/2004, (ii) MarcEzralow, the beneficial owner of 5% or more of our common stock, through the Marc Ezralow 1997 Trust u/t/d 11/26/1997, EMSE LLC, Elevado InvestmentCompany, LLC and the SPA Trust u/t/d 9/13/2004, (iii) J. Steven Emerson, through J. Steven Emerson Roth IRA Pershing LLC as Custodian and J. StevenEmerson IRA Rollover II Pershing LLC as Custodian, (iv) G. Tyler Runnels, through TRW and the Runnels Family Trust DTD 1-11-2000, and (v) MarkChristensen, through Trace Capital Inc.. The approximate dollar value of the amount of (i) the interest of Bryan Ezralow, through the Bryan Ezralow 1994Trust u/t/d 12/22/1994, EMSE LLC, Elevado Investment Company, LLC and the Marc Ezralow Irrevocable Trust u/t/d 6/1/2004, in the March 2017 PrivatePlacement was $1.4 million; (ii) the interest of Marc Ezralow, through the Marc Ezralow 1997 Trust u/t/d 11/26/1997, EMSE LLC, Elevado InvestmentCompany, LLC and the SPA Trust u/t/d 9/13/2004, in the March 2017 Private Placement was $1.2 million, (iii) the interest of J. Steven Emerson, through J.Steven Emerson Roth IRA Pershing LLC as Custodian and J. Steven Emerson IRA Rollover II Pershing LLC as Custodian, in the March 2017 PrivatePlacement was $2.5 million, (iv) the interest of G. Tyler Runnels, through TRW and the Runnels Family Trust DTD 1-11-2000, in the March 2017 PrivatePlacement was $0.8 million and (v) the interest of Mark Christensen, through Trace Capital Inc., in the March 2017 Private Placement was $1.0 million. Additionally, on February 28, 2017, we entered into a Subscription Agreement in connection with the March 2017 Private Placement, for whichTRW acted as placement agent and received a fee of $459,060. For more information on the March 2017 Private Placement see Management’s Discussion and Analysis-Liquidity and Capital Resources-March2017 Private Placement. G. Tyler Runnels and T.R. Winston On November 1, 2016, we entered into a sublease agreement with TRW to sublease office space in New York, for which we pay $10,000 per monthon a month-to-month basis. The Company terminated this office lease on October 31, 2017. Mark Christensen, Trace Capital Inc. and KES 7 Capital Inc. Since January 1, 2016, Mr. Christensen has been involved in the following related party transactions with the Company, through Trace Capital Inc.(“Trace”), an entity owned by Mr. Christensen’s wife, and KES 7 Capital Inc. (“KES 7”) for which he serves as Chief Executive Officer and 100% owner.Trace has participated in the following transactions with the Company: (i) the offering of Series B Preferred Stock in June 2016 pursuant to which Tracepurchased 500 shares of Series B Preferred Stock and warrants to purchase up to 227,274 shares of common stock with an exercise price of $2.50 (the “SeriesB Warrants”) for aggregate consideration of $500,000; (ii) the Company’s first lien credit facility entered into in September 2016, which had initial aggregateprincipal commitments of approximately $31 million and a maximum facility size of $50 million, and the upsize of that facility in February 2017, of whichTrace held indebtedness in an aggregate amount of $2.6 million, and which resulted in the repricing of the Series B Warrants to $0.01 that were exercised infull on April 25, 2017; (iii) the Company’s March 2017 private placement of units comprised of common stock and warrants raising net proceeds ofapproximately $20 million pursuant to which Trace purchased units for an aggregate purchase price of approximately $1 million; (iv) the conversion ofshares of Series B Preferred Stock that Trace held plus accrued dividends, which resulted in the issuance of 467,348 shares of the common stock to Trace(valued at approximately $1,495,514 based on the $3.20 closing trading price of the common stock on December 9, 2016); and (v) the amendment to theCompany’s first lien credit facility on April 24, 2017 and related matters, in which the balance of the first lien credit facility in an aggregate amount of $38.1million plus accrued and unpaid interest thereon was paid down (including the $2.6 million of indebtedness held by Trace) and in which $1.45 million wasreinvested by Trace in the form of bridge loans with an aggregate amount of $15 million outstanding. Each of the initial lenders that participated in the firstlien credit facility also waived their right to any prepayment premium, including Trace. Additionally, KES 7 has acted as an advisor and placement agent inconnection with certain of the Company’s financing transactions resulting in aggregate fees paid by the Company of approximately $2.4 million in cash andthe issuance of warrants to purchase 820,000 shares of common stock with an exercise price of $1.30 to KES 7. MMZ Consulting From August 15, 2016 through April 15, 2017, we engaged MMZ Consulting LLC (“MMZ”) as a third-party consultant to support our full cycledrilling & completions engineering needs. On January 29, 2017, Brennan Short, the president and owner of MMZ was hired to be our Chief Operating Officer.Since the beginning of this fiscal year, we have paid approximately $205,000 to MMZ in exchange for services rendered. Mr. Short is the sole member ofMMZ. Series C Preferred Stock Issuance On January 30, 2018, we entered into a Securities Purchase Agreement with certain private funds affiliated with Värde Partners, Inc. (the “Series CPurchasers”), pursuant to which, on January 31, 2018, the Series C Purchasers purchased 100,000 shares of our newly created series of preferred stock of theCompany, 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 theCompany’s Second Lien Credit Agreement. Värde Partners, Inc. and its applicable affiliated funds beneficially own over 5% of our common stock as a resultof their respective conversion rights under the Second Lien Credit Agreement and the Series C Preferred Stock. 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 $10.5million. VPD is affiliated with Värde Partners, Inc., which is the lead lender under the Second Lien Credit Agreement, and Värde Partners, Inc. and certainaffiliated funds hold all of the issued and outstanding shares of Series C Preferred Stock. As such, Värde Partners, Inc. and its applicable affiliated fundsbeneficially own over 5% of our common stock as a result of their respective conversion rights under the Second Lien Credit Agreement and the Series CPreferred Stock. Compensation of Directors See “Executive Compensation-Compensation of Nonemployee Directors” above. Conflict of Interest Policy Our Board has recognized that transactions between us and certain related persons present a heightened risk of conflicts of interest. We have acorporate conflict of interest policy that prohibits conflicts of interests unless approved by our Board. Our has established a course of conduct whereby itconsiders in each case, whether the proposed transaction is on terms as favorable or more favorable to us than would be available from a non-related party.Our Board also looks at whether the transaction is fair and reasonable to us, taking into account the totality of the relationships between the parties involved,including other transactions that may be particularly favorable or advantageous to us. Each of the related party transactions described above was presented toour Board for consideration and each of these transactions was unanimously approved by our Board after reviewing the criteria set forth in the preceding twosentences. 85  Director Independence See “Directors, Executive Officers and Corporate Governance-Affirmative Determinations Regarding Director Independence and Other Matters”above. Item 14. Principal Accounting Fees and Services The following table sets forth fees billed by our principal accounting firms, BDO USA, LLP and Marcum LLP, for the years ended December 31,2017 and 2016, respectively: Year Ended December 31, Fee Category 2017 2016 (In thousands) Audit Fees $1,616 $ 358 Audit-Related Fees 11 341 All Other Fees - - Total Fees $1,627 $699 Audit Fees consist of the aggregate fees for professional services rendered for the audit of our annual consolidated financial statements, our internalcontrols over financial reporting, and the reviews of the consolidated financial statements included in our Quarterly Reports on Forms 10-Q and for any otherservices 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 andrelated services that were reasonably related to the performance of the audit or review of our financial statements and were not otherwise included in AuditFees. 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 Our independent registered public accounting firm may not be engaged to provide non-audit services that are prohibited by law or regulation to beprovided by it, nor may our independent registered public accounting firm be engaged to provide any other non-audit service unless it is determined that theengagement of the principal accountant provides a business benefit resulting from its inherent knowledge of our Company while not impairing itsindependence. Our audit committee must pre-approve permissible non-audit services. During the year ended December 31, 2017, we had no non-auditservices provided by our independent registered public accounting firm. 86  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 theliquid 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. Ouractual 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, anextension 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/orstratigraphic 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 reserve in which we own a working interest, reported at the 100% or 8/8ths level. For example, thenumber 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 aparticular tract of land. Leasehold. Mineral rights leased in a certain area to form a project area. 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 gasliquids. 87  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 thefractional 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 astandard 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 andnatural 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 operatorsubject 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 borneby 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 intoanother 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 thecost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is bymeans 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 tobe economically producible - from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and governmentregulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardlessof whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operatormust 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 onundrilled 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 usingreasonably 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/orcompleting 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, byapplication of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, thelegal 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 andfinancing 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 orother geologic structures or water barriers and is individual and separate from other reservoirs. 88  Secondary Recovery. A recovery process that uses mechanisms other than the natural pressure or fluid drive of the reservoir, such as gas injection or waterflooding, 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 wereused 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 quantitiesof 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 displaceresidual 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 toreceive a share of the production revenue, subject to all royalties, overriding royalties and other burdens, all development costs, and all risks in connectiontherewith. 89  PART IV Item 15. Exhibits, Financial Statement Schedules a)Index to Financial Statements Reports of Independent Registered Public Accounting Firms91Consolidated Balance Sheets as of December 31, 2017 and 201694Consolidated Statements of Operations for the years ended December 31, 2017 and 201695Consolidated Statements of Stockholders’ Equity (Deficit) for the years ended December 31, 2017 and 201696Consolidated Statements of Cash Flows for the years ended December 31, 2017 and 201697Notes to Consolidated Financial Statements98Supplementary Information on Oil and Natural Gas Exploration, Development and Production Activities (unaudited)132 b)Exhibits The information required by this Item is set forth on the exhibit index that follows the signature page to this Annual Report and is incorporatedherein by reference. c)Financial Statement Schedules Not applicable. Item 16. Form 10-K Summary None. 90  Report of Independent Registered Public Accounting Firm Board of Directors and StockholdersLilis Energy, Inc. and SubsidiariesSan Antonio, Texas Opinion on Internal Control over Financial Reporting We have audited Lilis Energy, Inc.’s (the “Company’s”) internal control over financial reporting as of December 31, 2017, based on criteriaestablished in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the“COSO criteria”). In our opinion, the Company did not maintain, in all material respects, effective internal control over financial reporting as of December 31,2017, based on the COSO criteria. We do not express an opinion or any other form of assurance on management’s statements referring to any corrective plans and actions taken by theCompany after the date of management’s assessment. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), theconsolidated balance sheet of the Company and subsidiaries as of December 31, 2017, the related consolidated statements of operations, changes instockholders’ equity (deficit), and cash flows for the year then ended, and the related notes and our report dated March 9, 2018 expressed an unqualifiedopinion thereon. Basis for Opinion The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of theeffectiveness of internal control over financial reporting, included in the accompanying Item 9A, Management’s Annual Report on Internal Control overFinancial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are apublic accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with U.S. federal securitieslaws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audit of internal control over financial reporting in accordance with the standards of the PCAOB. Those standards require that weplan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all materialrespects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, andtesting and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such otherprocedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonablepossibility that a material misstatement of the Company’s annual or interim consolidated financial statements will not be prevented or detected on a timelybasis. A material weakness regarding management’s failure to design and maintain controls over the ceiling test has been identified and described inmanagement’s assessment. This material weakness was considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2017consolidated financial statements, and this report does not affect our report dated March 9, 2018 on those consolidated financial statements. Definition and Limitations of Internal Control over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financialreporting and the preparation of consolidated financial statements for external purposes in accordance with generally accepted accounting principles. Acompany’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonabledetail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions arerecorded as necessary to permit preparation of consolidated financial statements in accordance with generally accepted accounting principles, and thatreceipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3)provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that couldhave a material effect on the consolidated financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of anyevaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degreeof compliance with the policies or procedures may deteriorate. /s/ BDO USA, LLP Dallas, Texas March 9, 2018 91  Report of Independent Registered Public Accounting Firm Board of Directors and StockholdersLilis Energy, Inc. and SubsidiariesSan Antonio, Texas Opinion on the Consolidated Financial Statements We have audited the accompanying consolidated balance sheet of Lilis Energy, Inc. (the “Company”) and subsidiaries as of December 31, 2017, therelated consolidated statements of operations, changes in stockholders’ equity (deficit), and cash flows for the year then ended, and the related notes(collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all materialrespects, the financial position of the Company and subsidiaries at December 31, 2017, and the results of their operations and their cash flows for the yearthen ended, in conformity with accounting principles generally accepted in the United States of America. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), theCompany's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control – Integrated Framework(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) and our report dated March 9, 2018 expressed anadverse opinion thereon. Basis for Opinion These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on theCompany’s consolidated financial statements based on our audit. We are a public accounting firm registered with the PCAOB and are required to beindependent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities andExchange Commission and the PCAOB. We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtainreasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audit included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to erroror fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts anddisclosures in the consolidated financial statements. Our audit also included evaluating the accounting principles used and significant estimates made bymanagement, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis forour opinion. /s/ BDO USA, LLP We have served as the Company's auditor since 2017.Dallas, Texas March 9, 2018 92  Report of Independent Registered Public Accounting Firm To the Audit Committee of the Board of Directors and Shareholders of Lilis Energy, Inc. and Subsidiaries We have audited the accompanying consolidated balance sheet of Lilis Energy, Inc. and Subsidiaries (the “Company”) as of December 31, 2016,and the related consolidated statements of operations, changes in stockholders’ equity (deficit) and cash flows for the year then ended. These financialstatements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standardsrequire that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. TheCompany is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included considerationof internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose ofexpressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An auditalso includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principlesused and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides areasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Lilis Energy,Inc. and Subsidiaries, as of December 31, 2016, and the consolidated results of its operations and its cash flows for the year then ended in conformity withaccounting principles generally accepted in the United States of America. /s/ Marcum LLP New York, NY March 3, 2017 93  Lilis Energy, Inc. and SubsidiariesConsolidated Balance Sheets(In thousands, except share and per share data) December 31, 2017 2016 ASSETS Current assets: Cash and cash equivalents $17,462 $11,738 Accounts receivables, net of allowance of $39 and $106, respectively 7,426 2,247 Prepaid expenses and other current assets 584 767 Total current assets 25,472 14,752 Oil and natural gas properties, full cost method of accounting Unproved 101,771 24,461 Proved 141,717 69,809 Less: accumulated depreciation, depletion, amortization and impairment (73,183) (55,771)Total oil and natural gas properties, net 170,305 38,499 Other property and equipment, net 76 52 Other assets 91 216 Total other assets 167 268 Total assets $195,944 $53,519 LIABILITIES, REDEEMABLE PREFERRED STOCK AND STOCKHOLDERS' EQUITY (DEFICIT) Current liabilities: Accounts payable $10,488 $5,166 Accrued liabilities 13,857 2,706 Derivative instruments 853 - Dividends payable - 808 Asset retirement obligations 226 338 Current portion of long-term debt 11 17 Total current liabilities 25,435 9,035 Asset retirement obligations 726 919 Long-term debt 127,794 30,226 Derivative instruments 72,937 1,400 Total liabilities 226,892 41,580 Commitments and contingencies (Note 8) Conditionally redeemable 6% preferred stock, $0.0001 par value, 7,000 shares authorized, 2,000 shares issued andoutstanding with a liquidation preference of $2,240 at December 31, 2016 - 1,874 Stockholders’ equity (deficit): Series B Preferred stock, $0.0001 par value; stated value of $1,000; 20,000 shares authorized; 16,828 sharesissued and outstanding at December 31, 2016, with a liquidation preference of $20,627 at December 31, 2016 - 13,432 Common stock, $0.0001 par value per share; 150,000,000 shares authorized, 53,368,331 and 20,918,901 sharesissued and outstanding as of December 31, 2017 and 2016, respectively. 5 2 Additional paid-in capital 272,335 219,837 Accumulated deficit (303,288) (223,206)Total stockholders’ equity (deficit) (30,948) 10,065 Total liabilities, redeemable preferred stock and stockholders’ equity $195,944 $53,519 The accompanying notes are an integral part of these consolidated financial statements 94  Lilis Energy, Inc. and SubsidiariesConsolidated Statements of Operations(In thousands, except share and per share data) Year Ended December 31, 2017 2016 Revenues: Oil sales $17,826 $2,418 Natural gas sales 2,125 844 Natural gas liquid sales 1,661 173 21,612 3,435 Operating expenses: Production costs 7,023 1,590 Production taxes 1,187 (167)General and administrative 49,851 14,227 Depreciation, depletion, accretion and amortization 7,025 1,698 Impairment of evaluated oil and natural gas properties 10,505 4,718 Total operating expenses 75,591 22,066 Loss from operations (53,979) (18,631) Other income (expense): Other income 18 90 Inducement expense - (8,307)Gain on extinguishment of debt and modification of convertible debentures - 852 Loss from commodity derivatives, net (1,063) - Loss from fair value changes of debt conversion and warrant derivatives (6,260) (1,222)Loss from fair value changes of conditionally redeemable 6% preferred stock (41) (701)Interest expense (18,757) (4,924)Total other income (expense) (26,103) (14,212) Net loss before income taxes (80,082) (32,843) Income tax expense - - Net loss (80,082) (32,843)Dividends on redeemable preferred stock (122) (407)Loss on extinguishment of Series A convertible preferred stock - (540)Dividend and deemed dividends on Series B convertible preferred stock (4,635) (8,506)Net loss attributable to common stockholders $(84,839) $(42,296) Net loss per common share-basic and diluted $(2.00) $(3.73)Weighted average common shares outstanding: Basic and diluted 42,428,148 11,328,252 The accompanying notes are an integral part of these consolidated financial statements. 95  Lilis Energy, Inc. and SubsidiariesConsolidated Statements of Changes in Stockholders’ Equity (Deficit)(In thousands, except share and per share data) Series A Preferred Series B Preferred Additional Shares Shares Common Shares Paid In Accumulated Shares Amount Shares Amount Shares Amount Capital Deficit Total Balance, December 31, 2015 7,500 $6,794 - $- 2,786,275 $- $159,773 $(180,910) $(14,343)Stock based compensation - - - - 711,667 - 7,078 - 7,078 Exercise of warrants - - - - 420,707 - 187 - 187 Fair value of warrants issued forfinancing costs - - - - - - 713 - 713 Issuance and repricing of warrants toinduce conversion - - - - - - 8,307 - 8,307 Gain on modification of convertibledebentures - - - - - - (602) - (602)Fair value of warrants issued for debtdiscount - - - - - - 1,479 - 1,479 Common stock issued forconversion of convertible notes andaccrued interest - - - - 6,778,115 1 14,871 - 14,872 Common stock and warrants issuedin connection with the Brushymerger - - - - 5,785,119 - 7,111 - 7,111 Series B Preferred stock issued forcash, net of fees - - 20,000 18,195 - - - - 18,195 Warrants issued for Series BPreferred Stock offering fees - - - (1,591) - - 1,591 - - Conversion of Series A PreferredStock and dividends to commonstock (7,500) (6,794) - - 1,500,000 1 7,681 - 888 Loss on extinguishment of Series APreferred Stock - - - - - - 540 (540) - Conversion of Series B PreferredStock and dividends - - (3,172) (3,172) 2,937,018 - 3,229 - 57 Dividends and deemed dividendsfor Preferred Stock - - - - - - 7,879 (8,913) (1,034)Net loss - - - - - - - (32,843) (32,843)Balance, December 31, 2016 - - 16,828 13,432 20,918,901 2 219,837 (223,206) 10,065 Stock based compensation - - - - - - 21,538 - 21, 538 Common stock for restricted stockand stock options - - - - 5,859,383 - 524 - 524 Common stock withheld for taxeson stock-based compensation - - - - (786,081) - (3,709) - (3,709)Exercise of warrants - - - - 5,580,281 1 592 - 593 Conversion of Series B PreferredStock and dividends - - (16,828) (13,432) 16,601,026 2 14,863 - 1,433 Sale of common stock in privateplacement, net - - - - 5,194,821 - 18,649 - 18,649 Warrants repriced for term loan - - - - - - 1,031 - 1,031 Dividends and deemed dividends onpreferred stock - - - - - - (990) - (990)Net loss - - - - - - - (80,082) (80,082)Balance, December 31, 2017 - $- - $- 53,368,331 $5 $272,335 $(303,288) $(30,948) The accompanying notes are an integral part of these consolidated financial statements. 96  Lilis Energy, Inc. and SubsidiariesConsolidated Statements of Cash Flows(In thousands) Year Ended December 31, 2017 2016 Cash flows from operating activities: Net loss $(80,082) $(32,843)Adjustments to reconcile net loss to net cash used in operating activities: Equity instruments issued for services and compensation 21,538 7,078 Inducement expense - 8,307 Bad debt expense 22 494 Amortization of debt issuance cost and debt discount 10,371 3,185 Paid-in-kind interest 6,559 - Loss on commodity derivatives 1,063 - Cash settlement paid for commodity derivatives (96) - Loss in fair value of debt conversion and warrant derivatives 6,260 1,222 Loss in fair value of conditionally redeemable 6% preferred stock 41 701 Depreciation, depletion, amortization and accretion of asset retirement obligation 7,025 1,698 Impairment of evaluated oil and natural gas properties 10,505 4,718 Gain on extinguishment of debt and modification of convertible debentures - (852)Changes in operating assets and liabilities: Accounts receivable (5,204) (1,264)Other assets 309 1,554 Accounts payable, accrued expenses and other liabilities 14,446 (307)Net cash used in operating activities (7,243) (6,309) Cash flows from investing activities: Cash consideration for Brushy merger, net of cash acquired - (2,302)Net proceeds from sale of DJ Basin and non-operated properties 1,282 - Capital expenditures (148,784) (16,828)Net cash used in investing activities (147,502) (19,130) Cash flows from financing activities: Net proceeds from issuance of Series B Preferred Stock - 18,195 Proceeds from issuance of convertible notes - 2,863 Proceeds from issuance of First Lien Term Loan, net of financing costs - 29,701 Proceeds from exercise of accordion feature of the First Lien Term Loan, net of financing costs 6,706 - Proceeds from Bridge Loan and Second Lien Term Loan, net of financing costs 178,722 - Repayment of the First Lien Term Loan (38,100) - Repayment of conditionally redeemable 6% preferred stock including dividends (2,277) - Proceeds from exercise of stock options and warrants 745 187 Payment for tax withholding on stock-based compensation (3,709) - Proceeds from private placement, net of financing costs 18,399 - Repayment of notes payable (17) (13,879)Net cash provided by financing activities 160,469 37,067 Increase in cash and cash equivalents 5,724 11,628 Cash and cash equivalents at beginning of period 11,738 110 Cash and cash equivalents at end of period $17,462 $11,738 Supplemental disclosure: Cash paid for interest $2,292 $762 The accompanying notes are an integral part of these consolidated financial statements. 97  Lilis Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements NOTE 1 – Organization and Business Lilis Energy, Inc. (“Lilis”, “Lilis Energy” or the “Company”) was incorporated in the State of Nevada in 2007. The Company is an independent oiland natural gas company focused on the acquisition, development, and production of conventional and unconventional oil and natural gas properties in thecore of the Delaware Basin in Winkler, Loving, and Reeves Counties, Texas and Lea County, New Mexico. The Company has only one reportable operatingsegment, which is oil and natural gas exploration and production in the Delaware Basin. On June 23, 2016, the Company completed a merger transaction with Brushy Resources, Inc. (“Brushy Resources”). The merger resulted in theacquisition of our properties in the Delaware Basin and the majority of our current operating activity. In connection with the merger with Brushy Resources,the Company effected a 1-for-10 reverse stock split. As a result of the reverse split, every ten shares of issued and outstanding common stock wereautomatically converted into one newly issued and outstanding share of common stock, without any change in the par value per share; however, the numberof authorized shares of common stock remained unchanged. Shortly after the merger with Brushy Resources, the Company began to develop and implement a development program focusing on the drilling ofnew horizontal wells across multiple potentially productive formations in the Delaware Basin. The Company drilled its first horizontal well in late 2016 andcompleted it in January 2017. The Company intends to grow its business through generating cash flow from new production of oil, natural gas and naturalgas liquid (“NGL”), as well as through de-risking the development profile of our portfolio of properties in order to add overall value. On March 31, 2017, the Company completed the divestiture of all our oil and natural gas properties located in the DJ Basin completing itstransformation to a pure play Delaware Basin oil and natural gas company. NOTE 2 – Basis of Presentation and Summary of Significant Accounting Policies Principles of Consolidation The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries which includes Brushy Resources,ImPetro Operating, LLC (“ImPetro Operating”), ImPetro Resources, LLC (“ImPetro”), Lilis Operating Company, LLC (“Lilis Operating”), and HurricaneResources LLC (“Hurricane”). All significant intercompany accounts and transactions have been eliminated in consolidation. Use of Estimates The accompanying consolidated financial statements are prepared in conformity with generally accepted accounting principles in the United States(“U.S. GAAP”) which requires the Company to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities;disclosure of contingent assets and liabilities at the date of the financial statements, the reported amounts of revenues and expenses during the reportingperiod; and the quantities and values of proved oil, natural gas and natural gas liquid (“NGL”) reserves used in calculating depletion and assessingimpairment of its oil and natural gas properties. The most significant estimates pertain to the evaluation of unproved properties for impairment, proved oiland natural gas reserves and related cash flow estimates used in the depletion and impairment of oil and natural gas properties, the timing and amount oftransfers of our unevaluated properties into our amortizable full cost pool, the fair value of embedded derivatives and commodity derivative contracts,accrued oil and natural gas revenues and expenses valuation of options and warrants, inducement transactions and common stock, and the allocation ofgeneral administrative expenses. Actual results could differ significantly from these estimates. 98  Reclassifications Certain reclassifications have been made to the prior year financial statements to conform to the 2017 presentation. These reclassifications have noeffect on the Company’s previously reported results of operations. For the year ended December 31, 2016, the income from operator’s overhead recovery of$0.3 million has been reclassified from production costs to general and administrative expenses. Cash and Cash Equivalents Cash and cash equivalents include highly liquid instruments with an original maturity of three months or less are stated at cost, which approximatesfair value. Accounts Receivable The Company has accounts receivable from joint interest owners of properties operated by the Company. The Company typically has the right towithhold future revenue disbursements to recover any non-payment of related joint interest billings. Management routinely assesses accounts receivableamounts to determine their collectability and accrues an allowance for uncollectible receivables when, based on the judgment of management, it is probablethat a receivable will not be collected. The Company records actual and estimated oil and natural gas revenue receivable from third parties at its net revenueinterest. In addition, the Company has receivables derived from sales of certain oil and natural gas production which are collateral under the Company’scredit agreements. Fair Value of Financial Instruments As of December 31, 2017 and 2016, the carrying value of cash and cash equivalents, accounts receivable, accounts payable, accrued expenses,interest payable and advances from joint interest partners approximates fair value due to the short-term nature of such items. The carrying value of theCompany’s secured debt is carried at cost which approximates the fair value of the debt as the related interest rates approximates interest rates currentlyavailable 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 andgeophysical expenses, carrying charges on non-producing properties, costs of drilling, developing and completing productive wells and/or plugging andabandoning non-productive wells, and any other costs directly related to acquisition and exploration activities. Proceeds from property sales are generallyapplied as a credit against capitalized exploration and development costs, with no gain or loss recognized, unless such a sale would significantly alter therelationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% ormore of proved reserves. The Company accounts for its unproven long-lived assets in accordance with Accounting Standards Codification (“ASC”) Topic 360-10-05,Accounting for the Impairment or Disposal of Long-Lived Assets. ASC Topic 360-10-05 requires that long-lived assets be reviewed for impairment wheneverevents or changes in circumstances indicate that the historical carrying value of an asset may no longer be appropriate. Depletion of exploration and development costs and depreciation of wells and tangible production assets is computed using the units-of-productionmethod based upon estimated proved oil and natural gas reserves. Costs included in the depletion base to be amortized include (a) all proved capitalizedcosts including capitalized asset retirement costs net of estimated salvage values, less accumulated depletion, (b) estimated future development cost to beincurred in developing proved reserves; and (c) estimated decommissioning and abandonment/restoration costs, net of estimated salvage values, that are nototherwise included in capitalized costs. Costs associated with undeveloped acreage are excluded from the depletion base until it is determined whether proved reserves can be assigned tothe properties. When proved reserves are assigned to such properties or one or more specific properties are deemed to be impaired, the cost of such propertiesis added to the full cost pool which is subject to depletions. Under the full cost method of accounting, capitalized oil and natural gas property costs less accumulated depletion and net of deferred income taxesmay 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 reservesand the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unprovedproperties that are not subject to amortization. Should capitalized costs exceed this ceiling, an impairment expense is recognized. For the year endedDecember 31, 2017, higher capital expenditures with lower than expected development of proved reserves contributed to the excess of net book value of ouroil and natural gas properties over the ceiling resulting in the recognition of an impairment charge of $10.5 million. During 2016, commodity pricescontinued to trade in a low range. With low commodity prices sustained for the majority of 2016 in the DJ Basin, some of the Company’s properties becameuneconomic triggering an impairment charge of $4.7 million for the year ended December 31, 2016. 99  The present value of estimated future net cash flows was computed by applying: a flat oil price to forecast revenues from estimated future productionof proved oil and natural gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves(assuming the continuation of existing economic conditions), less any applicable future taxes. Wells in Progress Wells in progress connotes wells that are currently in the process of being drilled or completed or otherwise under evaluation as to their potential toproduce oil and natural gas reserves in commercial quantities. Such wells continue to be classified as wells in progress and withheld from the depletioncalculation and the ceiling test until such time as either proved reserves can be assigned, or the wells are otherwise abandoned. Upon either the assignment ofproved 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 testcalculations 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 notcommenced production, interest is capitalized as part of the historical cost of developing and constructing assets. Capitalized interest is determined bymultiplying the Company’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interestcapitalization is completed and placed in service, the associated capitalized interest is expensed through depreciation or impairment. As of December 31,2017, there were no significant exploratory projects on unproved properties and none of the development projects exceeded the interest capitalizationqualifying asset limit. As a result, no interest was capitalized as of December 31, 2017 and 2016. Other Property and Equipment Property and equipment include vehicles, office equipment and furniture which are stated at cost. Depreciation is calculated using the straight-linemethod over the estimated useful lives of the assets. The estimated useful lives of property and equipment range from three to seven years. The Companyrecorded approximately $0.04 million of depreciation for each of the years ended December 31, 2017 and 2016, respectively. Accrued Liabilities As of December 31, 2017 and 2016, the Company’s accrued liabilities consisted of the following: December 31, 2017 2016 ($ in thousands) Accrued bonus $3,000 $- Accrued drilling costs 3,615 1,331 Revenue payable 6,460 1,313 Other accrued liabilities 782 62 Total accrued liabilities $13,857 $2,706 Asset Retirement Obligations The Company incurs retirement obligations for certain assets at the time they are placed in service. The fair values of these obligations are recorded asliabilities on a discounted basis. The costs associated with these liabilities are capitalized as part of the related assets and depreciated. Over time, theliabilities are accreted for the change in their present value. For purposes of depletion, the Company includes estimated dismantlement and abandonmentcost, net of salvage values, associated with future development activities that have not yet been capitalized as asset retirement obligations. Asset retirementobligations incurred are classified as Level 3 (unobservable inputs) fair value measurements. 100  Revenue Recognition The Company recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i)persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller's price to the buyer is fixed ordeterminable, and (iv) collectability is reasonably assured. The Company uses the entitlements method of accounting for oil, natural gas and NGL revenues. Should sales proceeds be in excess of theCompany's entitlement, these amounts will be included in accrued liabilities and the Company's share of sales taken by others will be included in other assetsin the accompanying consolidated balance sheets. The Company had no material oil, natural gas or NGL entitlement assets or liabilities as of December 31,2017 and 2016. All revenue proceeds relating to third-party royalty owners not remitted by the end of a reporting period are recorded as revenue payable, acomponent of accrued liabilities. As of December 31, 2017, and 2016, the Company had approximately $6.5 million and $1.3 million, respectively, of suchrevenue proceeds recorded in accrued liabilities. Stock Based Compensation The Company applies a fair value method of accounting for stock-based compensation, which requires recognition in the financial statements of thecost of services received in exchange for equity awards. For equity awards, compensation expense is based on the fair value on the grant date or modificationdate and is recognized in the Company’s financial statements over the vesting period. The Company utilizes the Black-Scholes Merton option-pricing modelto measure the fair value of stock options based on several criteria, including but not limited to, the valuation model used and associated input factors, suchas expected term of the award, stock price volatility, risk free interest rate, dividend rate and award cancellation rate. These inputs are subjective and aredetermined using management’s judgment. If differences arise between the assumptions used in determining stock-based compensation expense and theactual factors, which become known over time, the Company may change the input factors used in determining future stock-based compensation expense.The Company recognizes forfeitures as and when the stock awards are forfeited. The Company accounts for warrant grants to nonemployees whereby the fair values of such warrants are determined using the option pricing modelat the earlier of the date at which the nonemployee’s performance is complete or a performance commitment is reached. Income Taxes The Company uses the asset and liability method in accounting for income taxes. Deferred tax assets and liabilities are recognized for temporarydifferences between financial statement carrying amounts and the tax bases of assets and liabilities, and are measured using the tax rates expected to be ineffect when the differences reverse. Deferred tax assets are also recognized for operating loss and tax credit carry forwards. The effect on deferred tax assetsand 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 usedto 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, 2017and 2016, the Company has determined that no liability is required to be recognized. The Company’s policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense. No interest or penaltieswere required to be accrued at December 31, 2017 and 2016. Further, the Company does not expect that the total amount of unrecognized tax benefits willsignificantly increase or decrease during the next 12 months. Loss Per Share Basic loss per share was calculated by dividing net income or loss applicable to common shares by the weighted average number of common sharesoutstanding during the periods presented. The calculation of diluted loss per share should include the potential dilutive impact of shares issuable upon theconversion of debt or preferred stock, warrants and options during the period, unless their effect is anti-dilutive. At December 31, 2017 and 2016, commonstock equivalents including shares underlying conversion of the Second Lien Term Loan, restricted stock units, restricted stock, options, warrants, preferredstock and debentures have been excluded from the diluted share calculations as they were anti-dilutive as a result of net losses incurred. The Companyincluded 3,522,735 warrants, with an exercise price of $.01, in its earnings per share calculation for the year ended December 31, 2016. There were nowarrants exercisable at a price of $0.01 per share for the year ended December 31, 2017. 101  The Company excluded the following shares from the diluted loss per share calculations because they were anti-dilutive at December 31, 2017 and2016: December 31, 2017 2016 Stock Options 7,305,000 5,956,833 Restricted Stock Units 9,999 149,584 Restricted Stock 2,475,266 1,068,305 Series B Preferred Stock - 15,454,545 Stock Purchase Warrants (1) 11,882,800 12,392,776 Conversion of Term Loan 24,202,016 - 45,875,081 35,022,043 (1)Excludes warrants exercisable for 3,522,735 shares of common stock at an exercise price of $0.01 for the year ended December 31, 2016 since thesewarrants are not anti-dilutive. There were no warrants exercisable at $0.01 per share for the year ended December 31, 2017. Concentration of Credit Risk The Company operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payment forcosts associated with the property and seeks reimbursement from the other joint interest owners in the property for their portion of those costs. Whenwarranted, prepayments are required from joint interest owners for drilling and completion projects. Joint interest owners consist primarily of independent oiland natural gas producers whose ability to reimburse the Company could be negatively impacted by adverse market conditions. The purchasers of the Company’s oil, natural gas and NGL production consist primarily of independent marketers, major oil and gas companies,refiners and gas pipeline companies. Credit evaluations are performed on the Company’s purchasers of its production and their financial condition ismonitored on an ongoing basis. Based on those evaluations and monitoring, the Company may obtain letters of credit or parental guarantees from somepurchasers. 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 suchtransactions. The Company monitors the credit ratings of its derivative counterparties on an ongoing basis. If a counterparty were to default on its obligationsto the Company under the derivative contracts or seek bankruptcy protection, it could have a material adverse effect on its ability to fund planned activitiesand could result in a larger percentage of our future production being subject to commodity price volatility. In addition, in poor economic environments andtight financial markets, the risk of a counterparty default is heightened and fewer counterparties may participate in derivative transactions, which could resultin greater concentration of exposure to any one counterparty or a larger percentage of the Company’s future production being subject to commodity pricechanges. Major Customers During the years ended December 31, 2017 and 2016, the Company’s major customers, as a percentage of total revenue, consisted of the following: Year Ended December 31, 2017 2016 Texican Crude & Hydrocarbon, LLC 85% 38%ETC Field Services LLC 14% 16%Noble Energy -% 41%All others 1% 5% 100% 100% 102  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 valuerecognized currently in earnings. Although derivative instruments are used by the Company to manage the price risk attributable to its expected oil andnatural gas production, those derivative instruments have not been designated as accounting hedges under the accounting guidance. All of our derivativesare accounted for as mark-to-market activities. Under ASC Topic 815, “Derivatives and Hedging,” these instruments are recorded on the consolidated balancesheets at fair value as either short term or long-term assets or liabilities based on their anticipated settlement date. The Company nets derivative assets andliabilities by commodity for counterparties where a legal right to such offset exists. Changes in the derivatives' fair values are recognized in current earningssince 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 fromthe Loan, as defined in Note 4, and accounted for separately from the debt. Additionally, warrants issued to SOSV Investment LLC (“SOS”) to purchase up to200,000 shares of the Company’s stock contain a price protection feature that will automatically reduce the exercise price should the Company enter intoanother agreement pursuant to which warrants are issued at a lower exercise price. The price protection feature has been recognized as an embeddedderivative and accounted for separately. Recently Issued Accounting Pronouncements The Company considers the applicability and impact of all Accounting Standards Updates (“ASUs”). The ASUs not listed below were assessed anddetermined to be either not applicable or are expected to have minimal impact on its consolidated financial position and/or results of operations. On August 28, 2017, the Financial Accounting Standards Board (“FASB”) issued ASU 2017-12, Derivatives and Hedging (Topic 815): TargetedImprovements to Accounting for Hedging Activities, which amends the hedge accounting recognition and presentation requirements in Accounting StandardsCodification (“ASC”) Topic 815. The new standard provides partial relief on the timing of certain aspects of hedge documentation and eliminates therequirement to recognize hedge ineffectiveness separately in income. The amendments in this ASU are effective for fiscal years beginning after December 15,2018 and for interim periods therein. Early adoption as of the date of issuance is permitted. The new standard does not impact accounting for derivatives thatare not designated as accounting hedges. The Company does not currently account for any of its derivative position as accounting hedges. The Companymay consider designating certain derivative contracts as accounting hedges in the future, but currently has no plans to do so. On July 13, 2017, the FASB issued a two-part ASU 2017-11, (Part I) Accounting for Certain Financial Instruments with Down Round Features,(Part II) Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain RedeemableNoncontrolling Interests with a Scope Exception. Part I of the ASU simplifies the accounting for certain financial instruments with down round features byrequiring companies to disregard the down round feature when assessing whether the instrument is indexed to its own stock, for purposes of determiningliability or equity classification. Companies that provide earnings per share (EPS) data will adjust their basic EPS calculation for the effect of the featurewhen triggered (that is, when the exercise price of the related equity-linked financial instrument is adjusted downward because of the down round feature)and will also recognize the effect of the trigger within equity. Part II of the ASU is not applicable to the Company since it addresses concerns relating to anindefinite deferral available to private companies with mandatorily redeemable financial instruments and certain noncontrolling interests. The provisions ofthis new ASU related to down rounds are effective for public business entities for fiscal years, and interim periods within those fiscal years, beginning afterDecember 15, 2018. Early adoption is permitted for all organizations. The Company expects to adopt this ASU at its effective date. The Company’s SOSWarrant Liability (as defined in Note 4) is a derivative solely because of its down round feature. Any outstanding SOS Warrants as of the date of adoption willbe reclassified to equity and gains or losses on changes in fair value will no longer be recognized. No other derivatives instruments outstanding as ofDecember 31, 2017 would be affected. On May 17, 2017, the FASB issued ASU 2017-09, Scope of Modification Accounting, clarifies Topic 718, Compensation – Stock Compensation,such that an entity must apply modification accounting to changes in the terms or conditions of a share-based payment award unless all of the followingcriteria are met: (1) the fair value of the modified award is the same as the fair value of the original award immediately before the modification and the ASUindicates that if the modification does not affect any of the inputs to the valuation technique used to value the award, the entity is not required to estimate thevalue immediately before and after the modification; (2) the vesting conditions of the modified award are the same as the vesting conditions of the originalaward immediately before the modification; and (3) the classification of the modified award as an equity instrument or a liability instrument is the same as theclassification of the original award immediately before the modification; the ASU is effective for all entities for fiscal years beginning after December 15,2017, including interim periods within those years. Early adoption is permitted, including adoption in an interim period. The Company adopted this ASU onJanuary 1, 2018. The Company expects the adoption of this ASU will only impact consolidated financial statements as and when there is a modification to itsshare-based award agreements. 103  On January 5, 2017, the FASB issued ASU 2017-01 Business Combinations (Topic 805): Clarifying the Definition of a Business, which clarifies thedefinition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. Thestandard introduces a screen for determining when assets acquired are not a business and clarifies that a business must include, at a minimum, an input and asubstantive process that contribute to an output to be considered a business. This standard is effective for fiscal years beginning after December 15, 2017,including interim periods within that reporting period. The Company adopted this ASU on January 1, 2018, and expects that the adoption of this ASU couldhave a material impact on future consolidated financial statements as there may be acquisitions that are no longer considered to be business combinations. On November 17, 2016, the FASB issued ASU 2016-18, Restricted Cash (Topic 230), to clarify the presentation of restricted cash in the statement ofcash flows. The amendments require that a statement of cash flows explain the change during the period in restricted cash or restricted cash equivalents. Inaddition, changes in cash and cash equivalents, restricted cash and restricted cash equivalents should be included with cash and cash equivalents whenreconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. As a result, transfers between cash and restrictedcash will not be presented as a separate line item in the operating, investing or financing section of the cash flow statement. The amendments are effective forpublic entities for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted. The Companyadopted this ASU on January 1, 2018 and since the Company has no restricted cash, there is no current impact to the consolidated statement of cash flows. On August 26, 2016, the FASB issued ASU No. 2016-15, Classification of Certain Cash Receipts and Cash Payments (a consensus of the EmergingIssues Task Force. The amendments in ASU 2016-15 address eight specific cash flow issues and apply to all entities, including both business entities and not-for-profit entities that are required to present a statement of cash flows under ASC 230, Statement of Cash Flows. The amendments in ASU 2016-15 areeffective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption ispermitted, including adoption in an interim period. The Company adopted this ASU on January 1, 2018. The Company does not anticipate the adoption ofthis ASU will have a material effect on its consolidated financial statements and related disclosures. On March 30, 2016, the FASB issued ASU 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-BasedPayment Accounting. This ASU will simplify the accounting for share-based payment transactions, including the income tax consequences, classification ofawards as either equity or liabilities, and classification on the statement of cash flows. This ASU is effective for annual and interim periods beginning in 2017with early adoption permitted. The Company adopted this ASU on January 1, 2017. The Company grants primarily qualified incentive stock options whichdo not require the Company to withhold any income taxes when these options are exercised. As of December 31, 2017, none of the four employees who havenon-qualified stock options have exercised their vested options. During the year ended December 31, 2017, the Company withheld income taxes for vestedrestricted shares but these tax withholdings were processed by a third-party payroll service company. The tax withholding payments were received from theemployees who elected to pay cash within 30 days following the Company’s payment to the third-party payroll service company. As a result, these fundsflowed through the operating section of the Company’s consolidated statement of cash flows and had no impact on its consolidated statement of operations. On March 14, 2016, the FASB issued ASU 2016-06, Derivatives and Hedging (Topic 815): Contingent Put and Call Options in Debt Instruments.This new standard simplifies the embedded derivative analysis for debt instruments containing contingent call or put options by removing the requirement toassess whether a contingent event is related to interest rates or credit risks. This new standard was effective for the Company on January 1, 2017. TheCompany has identified the conversion feature of its debt instrument as an embedded derivative which meets the criteria to be bifurcated from its hostcontract, the Second Lien Credit Agreement (as defined below), and accounted for at fair value as derivative liabilities. On February 25, 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires companies to recognize the assets and liabilities for therights and obligations created by long-term leases of assets on the balance sheet. The guidance requires adoption by application of a modified retrospectivetransition approach for existing long-term leases and is effective for fiscal years beginning after December 15, 2018, including interim periods within thoseyears. Oil and natural gas leases are scoped out of the new ASU. As of December 31, 2017, the Company currently has only one operating lease within thescope of this standard that expires in less than 2 years. The effect of this guidance relating to the Company’s existing long-term leases is expected to requireadditional disclosures, and the Company is currently evaluating the impact that this ASU would have on the Company’s consolidated financial statements. 104  On May 28, 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, its final standard on revenue from contracts withcustomers. ASU 2014-09 outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers andsupersedes most current revenue recognition guidance, including industry-specific guidance. The core principle of the revenue model is that an entityrecognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expectsto be entitled in exchange for those goods or services. In applying the revenue model to contracts within its scope, an entity identifies the contract(s) with acustomer, identifies the performance obligations in the contract, determines the transaction price, allocates the transaction price to the performanceobligations in the contract and recognizes revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 applies to all contracts withcustomers and requires significantly expanded disclosures about revenue recognition. ASU 2014-09 has been amended several times with subsequent ASUsincluding ASU 2015-14 Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date. ASU 2014-09 will be effective for the Companyon January 1, 2018, with early adoption permitted, but not earlier than January 1, 2017. The guidance under these standards is to be applied using a fullretrospective method or a modified retrospective method. The Company has adopted the standard on January 1, 2018 using the modified retrospectiveapproach. The Company has a small number of contracts with customers and has identified transactions within the scope of the standard. The Company hasreviewed each of the contracts and transactions within the scope of the new standard. Based on the Company’s assessment, the adoption of the new standardwill not have a material impact on the Company’s consolidated financial statements. As a result of adoption of ASU 2014-09, the Company has changed itsmethod of recording certain natural gas gathering and processing charges that were previously recorded as expenses and will now be recorded as a reductionof revenues under the new standard. The Company has also changed its method of recording gas balancing arrangements to recognize revenues from gasbalancing arrangements only when a transaction with a customer has occurred. As of the date of adoption, the Company did not have any outstanding gasbalancing arrangements. Such changes are not expected to result in a material change in the Company’s controls and processes. NOTE 3 - OIL AND NATURAL GAS PROPERTIES The following table sets forth a summary of oil and natural gas property costs (net of divestitures) not being amortized at December 31, 2017 and2016: December 31, 2017 2016 (In thousands) Unproved acreage: Beginning Balance $24,461 $- Lease purchases 78,110 546 Assets conveyed - 23,915 Transfer and other reclassification to properties (800) - Total unproved acreage $101,771 $24,461 Wells in progress: Beginning Balance $7,453 $- Additions - 7,453 Reclassification to proved properties (7,453) - Total wells in progress not subject to DD&A $- $7,453 At December 31, 2017 and 2016, the Company completed an assessment of its inventory of unproved acreage for impairment, which resulted in notransfers from unproved acreage to proved properties. Depreciation, depletion and amortization expense related to proved properties was approximately $7.0 million and $1.7 million for the years endedDecember 31, 2017, and 2016, respectively. Divestiture of Oil and Natural Gas Properties On March 31, 2017, the Company entered into a purchase and sale agreement with Nanke Energy LLC for the divestiture of all of its oil and naturalgas properties located in the Denver-Julesburg Basin (the “DJ Basin”) for consideration of $2 million, subject to customary post-closing purchase priceadjustments. The sale of the Company’s DJ Basin assets did not significantly alter the relationship between capitalized costs and proved reserves, and assuch, all proceeds were recorded as adjustments to the Company’s full cost pool with no gain or loss recognized. The DJ Basin assets were sold to an entityowned by the Company’s former chief financial officer and therefore the divestiture is considered a related party transaction. See Note 9 - Related PartyTransactions. The net proceeds of $1.08 million received on March 31, 2017 included an offset against $0.7 million of severance pay and $0.22 million ofnet sales adjustments due to the purchaser. In addition, the Company received $0.2 million in proceeds from the sale of non-operated properties sold in 2017. Acquisition of Unproved Properties On October 3, 2017, the Company entered into a lease acquisition agreement (the “Acquisition Agreement”) with KEW Drilling, a Delaware limitedpartnership (“KEW”), pursuant to which the Company acquired from KEW unproved acreage in Winkler County, Texas for an aggregate purchase price of$48.9 million pursuant to the terms set forth in the Acquisition Agreement (collectively, the “Leases”). The Company funded the purchase price for the leaseswith borrowings drawn under the Delayed Draw Term Loans pursuant to the Second Lien Credit Agreement as described in Note 7 - Long-term Debt below. 105  NOTE 4 - FAIR VALUE OF FINANCIAL INSTRUMENTS The Company measures fair value of its financial assets on a three-tier value hierarchy, which prioritizes the inputs, used in the valuationmethodologies 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 whenmeasuring fair value. The determination of the fair values of our derivative contracts incorporates various factors, which include not only the impact of our non-performance risk on our liabilities but also the credit standing of the counterparties involved. We utilize counterparty rate of default values to assess theimpact of non- performance risk when evaluating both our liabilities to, and receivables from, counterparties. Recurring Fair Value Measurements Fair Value Measurement Classification Quoted Prices inActive Markets forIdentical Assets orLiabilities Significant OtherObservable Inputs SignificantUnobservableInputs (Level 1) (Level 2) (Level 3) Total (in thousands) As of December 31, 2017 Oil and natural gas derivative swap contracts $- $(706) $- $(706)Oil and natural gas derivative collar contracts - (147) - (147)Warrant liabilities - - (223) (223)Second Lien Term Loan conversion features - - (72,714) (72,714)Total $- $(853) $(72,937) $(73,790)As of December 31, 2016 Warrant liabilities - - (1,400) (1,400)Total $- $- $(1,400) $(1,400) The Company’s derivative liability associated with the Second Lien Term Loan and warrants are measured using Level 3 inputs as follows: Second Lien Term Loan Conversion Features: Under the terms of the Company’s second lien credit agreement, dated as of April 26, 2017, by andamong the Company, certain subsidiaries of the Company, as guarantors (the “Guarantors”), Wilmington Trust, National Association, as administrative agent(the “Agent”), and the lenders party thereto (the “Lenders”), including Värde Partners, Inc., as lead lender (the “Lead Lender”), as amended (the “Second LienCredit Agreement”), the Lead Lender has the option to convert 70% of the principal amount of each tranche of the Second Lien Term Loan (the “Loan”)under the Second Lien Credit Agreement, together with accrued paid-in-kind interest and the make-whole premium on such principal amount (together, the“Conversion Sum”), into shares of common stock. The make-whole premium is the cash amount representing the excess of (a) the present value at suchrepayment, prepayment or acceleration date or the date the obligations otherwise become due and payable in full of (1) the sum of the principal amountrepaid, prepaid or accelerated plus (2) the interest accruing on such principal amount from the date of such repayment, prepayment or acceleration throughthe maturity date (excluding accrued but unpaid paid-in-kind interest to the date of such repayment, prepayment or acceleration), such present value to becomputed using a discount rate equal to the Treasury Rate plus 50 basis points discounted to the repayment, prepayment or acceleration date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months), over (b) the principal amount of the Loan repaid, prepaid or accelerated. Thenumber of shares issued will be based on the division of 70% of the Conversion Sum by the conversion price then in effect. 106  The Company also has the option to cause the Loan to convert if, at the time of exercise of the Company’s conversion option, the closing price ofthe Company’s common stock has been at least 150% of the Conversion Price (as defined below) then in effect for at least 20 of the 30 immediatelypreceding trading days. The features of the make-whole premium in the Loan require the conversion features to be recorded as embedded derivatives andbifurcated from its host contracts, the Loan, and accounted for separately from the debt. The conversion features contained in the Loan are recorded as aderivative liability at fair value each reporting period based upon values determined through the use of discounted lattice models of the Loan under theSecond Lien Credit Agreement. Change in fair value is accounted for in the consolidated statement operations. The embedded derivatives under the SecondLien Credit Agreement including the delayed draw term loans were recorded at closing as a derivative liability with a fair value of approximately $65.6million. At December 31, 2017, the fair value of the derivative liabilities associated with the Loan conversion features was approximately $72.7 million. As aresult, the Company recorded an unrealized loss of $7.1 million on the change in fair value of derivative liabilities associated with the Loan conversionfeatures. The fair value of the holder conversion features was determined using a binomial lattice model based on certain assumptions including (i) theCompany’s stock price, (ii) risk-free rate, (iii) expected volatility, (iv) the Company’s implied credit rating, and (v) the implied credit yield of the Loan. Heartland Warrant Liability. On January 8, 2015, the Company entered into a credit agreement with Heartland Bank (the “Heartland CreditAgreement”). In connection with the Heartland Credit Agreement, the Company issued a warrant to purchase up to 22,500 shares of the Company’s commonstock at an exercise price of $25.00. The warrant contained a price protection feature that would have automatically reduced the exercise price if theCompany entered into another agreement pursuant to which warrants were issued with a lower exercise price and would also have triggered an adjustment tothe number of underlying shares of common stock. On June 14, 2017, the Company and Heartland executed an amended and restated warrant agreementwhereby the Company issued a warrant to purchase 160,714 shares of common stock at an exercise price of $3.50 to replace the original warrant to purchase22,500 shares of common stock to settle a disagreement regarding the impact of the anti-dilutive price protection provisions in the original warrant. Theamended and restated warrant agreement no longer contains any anti-dilutive price protection provisions and the warrant is no longer accounted for as aderivative. As a result of the issuance of the amended and restated warrant, the Company recorded approximately $0.02 million of realized gain on theHeartland warrant liability during the year ended December 31, 2017. For the year ended December 31, 2016, the Company recorded an unrealized loss ofapproximately $0.04 million on the Heartland warrant liability. SOS Warrant Liability. On June 23, 2016, in conjunction with the merger with Brushy in June 2016, the Company issued to SOS a warrant topurchase up to 200,000 shares of the Company’s common stock at an exercise price of $25.00. The warrant contains a price protection feature that willautomatically reduce the exercise price if the Company enters into another agreement pursuant to which warrants are issued with a lower exercise price. Thefair value of the warrants was approximately $0.2 million at December 31, 2017. For the years ended December 31, 2017, and 2016, the Company incurred anunrealized loss of approximately $0.1 million and an unrealized gain of $0.02 million, respectively, on the SOS warrant liability. As of December 31, 2017and 2016, the fair value of the SOS warrant liability was approximately $0.2 million and $0.1 million, respectively. Bristol Capital, LLC Warrant Liability. On September 2, 2014, the Company entered into a consulting agreement with Bristol Capital, LLC(“Bristol”), pursuant to which the Company issued to Bristol a warrant to purchase up to 100,000 shares of the Company’s common stock at an exercise priceof $20.00 (or, in the alternative, options exercisable for 100,000 shares of common stock, but in no case, both). The agreement had a price protection featurethat automatically reduced the exercise price if the Company entered into another consulting agreement pursuant to which warrants were issued with a lowerexercise price, which was triggered in year 2016. On March 14, 2017, the Company issued 77,131 shares of common stock to Bristol pursuant to a settlementagreement for a cashless exercise of the warrant. The Bristol warrant was also revalued on March 14, 2017 resulting in a realized gain in fair value of $0.8million for the year ended December 31, 2017 and decreasing the Bristol derivative liability to $0.4 million. As a result of the cashless exercise, theCompany reclassified the $0.4 million of Bristol derivative liability to additional paid-in capital as of March 31, 2017. For the year ended December 31,2016, the Company recorded an unrealized loss of approximately $1.2 million on the Bristol warrant liability. 107  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 inthe fair value hierarchy, except for the commodity derivatives classified as Level 2 as disclosed in Note 6, as of December 31, 2017 and 2016: Second LienTermLoanConversionFeatures WarrantLiabilities Total (in thousands) Balance at January 1, 2017 $- $(1,400) $(1,400)Issuance (65,647) - (65,647)Cashless exercise of warrants - 370 370 Change in fair value of derivative liabilities (7,067) 807 (6,260)Balance at December 31, 2017 $(72,714) $(223) $(72,937) ConvertibleDebentureDerivativeLiability WarrantLiabilities IncentiveBonus Total (in thousands) Balance at January 1, 2016 $(6) $(56) $(223) $(285)Additional liability - (164) (393) (557)Reversal of accrued bonus - - 718 718 Converted to equity (54) - - (54)Change in fair value of derivative liabilities 60 (1,180) (102) (1,222)Balance at December 31, 2016 $- $(1,400) $- $(1,400) NOTE 5 - ASSET RETIREMENT OBLIGATIONS (ARO) The information below reconciles the value of the asset retirement obligation for the periods presented: Year Ended December 31, 2017 2016 (In thousands) Balance at January 1 $1,257 $208 Liabilities assumed from merger - 777 Liabilities incurred 20 311 Accretion expense 82 132 Settlements (288) (92)Change in estimate (119) (79)Balance at December 31 952 1,257 Less: current portion of ARO at December 31 (226) (338)Total Long-term ARO at end of year $726 $919 NOTE 6 - DERIVATIVES As discussed in Note 4, the Second Lien Term Loan contains conversion features that are exercisable at the option of the Lead Lender or theCompany. The conversion features have been identified as embedded derivatives which (i) contain economic characteristics that are not clearly and closelyrelated to the host contract, the Second Lien Term Loan, and (ii) separate, stand-alone instruments with similar terms would qualify as derivative instruments.As such, the conversion features were bifurcated and accounted for separately from the Second Lien Term Loan. The conversion features are recorded at fairvalue for each reporting period with changes in fair value included in the consolidated statement of operations for the year ended December 31, 2017. TheCompany recorded derivative liabilities associated with the Second Lien Term Loan at an original fair value of approximately $65.6 million at issuance. Asof December 31, 2017, the fair value of the derivative liability was approximately $72.7 million. As a result, the Company recognized unrealized gains ofapproximately $7.1 million in its consolidated statement of operations for the year ended December 31, 2017. There were no derivative liabilities associatedwith convertible debt instruments for the year ended December 31, 2016. In addition, as of December 31, 2017 and 2016, the Company’s outstandingderivative liabilities included the fair value of the derivative liabilities associated with the SOS warrants totaled $0.2 million and $0.2 million, respectively. To reduce the impact of fluctuations in oil and natural gas prices on the Company’s revenues, or to protect the economics of property acquisitions,the Company periodically enters into derivative contracts with respect to a portion of its projected oil and natural gas production through varioustransactions that fix or modify the future prices to be realized. The derivative contracts may include fixed-for-floating price swaps (whereby, on the settlementdate, 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 notionalquantity of production), put options (whereby the Company pays a cash premium in order to establish a fixed floor price for a notional quantity of productionand, 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 settlementdate, 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 ofproduction). 108  These hedging activities, which are governed by the terms of our Second Lien Credit Agreement, are intended to support oil and natural gas prices attargeted levels and manage exposure to oil and natural gas price fluctuations. It is our policy to enter into derivative contracts only with counterparties thatare creditworthy and competitive market makers. All of our derivatives are with non-lender counterparties and are designated as unsecured. Certain of ourderivative counterparties may require the posting of cash collateral under certain conditions. It is never the Company’s intention to enter into derivativecontracts for speculative trading purposes. All of our derivatives are accounted for as mark-to-market activities. Under ASC Topic 815, “Derivatives and Hedging,” these instruments arerecorded on the consolidated balance sheets at fair value as either short term or long-term assets or liabilities based on their anticipated settlement date. TheCompany nets derivative assets and liabilities by commodity for counterparties where a legal right to such offset exists. Changes in the derivatives’ fairvalues are recognized in current earnings since the Company has elected not to designate its current derivative contracts as cash flow hedges for accountingpurposes. The following table presents the Company’s derivative positions as of December 31, 2017: As ofDecember 31, 2017 (In thousands) Oil positions: Fixed-for-floating price swaps (NYMEX WTI): Hedged Volume (Bbls) 75,070 Average price ($/Bbl) $50.74 Put Options (NYMEX WTI): Hedged Volume (Bbls) 105,930 Average price ($/Bbl) $52.50 Call Options (NYMEX WTI): Hedged Volume (Bbls) 105,930 Average price ($/Bbl) $60.80 Year Ended December 31, 2017 (In thousands) Beginning fair value of commodity derivatives $— Net losses on crude oil derivatives (1,063)Net settlement paid on crude oil derivative contracts 96 Net settlement unpaid on crude oil derivative contracts 114 Ending fair value of commodity derivatives $(853) The Company’s derivatives are presented on a net basis under fair value of derivative instruments on the consolidated balance sheets. The followinginformation summarizes the gross fair values of derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on theCompany’s consolidated balance sheets: December 31, 2017 Gross Amount ofRecognized Assetsand Liabilities Gross AmountsOffset in theConsolidatedBalance Sheets Net AmountsPresented in theConsolidatedBalance Sheets (in thousands) Offsetting Derivative Assets: Current asset $- $- $- Long-term asset - - - Total asset $- $- $- Offsetting Derivative Liabilities: Current liability $853 $- $853 Long-term liability - - - Total liability $853 $- $853 109  The Company had no hedging activities as of December 31, 2016. NOTE 7 - LONG-TERM DEBT As of December 31, 2017 2016 (In thousands) 6% Bridge Loans associated with the amended First Lien Term Loan, due 2019, net of debt issuance costs $30,363 $- 6% Senior Secured Term Loan, due 2019, net of debt issuance costs - 29,214 8.25% Second Lien Term Loans, due 2021, net of debt issuance costs and debt discount 96,431 - 6% note payable to SOS Investment, LLC, due 2019 1,000 1,000 Other notes payable, due 2018 11 29 Total Long-term debt $127,805 $30,243 Less: current portion (11) (17)Total Long-term debt, net of current portion $127,794 $30,226 Total principal amount of debt maturities related to borrowings for the five years ending December 31, 2022 include: $0.01 million in 2018, $31.0million in 2019, and $150.0 million in 2021. There will be no payments due in 2020 and 2022. At December 31, 2017 and 2016, the carrying amounts of term loans were as follows: PrincipalAmount Paid-in-kind Interest Unamortized Debt Issuance Costs & DebtDiscount Carrying Amount December 31, 2017: Bridge Loans associated with the amended First Lien Term Loan, dueSeptember 2019 $30,000 $807 $(444) $30,363 Second Lien Term Loan, due April 2021 150,000 5,752 (59,321) 96,431 Total: $180,000 $6,559 $(59,765) $126,794 December 31, 2016: Senior Secured Term Loan, due 2019 $31,000 $- $(1,786) $29,214 Total: $31,000 $- $(1,786) $29,214 First Lien Credit Agreement On September 29, 2016, the Company entered into a first lien credit agreement by and among the Company and its wholly owned subsidiaries,Brushy, Impetro Operating and Resources (the “Initial Guarantors”), and the lenders party thereto (each a “Lender” and together, the “Lenders”) and T.R.Winston & Company, LLC (“TRW”) acting as initial collateral agent (the “First Lien Credit Agreement”). The First Lien Credit Agreement provided for a $50 million three-year senior secured term loan with initial commitments of $31 million. OnFebruary 7, 2017, pursuant to the terms of the First Lien Credit Agreement, the Company exercised the accordion advance feature, increasing the aggregateprincipal amount outstanding under the term loan from $31 million to $38.1 million (the “First Lien Term Loan”). In connection with the exercise of the accordion advance feature for $7.1 million, the Company incurred $0.4 million in commitment fees and alsoamended certain warrants held by the lenders to purchase up to approximately 738,638 shares of common stock, such that the exercise price per share waslowered from $2.50 to $0.01. The Company accounted for these repriced warrants as additional debt discount to the First Lien Term Loan for $1.0 million, tobe accreted, together with the remaining $0.6 million debt discount at December 31, 2016, over the remaining term of the loan. On April 26, 2017, theCompany fully paid off the amount outstanding of $38.1 million including accrued interest on the First Lien Term Loan. As a result, for the year endedDecember 31, 2017, the Company fully amortized approximately $1.4 million of debt discount and approximately $1.6 million of deferred financing costs,respectively. These amounts were recorded as a non-cash component of interest expense. 110  Amendments to First Lien Credit Agreement On April 24, 2017, and subsequently on April 26, 2017, and July 25, 2017, and October 19, 2017 the Company entered into the first, second, thirdand fourth amendments (together, the “First Lien Amendments”), respectively, to the Company’s First Lien Credit Agreement. The First Lien Amendments,among other things, added Lilis Operating and Hurricane Resources as guarantors under the credit agreement, added certain lenders, and extended furthercredit in the form of an initial bridge loan in an aggregate principal amount of $15.0 million (the “Initial Bridge Loan”). The Initial Bridge Loan was fullydrawn on April 24, 2017, and is secured by the same first priority liens on substantially all of the Company’s assets as the First Lien Term Loan. Additionally,pursuant to the First Lien Amendments, the lenders made further extensions of credit, in addition to the currently existing loans under the First Lien CreditAgreement (the “Bridge Loans”), in the form of an additional, incremental bridge loan in an aggregate principal amount of $15,000,000 (the “IncrementalBridge Loan”, and together with the Bridge Loans, the “First Lien Loans”). The First Lien Loans, including the Incremental Bridge Loan, were fully drawn asof October 19, 2017. As of December 31, 2017, the unamortized portion of the debt issuance costs associated with the First Lien Loans were approximately$0.3 million. The First Lien Credit Agreement, as amended, (a) provides that, effective as of October 1, 2017, the unpaid principal of the First Lien Loans will bear(i) cash interest at a rate per annum of 10% and (ii) additional interest at a rate per annum of 6%, payable only in-kind by increasing the principal amount ofthe First Lien Loans by the amount of such interest due on each interest payment date and (b) permits the loans under the Second Lien Credit Agreement toequal an increased amount of up to $175.0 million. The First Lien Loans mature on October 21, 2018 and may be repaid in whole or part at any time at theoption of the Company, subject to the payment of certain specified prepayment premiums. Additionally, the First Lien Loans are subject to mandatoryprepayment with the net proceeds of certain asset sales and casualty events, subject to the right of the Company to reinvest the net proceeds of asset sales andcasualty events within 180 days. The Company subsequently used approximately $31.5 million of the proceeds of the Riverstone First Lien Loans(hereinafter defined) to repay in full our obligations under and retire the First Lien Credit Agreement. As the First Lien Loans were fully repaid subsequent toDecember 31, 2017, these loans were classified as long-term. Second Lien Credit Agreement On April 26, 2017, the Company entered into the Second Lien Credit Agreement comprised of convertible loans in an aggregate initial principalamount of up to $125 million in two tranches. The first tranche consists of an $80 million term loan (the “Second Lien Term Loan”), which was fully drawnand funded on April 26, 2017. The second tranche consists of up to $45 million in delayed-draw term loans (the “Delayed Draw Term Loan” and, togetherwith the Second Lien Term Loan, the “Second Lien Loans”) to be funded on or before February 28, 2019, at the request of the Company, subject to certainconditions, in a single draw or in multiple draws. Each tranche of Second Lien Loans will bear interest at a rate per annum of 8.25%, compounded quarterly inarrears and payable only in-kind by increasing the principal amount of the loan by the amount of the interest due on each interest payment date. On October 3, 2017, the Company, certain subsidiaries of the Company, as guarantors (the “Guarantors”), Wilmington Trust, National Association,as administrative agent and the lenders party thereto, entered into Amendment No. 1 to the Second Lien Credit Agreement (“Amendment No. 1 to the SecondLien Credit Agreement”). The purpose of Amendment No. 1 to the Second Lien Credit Agreement is to waive certain conditions precedent to the drawing ofthe Delayed Draw Term Loan under the Second Lien Credit Agreement and to provide for the funding of such Delayed Draw Term Loan upon the signing ofthe lease acquisition agreement with KEW Drilling, a Delaware limited partnership. The Company borrowed the full $45.0 million of the availability underthe Delayed Draw Term Loan on October 4, 2017. On October 19, 2017, the Company entered into a second amendment to the Second Lien Credit Agreement (“Amendment No. 2 to the Second LienCredit Agreement”), by and among the Company, the Guarantors, the Agent and the Lenders, including the Lead Lender. Amendment No. 2 to the SecondLien Credit Agreement permits the Company to incur the Incremental Bridge Loan under the First Lien Credit Agreement. On November 10, 2017, the Company entered into a third amendment to the Second Lien Credit Agreement (“Amendment No. 3 to the Second LienCredit Agreement”), by and among the Company, the Guarantors, the Agent and the Lenders, including the Lead Lender. Amendment No. 3 to the SecondLien Credit Agreement increased by $25.0 million the amount of delayed draw term loans available for borrowing under the Second Lien Credit Agreement.The additional $25.0 million of Delayed Draw Term Loan was drawn on November 10, 2017. The $25.0 million of proceeds from these loans may be used tofund oil and natural gas property acquisitions, subject to certain limitations, to fund drilling and completion costs or for other general corporate purposes. 111  The Second Lien Loans are secured by second priority liens on substantially all of the Company’s and the Guarantors’ assets, including their oil andnatural gas properties located in the Delaware Basin, and all of the obligations thereunder are unconditionally guaranteed by each of the Guarantors. TheSecond Lien Loans mature on April 26, 2021. The Loans are subject to mandatory prepayment with the net proceeds of certain asset sales, casualty eventsand debt incurrences, subject to the right of the Company to reinvest the net proceeds of asset sales and casualty events within 180 days and, in the case ofasset sales and casualty events, prepayment of the Bridge Loan. The Company may not voluntarily prepay the Loans prior to March 31, 2019 except (a) inconnection with a Change of Control (as defined in the Second Lien Credit Agreement) or (b) if the closing price of our common stock on the principalexchange on which it is traded has been equal to or greater than 110% of the Conversion Price (as defined below) for at least 20 of the 30 trading daysimmediately preceding the prepayment. The Company will be required to pay a make-whole premium in connection with any mandatory or voluntaryprepayment of the Loans. Each tranche of the Second Lien Loans is separately convertible at any time, in full and not in part, at the option of the Lead Lender, as follows: ·70% of the principal amount of each tranche of Second Lien Loans, together with accrued and unpaid interest and the make-whole premium on suchprincipal amount (the “Conversion Sum”), will convert into a number of newly issued shares of common stock determined by dividing the total ofsuch principal amount, accrued and unpaid interest and make-whole premium by $5.50 (subject to certain customary adjustments, the “ConversionPrice”); and ·30% of the principal amount of the Conversion Sum will convert on a dollar for dollar basis into a new term loan (the “Take Back Loans”). The terms of the Take Back Loans will be substantially the same as the terms of the Second Lien Loans, except that the Take Back Loans will not beconvertible and will bear interest payable in cash at a rate of LIBOR plus 9% (subject to a 1% LIBOR floor). Additionally, the Company will have the option to convert the Second Lien Loans, in whole or in part, into shares of common stock at any time orfrom time to time if, at the time of exercise of the Company’s conversion option, the closing price of the common stock on the principal exchange on which itis traded has been at least 150% of the Conversion Price then in effect for at least 20 of the 30 immediately preceding trading days. Conversion at theCompany’s option will occur on the same terms as conversion at the Lender’s option. As discussed in Note 4, Fair Value of Financial Instruments, above and Note 6, Derivatives, above, the Company separately accounts for theembedded conversion features as a derivative instrument in accordance with accounting guidance relating to recording embedded derivatives at fair value.The initial fair value of the embedded derivatives is recorded as a debt discount to the Second Lien Term Loan. The debt discount is amortized over the termof the Second Lien Term Loan using the effective interest method. Restrictive Covenants As of December 31, 2017, the Company’s First Lien Credit Agreement and Second Lien Credit Agreement contain various covenants, includingrestrictions on additional indebtedness, payment of cash dividends on common stock and preferred stock, and maintenance of certain financial ratios. TheFirst Lien Credit Agreement, as amended, requires that, commencing with the testing period ending at December 31, 2018, we satisfy an asset coverage ratio(“ACR”) test by maintaining an ACR of 1.00 to 1.00 or greater. In addition, the Second Lien Credit Agreement requires us to maintain, commencing with thetesting period ending June 30, 2018, an ACR of 1.00 to 1.00. or greater. At December 31, 2017, the Company was in compliance with all restricted covenants. SOS Note On June 30, 2016, pursuant to the merger agreement with Brushy and as a condition of the fourth amendment to such merger agreement, theCompany was required to make a cash payment of $500,000 to SOS, and also executed a subordinated promissory note with SOS, for $1 million, at an interestrate of 6% per annum which matures on June 30, 2019. In conjunction with the cash payment and the note, the Company also issued 200,000 warrants at anexercise price of $25.00. The Company accounted for the cost of warrants of $0.2 million as part of the Brushy merger transaction costs during the year endedDecember 31, 2016. The SOS note was fully paid on January 22, 2018. Interest Expense The components of interest expense are as follows: Years Ended December 31, 2017 2016 Interest on term loans $1,774 $446 Interest on notes payable 53 412 Interest on convertible notes and debentures (1) - 880 Paid-in-kind interest on term loans 6,559 - Amortization of debt financing costs on term loans 1,886 328 Amortization of discount on term loans 8,485 2,858 Total: $18,757 $4,924 (1)These convertible notes and debentures including accrued interest were fully converted into the Company’s common stock upon closing of theBrushy merger on June 23, 2016. 112  NOTE 8 - COMMITMENTS AND CONTINGENCIES Environmental and Governmental Regulation At December 31, 2017, there were no known environmental or regulatory matters which are reasonably expected to result in a material liability to theCompany. Many aspects of the oil and natural gas industry are extensively regulated by federal, state, and local governments in all areas in which theCompany has operations. Regulations govern such things as drilling permits, environmental protection and air emissions/pollution control, spacing of wells,the unitization and pooling of properties, reports concerning operations, land use, and various other matters including taxation. Oil and natural gas industrylegislation and administrative regulations are periodically changed for a variety of political, economic, and other reasons. As of December 31, 2017, theCompany had not been fined or cited for any violations of governmental regulations that would have a material adverse effect upon the financial conditionof the Company. Legal Proceedings The Company may from time to time be involved in various legal actions arising in the normal course of business. In the opinion of management, theCompany’s liability, if any, in these pending actions would not have a material adverse effect on the financial position of the Company. The Company’sgeneral 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 ofoperations or financial condition. Operating Leases The Company has a two-year operating lease for office space in San Antonio, Texas and various other operating leases on a month-to-month basiswhich include office leases in Fort Worth and Houston, Texas and corporate apartment leases in San Antonio, Texas. Rent expense for the years endedDecember 31, 2017 and 2016, was approximately $0.6 million and $0.2 million, respectively. As of December 31, 2017, the Company has approximately$0.2 million of minimum lease payments on its operating lease which consists of annual minimum lease payments of approximately $0.2 million in 2018. NOTE 9 - RELATED PARTY TRANSACTIONS During the years ended December 31, 2017 and 2016, the Company has engaged in the following transactions with related parties: Year Ended December 31, Related Party Transactions 2017 2016 ($ in thousands) Greater than 10% Shareholder: 113  Year Ended December 31, Related Party Transactions 2017 2016 ($ in thousands) Bryan Ezralow (Ezralow as a family has>10% ownership in the Company) Participated in Series B Preferred Stock offering in 2016and converted into common stock during the year endedDecember 31, 2017. $628 $1,300 Participated in the September 29, 2016 $50 million creditfacility which was fully paid off during the year endedDecember 31, 2017. 1,356 1,450 Converted the holdings of Debentures entered into onDecember 29, 2015 into common stock through EZ ColonyPartners, LLC owned by Bryan Ezralow upon the closing ofthe Brushy merger on June 23, 2016. - 1,540 Warrants exercised at $0.01 per share during the year endedDecember 31, 2017 21 - Participated in private placement transaction on February28, 2017 1,400 - Total: $3,405 $4,290 Mark Ezralow Participated in Series B Preferred Stock offering in 2016and converted into common stock during the nine monthsended September 30, 2017. $574 $- Participated in the September 29, 2016 $50 million creditfacility which was fully paid off during the year endedDecember 31, 2017. 1,055 950 Warrants exercised at $0.01 per share during the year endedDecember 31, 2017. 18 - Participated in private placement transaction on February28, 2017. 1,200 - Total: $2,847 $950 114  Year Ended December 31, Related Party Transactions 2017 2016 ($ in thousands) Investor Company Participated in Series B Preferred Stock offering in 2016and converted into common stock during the year endedDecember 31, 2017. $4,318 $- Participated in the September 29, 2016 $50 million creditfacility which was repaid during the year ended December31, 2017 20,093 Participated in the amendment to the Company’s first liencredit facility in April 2017 by reinvesting its principalamount that was paid down in the form of bridge loanincluding paid and accrued interest 2,188 - Participated in the amendment to the Company’s first liencredit facility in October 2017 by an investment in the formof incremental bridge loan including paid and accruedinterest 1,368 - Warrants exercised at $0.01 per share during the year endedDecember 31, 2017. 23 - Total: $27,990 $- Directors and Officers: G. Tyler Runnels,(Director) Received advisory fee for Series B Preferred Stock offeringfees and warrants to purchase up to 452,724 shares ofcommon stock, at an exercise price of $1.30 per share,exercisable on or after September 17, 2016 through T.R.Winston & Company, LLC (“TRW”) (1). $- $500 115  Year Ended December 31, Related Party Transactions 2017 2016 ($ in thousands) Reinvested advisory fee for 150 shares of Series B PreferredStock and 68,182 warrants at exercise price of $2.50 pershare through TRW. - 150 Converted shares of Series A Preferred Stock into commonstock upon the closing of the Brushy merger on June 23,2016 through TRW and Runnels Family Trust DTD 1-11-2000(2). - 779 Cash paid for advisory fee on Convertible Notes which wasreinvested in 350 shares of Series B Preferred Stock throughTRW. - 350 Participated in Convertible Notes maturing on June 30,2016 and April 1, 2017 through TRW, which were fullyconverted into common stock upon closing of the Brushymerger on June 23, 2016. - 400 116  Year Ended December 31, Related Party Transactions 2017 2016 ($ in thousands) Participated in Series B Preferred Stock offering in 2016through TRW and Runnels Family Trust DTD 1-11-2000and converted into common stock during the year endedDecember 31, 2017. 520 - Participated in private placement transaction on February28, 2017 through TRW and Runnels Family Trust DTD 1-11-2000. 796 - Warrants exercised at $0.10 per share during the year endedDecember 31, 2017 through Runnels Family Trust DTD 1-11-2000 and TRW Capital Growth Fund, LP(3). 17 - Sublet office space through TRW in New York to theCompany for rent of $10,000 per month from January 1,2017 through October 31, 2017. 80 15 Total: $1,413 $2,194 117  Year Ended December 31, Related Party Transactions 2017 2016 ($ in thousands) Nuno Brandolini(Director) Participated in Convertible Notes maturing on September30, 2016 and April 1, 2017. These notes were fullyconverted into common stock upon closing of the Brushymerger on June 23, 2016. $- $250 Converted shares of Series A Preferred Stock into commonstock upon the closing of the Brushy merger on June 23,2016. - 100 Warrants exercised at $0.10 per share during the year endedDecember 31, 2017. 4 - Total: $4 $350 General Merrill McPeak(Director) Participated in Convertible Notes maturing on June 30,2016 and April 1, 2017. These notes were fully convertedinto common stock upon closing of the Brushy merger onJune 23, 2016. $- $250 118  Year Ended December 31, Related Party Transactions 2017 2016 ($ in thousands) Converted shares of Series A Preferred Stock into commonstock upon the closing of the Brushy merger on June 23,2016. - 250 Total: $- $500 R. Glenn Dawson(Director) Participated in Convertible Notes maturing on June 30,2016 and April 1, 2017. These notes were fully convertedinto common stock upon closing of the Brushy merger onJune 23, 2016. $- $50 Participated in Series B Preferred Stock offering in 2016and converted into common stock during the year endedDecember 31, 2017. 130 125 Total: $130 $175 119  Mark Christensen (Director) Participated in the Company’s accordion advance of thefirst lien facility in February 2017 through Trace CapitalInc. (“Trace Capital”) (4) $1,600 $- Participated in private placement transaction on February28, 2017 through Trace Capital. 1,000 - Participated in the amendment to the Company’s first liencredit facility in April 2017 through Trace Capital byreinvesting its principal amount that was paid down in theform of bridge loans plus paid and accrued interest 1,586 - Participated in the September 29, 2016 $50 million creditfacility and February 7, 2017 accordion advance of the firstlien facility which were repaid during the year endedDecember 31, 2017 2,612 Participated in the amendment to the Company’s first liencredit facility in October 2017 by an investment in the formof incremental bridge loan including paid and accruedinterest 1,578 - Exercise of warrants 2 - Received fees through KES 7 Capital Inc. (5) for acting asan advisor on certain of the Company’s financingtransactions. 905 - Total: $9,283 $- Ronald D. Ormand (ExecutiveChairman) Participated in Convertible Notes maturing on June 30,2016 and April 1, 2017 through the Bruin Trust.(6) Thesenotes were fully converted into common stock upon closingof the Brushy merger on June 23, 2016. $- $1,150 Participated in Series B Preferred Stock offering in 2016and converted into common stock in 2017 through PerugiaInvestment LP(7) during the year ended December 31, 2017. 1,093 1,000 Exercise of warrants 4 - Converted shares of Series A Preferred Stock into commonstock through Perugia Investment LP upon the closing ofthe Brushy merger on June 23, 2016. - 500 Consulting fee paid to MLV & Co. LLC for which Mr.Ormand was the Managing Director and Head of the EnergyInvestment Banking Group - 100 Accounts receivable due for federal tax withholding onvested restricted shares. This amount was deducted frombonus payment in February 2018. 107 - Total: $1,204 $2,750 Joseph C. Daches (Chief FinancialOfficer) Accounts receivable due for federal tax withholding onvested restricted shares. This amount was deducted frombonus payment in February 2018. $100 - Total: $100 $- Brennan Short (former Chief OperatingOfficer) Consulting fees paid to MMZ Consulting, Inc. which isowned by Mr. Short. Mr. Short is the sole member of thecorporation. $283 $- Total: $283 $- Abraham Mirman (former ChiefExecutive Officer and Director) Participated in Convertible Notes maturing on June 30,2016 and April 1, 2017 through The Bralina Group,LLC.(8) These notes were fully converted into commonstock upon closing of the Brushy merger on June 23, 2016. $- $750 Participated in Series B Preferred Stock offering in 2016and converted into common stock in 2017 through theBralina Group, LLC. 1,803 1,650 Converted shares of Series A Preferred Stock into commonstock upon the closing of the Brushy merger on June 23,2016. - 250 Total: $1,803 $2,650 Kevin Nanke (former Chief FinancialOfficer) Participated in Convertible Notes maturing on June 30,2016 and April 1, 2017. These notes were converted intothe Company’s common stock upon the closing of theBrushy merger on June 23, 2016. $- $100  Participated in Series B Preferred Stock offering in 2016and converted into common stock in 2017 through KKNHoldings LLC during the year ended December 31, 2017. 219 200 Warrants exercised at $0.01 per share during the year endedDecember 31, 2017. 4 - Purchased the DJ Basin properties from the Companythrough Nanke Energy, LLC on January 31, 2017. 2,000 - Total: $2,223 $300 120  (1)Mr. Runnels has sole voting and dispositive power over all securities held by T.R. Winston & Company, LLC.(2)Mr. Runnels acts as a trustee with Jasmine N. Runnels for the Runnels Family Trust DTD 1-11-2000 and has shared voting and dispositive power.(3)Mr. Runnels has sole voting and dispositive power over all securities held by TRW Capital Growth Fund, LP.(4)Trace Capital Inc. is an entity controlled by Mr. Christensen’s wife, who has sole voting and dispositive power over the securities held by Trace CapitalInc.(5)Mr. Christensen has sole voting and dispositive power over all securities held by KES 7 Capital Inc.(6)An irrevocable trust managed by Jerry Ormand, Mr. Ormand's brother, as trustee and whose beneficiaries are the adult children of Ronald Ormand.(7)Mr. Ormand has sole voting and dispositive power over the securities held by Perugia Investment LP.(8)Mr. Mirman has shared voting and dispositive power over the securities held by The Bralina Group, LLC with Susan Mirman. NOTE 10 - INCOME TAXES The income tax provision (benefit) for the years ended December 31, 2017 and 2016 consisted of the following: December 31, 2017 2016 (in thousands) U.S. Federal: Current $- $- Deferred 32,579 (2,971) State and local: Current - - Deferred 1,059 (124) 33,638 (3,095)Change in valuation allowance (33,638) 3,095 Income tax provision $- $- The tax effects of temporary differences that give rise to the Company’s deferred tax asset as of December 31, 2017 and 2016 consisted of thefollowing: December 31, 2017 2016 (In thousands) Deferred tax assets: Oil and natural gas properties and equipment $- $5,156 Net operating loss carry-forward 15,653 42,017 Share based compensation 784 2,135 Abandonment obligation 212 445 Derivative instruments 191 - Accrued liabilities 43 - Debt conversion costs - 482 Other 9 28 Total deferred tax asset 16,892 50,263 Valuation allowance (16,624) (50,263)Deferred tax asset, net of valuation allowance $268 $- Deferred tax liabilities: Oil and natural gas properties and equipment $268 $- Total deferred tax liability 268 - Net deferred tax asset (liability) $- $- 121  Reconciliation of the Company’s effective tax rate to the expected U.S. federal tax rate is: Year EndedDecember 31, 2017 2016 Effective federal tax rate 34.00% 34.00%State tax rate, net of federal benefit 1.11% 1.42%Effect of the Tax Cuts and Jobs Act -11.22% -%Change in fair value derivative liability -2.59% -1.32%Debt discount amortization -3.51% -4.11%Share based compensation differences and forfeitures 0.91% -2.28%Change in rate -0.05% -5.90%Other permanent differences -4.61% -12.29%NOL true-up - §382 limitation -47.22% -0.00%Other -6.47% -0.10%Valuation allowance 39.65% -9.42%Net -% -% As of December 31, 2017 and 2016, the Company had net operating loss carry-forwards for federal income tax purposes of approximately $70.1million and $118.6 million, respectively, available to offset future taxable income. To the extent not utilized, the net operating loss carry-forwards as ofDecember 31, 2017 will expire beginning in 2027 through 2036. A full Section 382 analysis was prepared in 2017 resulting in a true-up of the Company’snet operating losses subject to limitation under Section 382 from $118.6 million to $9.1 million as of December 31, 2016. The net operating loss of $70.1million as of December 31, 2017 could be subject to Section 382 limitation due to potential ownership changes of more than 50% which may have occurredduring the current tax year. In assessing the need for a valuation allowance on the Company’s deferred tax assets, management considers whether it is more likely than not thatsome 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 issufficient to reverse existing temporary differences that give rise to deferred tax assets, as well as whether future taxable income is sufficient to utilize netoperating 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 inavailable carryback years, and no tax planning strategies contemplated to realize the valued deferred tax assets. As of December 31, 2017, and 2016, management assessed the available positive and negative evidence to estimate if sufficient future taxable incomewould 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 realizedin the near future. Therefore, the Company recorded a full valuation allowance of approximately $16.6 million and $50.0 million on its deferred tax assets asof December 31, 2017 and 2016, respectively. The New Tax Cuts and Jobs Act (the “Act”) was signed into law on December 22, 2017. The Act makes broad and complex changes to the U.S. taxcode applicable to certain items in 2017 as well as those applicable to 2018 and subsequent years. ASC 740 requires the recognition of the tax effects of the Act for annual periods that include December 22, 2017. At December 31, 2017, the Companyhas made reasonable estimates of the effects on its existing deferred tax balances. The Company has remeasured certain federal deferred tax assets andliabilities based on the rates at which they are expected to reverse in the future, which is generally twenty one percent. The provisional amount recognizedrelated to the remeasurement of its federal deferred tax balance was $9.5 million, which was subject to a valuation allowance at December 31, 2017. The Company will continue to analyze the Act and future IRS regulations, refine its calculations, gain a more thorough understanding of howindividual states are implementing this new law and evaluate other provisions of the tax reform. This further analysis could potentially affect themeasurement of deferred tax balances or potentially give rise to new deferred tax amounts. NOTE 11 - STOCKHOLDERS’ EQUITY Authorized Shares of Common Stock On May 2, 2017, the Board of Directors authorized the amendment of the Company’s certificate of incorporation to increase the number ofauthorized shares of common stock by 50 million from the prior level of 100 million. This amendment was also approved by the Company’s stockholders onJuly 13, 2017. There was no change in the stated par value of the shares as a result of this amendment. Conditionally Redeemable 6% Preferred Stock In August 2014, the Company designated 2,000 shares of its authorized preferred stock as Conditionally Redeemable 6% Preferred Stock, or (the“Redeemable Preferred”). All 2,000 shares of Redeemable Preferred were issued in September 2014, pursuant to the Settlement Agreement with Hexagon,LLC (f/k/a Hexagon Investments, LLC) (“Hexagon”). The Redeemable Preferred had a par value and stated value $1,000 per share. 122  Effective as of April 24, 2017, the Company redeemed, in full, the Company’s Redeemable Preferred pursuant to a Settlement and ReleaseAgreement (the “Settlement Agreement”) between the Company and Hexagon, which sets forth the terms of the redemption. In addition, the SettlementAgreement resolves certain other issues related to liability reimbursements on certain oil and natural gas properties that had previously been alleged byHexagon. Series B 6% Convertible Preferred Stock On June 15, 2016, the Company entered into a purchase agreement for the private placement of 20,000 shares of its Series B Preferred Stock, alongwith detachable warrants to purchase up to 9,090,926 shares of Common Stock, at an exercise price of $2.50 per share, for aggregate gross proceeds of $20million. Each share of Series B Preferred Stock was convertible, at the option of the holder, subject to adjustment under certain circumstances into shares ofCommon Stock of the Company at a conversion price of $1.10. The Series B Preferred Stock is convertible at any time, subject to certain conditions, at theoption of the holders, or at the Company’s discretion when the Company’s Common Stock trades above $10.00 (subject to any reverse or forward stock splitsand the like) for ten consecutive days. In addition, the Company has the right to redeem the shares of Series B Preferred Stock, along with any accrued andunpaid dividends, at any time, subject to certain conditions as set forth in the Certificate of Designation. The holders of the Series B Preferred Stock areentitled to receive a dividend payable (subject to certain conditions as set forth in the Certificate of Designation), in cash or shares of Common Stock of theCompany, at the election of the Company, at a rate of 6% per annum. The Series B Preferred Stock was classified as equity based on the following criteria: i) the redemption of the instrument at the control of theCompany; ii) the instrument is convertible into a fixed amount of shares at a conversion price of $1.10; iii) the instrument is closely related to the underlyingCompany’s Common Stock; iv) the conversion option is indexed to the Company’s stock; v) the conversion option cannot be settled in cash and only can beredeemed at the discretion of the Company; and vi) the Series B Preferred Stock is not considered convertible debt. Shares of the Series B Preferred Stock and related warrants were valued using the relative fair value method. The Company determined thetransaction created a beneficial conversion feature of $7.9 million, which was expensed immediately and was calculated by taking the net proceeds ofapproximately $15.2 million and valuing the warrants as of June 15, 2016, utilizing a Black-Scholes Merton option model. The inputs for the pricing modelare: $1.20 market price per share; exercise price of $2.50 per share; contractual life of 2 years; volatility of 238%; and risk-free rate of 0.78%. As of December31, 2016, the total value of the issued and outstanding shares of Series B Preferred Stock was approximately $13.4 million. As of December 31, 2017, allshares of Series B Preferred Stock were fully converted into the Company’s shares of common stock. On April 25, 2017, the Company entered into a Series B 6.0% Convertible Preferred Stock Conversion Agreement (the “Conversion Agreement”),with all of the holders of the outstanding Series B Preferred Stock (the “Series B Holders”) to convert any outstanding shares of Series B Preferred Stockincluding an increase in the stated value to reflect dividends that would have accrued through December 31, 2017 into approximately 14.3 million shares ofcommon stock. On the same date, the Series B Holders further agreed to adopt the Amended and Restated Certificate of Designation of Preferences, Rightsand Limitations of Series B 6% Convertible Preferred Stock (“A&R COD”) in order to remove certain restrictions contained therein with respect to beneficialownership limitations, a condition of the Conversion Agreement. The A&R COD became effective on April 26, 2017, resulting in the automatic conversionof all outstanding Series B Preferred Stock. As a result of the automatic conversion, the Company recognized $4.6 million of dividends and deemeddividends on the Series B Preferred Stock during the year ended December 31, 2017. The Conversion Agreement contained customary representations and warranties by the Series B Holders and other agreements and obligations of theparties. Private Placement On February 28, 2017, the Company entered into a Securities Subscription Agreement (the “Subscription Agreement”) with certain institutional andaccredited investors in connection with a private placement (the “March 2017 Private Placement”) to sell 5.2 million units, consisting of approximately 5.2million shares of common stock and warrants to purchase approximately an additional 2.6 million shares of common stock. Each unit consisted of one shareof common stock and a warrant to purchase 0.50 shares of common stock, at a price per unit of $3.85. Each warrant has an exercise price of $4.50 and may besubject to redemption by the Company, upon prior written notice, if the price of the Company’s common stock closes at or above $6.30 for twenty tradingdays during a consecutive thirty trading day period. As of December 31, 2017, the Company received aggregate gross proceeds of $20.0 million and issued5,194,821 shares of common stock and warrants to purchase 2,597,420 shares of common stock. 123  Warrants The following table provides a summary of warrant activity for the years ended December 31, 2017 and 2016: Warrants Weighted- Average ExercisePrice Expiration DateOutstanding at January 1, 2016 2,478,316 $14.80 12/31/2018 to 02/04/2020Warrants issued to Series B Preferred Stock 9,090,926 1.54 06/22/2018Warrants issued for fees 1,272,727 1.30 06/22/2018Warrants issued with Convertible Notes 1,145,238 2.47 12/31/2018 to 05/04/2019Warrants issued to amend Convertible Notes 1,648,267 2.50 08/03/2019Additional warrants issued to Bristol 541,026 3.12 05/29/2017Warrants issued to SOS in connection with the Merger 200,000 2.50 06/22/2018Exercised, forfeited, or expired (460,989) (34.74) Outstanding at December 31, 2016 15,915,511 $3.34 Warrants issued in connection with private placement 2,597,420 4.50 03/06/2022Warrants issued to Heartland 160,714 3.50 01/08/2020Exercised (6,144,176) (0.30) Forfeited or expired (646,669) (25.70) Outstanding at December 31, 2017 11,882,800 $3.46 The aggregate intrinsic value associated with outstanding warrants was approximately $19.6 million and $18.3 million at December 31, 2017 and2016, respectively, based on the Company’s closing Common Stock price of $5.11 and $3.10, respectively. The weighted average remaining contractual lifewas 1.66 years and 1.64 years as of December 31, 2017 and 2016. During the year ended December 31, 2016, the Company issued approximately 13.2 million warrants to purchase shares of Common Stock toPurchasers of the Convertible Notes, Purchasers of Series B Preferred Stock and placement agent fees in connection with the Series B Preferred Stock Offering.The Company also issued a warrant to purchase 200,000 shares of Common Stock to Brushy's subordinated lender in exchange for extinguishment of certaindebt owed by Brushy. In connection with the May 2016 Financing, in exchange for additional consideration in the form of participation in the May 2016 ConvertibleNotes offering, certain Purchasers received amended and restated warrants to purchase approximately 620,000 shares of Common Stock, which reduced theexercise price of the warrants issued to these Purchasers in each of the prior two Convertible Notes issuances from $2.50 to $0.10, 80,000 of which weresubsequently exercised. Additionally, during the year ended June 30, 2016, in exchange for several offers to immediately exercise a portion of eachinvestor’s outstanding warrants issued between 2013 and 2014, the Company reduced the exercise price on warrants to purchase a total of 416,454 shares ofCommon Stock ranging from $42.50 to $25.00 per share to $0.10 per share, of which a total of 315,990 were subsequently exercised, resulting in the issuanceof an aggregate amount of 300,706 shares of Common Stock due to certain cashless exercises. The Company accounted for the reduction in the exercise priceas an inducement expense and recognized $1.7 million in other income (expense). Additionally, in connection with the Credit and Guarantee Agreement, as partial consideration to the Lenders, the Company also amended certainwarrants issued in the Series B private placement held by the Lenders to purchase up to an aggregate amount of approximately 3.5 million shares of CommonStock, such that the exercise price per share was lowered from $2.50 to $0.01 on such warrants. The number of warrants amended for each Lender was basedon the amount of each Lender’s respective participation in the initial Term Loan relative to the amount invested in the Series B private placement. All of theamended warrants are exercisable through June 22, 2017, subject to certain conditions. As of December 31, 2017, these warrants with an exercise price of$0.01 per share were fully exercised, resulting in the issuance of an aggregate of 4,441,836 shares of Common Stock. 124  NOTE 12 - 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”). On November 3, 2016 the Company’s stockholders voted to increase number of shares of Common Stock authorized for issuance under the2016 Plan to 10 million. At the 2017 Annual Meeting of Stockholders of the Company held on July 13, 2017, the Company’s stockholders approved thesecond amendment to its 2016 Plan to increase the number of shares of common stock available for grant under the 2016 Plan from 10 million to 13 millionshares. As of December 31, 2017, 607,186 shares of the 13 million shares of the Company’s common stock authorized for awards under the 2016 Planremained available for future issuances. The Company generally issues new shares to satisfy awards under employee share-based payment plans. 2017 2016 (in thousands) StockOptions RestrictedStock Total StockOptions RestrictedStock Total Stock-based compensation expensed $7,255 $14,283 $21,538 $4,475 $2,398 $6,873 Unamortized stock-based compensation costs $4,267 $8,669 $12,936 $5,200 $1,249 $6,449 Weighted average amortization period remaining(years) 0.70 0.82 1.68 1.45 Summary of non-cash compensation in the Statement of Changes in Stockholders’ Equity: December 31, 2017 2016 (In thousands) Common stock issued for directors’ fees $- $85 Common stock issued for officer and Board compensation - 120 Stock based compensation for issuance of stock options 7,255 4,475 Stock based compensation for issuance of restricted stock 14,186 2,398 Common stock issued for professional services 97 - Total non-cash compensation in the Statement of Changes in Stockholders’ Equity $21,538 $7,078 Restricted Stock Employees may be granted restricted stock in the form of restricted stock awards or restricted stock units. Restricted stock is subject to forfeiturerestrictions and cannot be sold, transferred, or disposed of during the restriction period. The holders of restricted stock awards have the same rights as astockholder of the Company with respect to such shares, including the right to vote and receive dividends or other distributions paid with respect to theshares. A restricted stock unit is equivalent to a restricted stock award except that unit holders do not have the right to vote. Restricted stock vests overservice periods ranging from the date of grant generally up to two or three years. A summary of restricted stock grant activity pursuant to the 2016 Plan for the years ended December 31, 2017 and 2016 is presented below: Number of Shares Weighted Average Grant Date Price Outstanding at January 1, 2016 - $- Granted 1,780,052 1.54 Vested and issued (711,747) (1.75)Forfeited - - Outstanding at December 31, 2016 1,068,305 $1.55 Granted 4,266,345 4.84 Vested and issued (2,162,915) (3.78)Forfeited (696,469) (4.26)Outstanding at December 31, 2017 2,475,266 $4.22 125  A summary of restricted stock unit grant activity pursuant to the 2012 Plan for the years ended December 31, 2017 and 2016 is presented below. TheCompany no longer grants any awards under previous plans. Number of Shares Weighted Average Grant Date Price Outstanding at January 1, 2016 186,900 $12.29 Granted - - Vested and issued (10,834) (18.75)Forfeited (26,482) (16.15)Outstanding at December 31, 2016 149,584 10.56 Granted - - Vested and issued (139,585) (4.77)Forfeited - - Outstanding at December 31, 2017 $9,999 $6.57 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 greaterthan, 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 andterminate at the earlier of the date of exercise or ten years from the date of grant. During the year ended December 31, 2017, the Company received cashproceeds of approximately $0.5 million from the exercise of vested stock options. The fair value of stock option awards is determined using the Black-Sholes-Merton option-pricing model based on several assumptions. Theseassumptions are based on management’s best estimate at the time of grant. The Company used the following weighted average of each assumption based onthe grants in each fiscal year: 2017 2016 Expected Term in Years 2 years 4 years Expected Volatility 101% 152%Expected Dividends 0% 0%Risk-Free Interest Rate 1.38% 1.08% The Company estimates expected volatility based on an analysis of its historical stock prices since the IPO date in 2007. The Company estimates theexpected term of its option awards based on the vesting period. The Company uses this method to provide a reasonable basis for estimating its expected termdue to the lack of sufficient historical employee exercise data on stock option awards. A summary of stock option activity for the years ended December 31, 2017 and 2016 is presented below: Stock Options Outstanding and Exercisable Number of Options Weighted Average Exercise Price Number of Options Vested/ Exercisable Weighted Average Remaining Contractual Life (Years) Outstanding at January 1, 2016 608,333 $14.60 296,666 4.1 Granted 5,683,500 2.14 Forfeited or cancelled (335,000) (5.34) Outstanding at December 31, 2016 5,956,833 $2.04 2,208,757 9.6 Granted 3,260,000 4.74 Exercised (304,896) (2.01) Forfeited or cancelled (1,606,937) (3.06) Outstanding at December 31, 2017 7,305,000 $3.74 3,534,484 8.9 During the year ended December 31, 2017, options to purchase 3,260,000 shares of the Company’s common stock were granted under the 2016 Plan.The weighted average fair value of these options was $4.74. The options to purchase 3,260,000 shares of the Company’s common stock include the following: (i)Options granted to employees of the Company to purchase 2,510,000 shares of the Company’s common stock during the year endedDecember 31, 2017; and (ii)On June 16, 2017, the Company cancelled 250,000 of the options granted in June 2016 and all of the 500,000 options granted in December2016 to an executive due to option grants that were in excess of the 2016 Plan individual limits. Additional options to purchase 750,000shares of the Company’s common stock, 389,657 restricted shares and cash in an amount of $87,922 were awarded and paid to theexecutive to replace the cancelled option grants. The Company accounted for the replacement award as a modification of the terms of thecancelled award in accordance with ASC 718-20-35-8 “Cancellation of an award accompanied by the concurrent grant of (or offer to grant)a replacement award or other valuation consideration.” As a result, during the year ended December 31, 2017, the Company recordedincremental compensation of approximately $1.6 million which was the excess of the fair value of the vested replacement award over thefair value of the cancelled awards. The incremental fair value of the unvested replacement awards was to be amortized over the remainingvesting period. As a result of the resignation of the executive in August 2017, the remaining unvested replacement awards were fullyvested and expensed totaling approximately $3.2 million during the year ended December 31, 2017. 126  The outstanding options had an intrinsic value of approximately $10.1 million and $12.3 million at December 31, 2017 and 2016, respectively. NOTE 13 - Supplemental Cash Flow Information The following table summarizes information on non-cash investing and financing activities for the years ended December 31, 2017 and 2016 (inthousands): 2017 2016 Non-cash investing and financing activities excluded from the statement of cash flows: Conversion of Series B Preferred Stock and accrued dividends to common stock $14,865 $- Common stock issued for Brushy’s common stock - 7,111 Common stock issued for Series A Preferred Stock and accrued dividends - 7,682 Common stock issued for convertible notes and accrued interest - 14,872 Common stock issued for Series B Preferred Stock and accrued dividends - 3,229 Warrants issued for fees associated with Series B Preferred Stock issuance - 1,591 Warrants issued for Series B Preferred Stock issuance and recorded as a deemed dividend - 7,879 Fair value of warrants issued for financing costs and debt discount 1,031 2,192 Common stock issued for commitment fees associated with Private Placement 250 - Cashless exercise of warrants 370 - Issuance of common stock for drilling services 97 - Accrued drilling costs 3,615 1,331 NOTE 14 - SUBSEQUENT EVENTS Purchase and Sale Agreement On January 30, 2018, the Company entered into a Purchase and Sale Agreement (the “Purchase and Sale Agreement”) by and between the Companyand OneEnergy Partners Operating, LLC (“OEP”), pursuant to which the Company agreed to purchase from OEP, and OEP agreed to sell to the Company,certain oil and natural gas properties and related assets for a purchase price of $70 million, subject to customary purchase price adjustments (the“Acquisition”). The unadjusted purchase price for the Acquisition will consist of $40 million in cash and $30 million in shares of the Company’s Common Stock,valued at a price per share equal to (i) the volume-weighted average trading price of the Common Stock on the NYSE American for the 20 consecutivetrading days ending on and including the first trading day preceding the closing date of the Acquisition multiplied by (ii) 1.05, but in no event may suchprice be less than $4.25 or greater than $5.25. The Company intends to fund the cash portion of the purchase price with a portion of the net proceeds from thetransaction described under “Preferred Stock Issuance” below. The properties to be acquired by the Company pursuant to the Purchase and Sale Agreement consists of leasehold acreage in the Delaware Basin inLea County, New Mexico. The Purchase and Sale Agreement contains customary terms and conditions, including title and environmental due diligence provisions,representations and warranties, covenants and indemnification provisions. The Purchase and Sale Agreement also includes registration rights provisionspursuant to which, among other matters, (i) the Company will be required to file with the Securities and Exchange Commission (the “SEC ”) a registrationstatement under the Securities Act of 1933, as amended (the “Securities Act ”), registering for resale the shares of Common Stock issued to OEP pursuant tothe Purchase and Sale Agreement and (ii) OEP will have piggyback rights to include shares of Common Stock in certain underwritten offerings. The Company expects to close the Acquisition in March 2018, subject to the satisfaction of customary closing conditions. 127  Preferred Stock Issuance On January 30, 2018, the Company entered into a Securities Purchase Agreement (the “Securities Purchase Agreement ”) by and among theCompany and certain private funds affiliated with Värde Partners, Inc. (the “Purchasers ”), pursuant to which the Company agreed to issue and sell to thePurchasers, and the Purchasers agreed to purchase from the Company, 100,000 shares of a newly created series of preferred stock of the Company, designatedas “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 SecondLien Credit Agreement (as defined above). Closing of the issuance and sale of the shares of Series C Preferred Stock pursuant to the Securities Purchase Agreement occurred on January 31,2018. The terms of the Series C Preferred Stock are set forth in the Certificate of Designation for the Series C Preferred Stock (the “Certificate ofDesignation”) filed by the Company with the Secretary of State of the State of Nevada on January 31, 2018. The following is a description of the materialterms of the Series C Preferred Stock and the Securities Purchase Agreement. Ranking. The Series C Preferred Stock ranks senior to the Common Stock with respect to dividends and rights on the liquidation, dissolution orwinding up of the Company. Stated Value. The Series C Preferred Stock has a per share stated value of $1,000, subject to increase in connection with the payment of dividends inkind as described below (the “Stated Value”). Dividends. Holders of shares of Series C Preferred Stock will be entitled to receive cumulative preferential dividends, payable and compoundedquarterly 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 untilApril 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. TheCompany expects to pay dividends in kind for the foreseeable future. In addition to these preferential dividends, holders of shares of Series C Preferred Stockwill be entitled to participate in any dividends paid on the Common Stock on an as-converted basis. Optional Redemption. The Company has the right to redeem the Series C Preferred Stock, in whole or in part at any time (subject to certainlimitations 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 Companyin respect thereof (the “Optional Redemption Amount”). The Series C Preferred Stock is perpetual and is not mandatorily redeemable at the option of theholders, except upon the occurrence of a Change of Control (as defined in the Certificate of Designation) as described below. Conversion. Each share of Series C Preferred Stock is convertible at any time at the option of the holder into a number of shares of Common Stockequal to (i) the applicable Optional Redemption Amount divided by (ii) a conversion price of $6.15, subject to adjustment (the “Conversion Price”). TheConversion Price will be subject to proportionate adjustment in connection with stock splits and combinations, dividends paid in stock and similar eventsaffecting the outstanding Common Stock. Additionally, the Conversion Price will be adjusted, based on a broad-based weighted average formula, if theCompany issues, or is deemed to issue, additional shares of Common Stock for consideration per share that is less than the lesser of (i) $5.25 and (ii) theConversion Price then in effect, subject to certain exceptions and to the Share Cap (as defined below). The Company has the right to force the conversion of any or all of the outstanding shares of Series C Preferred Stock if (i) the volume-weightedaverage price per share of the Common Stock on the principal exchange on which it is then traded has been at least 140% of the Conversion Price then ineffect for at least 20 of the 30 consecutive trading days immediately preceding the exercise by the Company of the forced conversion right and (ii) certaintrading and other conditions are satisfied. To comply with rules of the NYSE American, the Certificate of Designation provides that the number of shares of Common Stock issuable onconversion of a share of Series C Preferred Stock may not exceed (i) the Stated Value divided by (ii) $4.42 (which was the closing price of the Common Stockon the NYSE American on January 30, 2018) (the “Share Cap”) prior to approval by the Company’s stockholders of the issuance of shares of Common Stockin excess of the Share Cap upon conversion of shares of Series C Preferred Stock. The Securities Purchase Agreement requires the Company to seek suchstockholder approval at its next special or annual meeting of stockholders, which must occur within six months after the initial issuance of the Series CPreferred Stock. The Company intends to seek such stockholders approval at its 2018 annual meeting of stockholders. 128  Change of Control. Upon the occurrence of a Change of Control (as defined in the Certificate of Designation), each holder of shares of Series CPreferred Stock will have the option to: ·cause the Company to redeem all of such holder’s shares of Series C Preferred Stock for cash in an amount per share equal to (i) the OptionalRedemption Amount plus (ii) 2.5% of the Stated Value, in each case as in effect immediately prior to the Change of Control; ·convert all of such holder’s shares of Series C Preferred Stock into the number of shares of Common Stock into which such shares are convertibleimmediately prior to the Change of Control; or ·continue to hold such holder’s shares of Series C Preferred Stock, subject to any adjustments to the Conversion Price or the number and kind ofsecurities or other property issuable upon conversion resulting from the Change of Control and to the Company’s or its successor’s optionalredemption rights described above. Liquidation Preference. Upon any liquidation, dissolution or winding up of the Company, holders of shares of Series C Preferred Stock will beentitled 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, anamount per share of Series C Preferred Stock equal to the greater of (i) the Optional Redemption Amount then in effect and (ii) the amount such holder wouldreceive in respect of the number of shares of Common Stock into which a share of Series C Preferred Stock is then convertible. Board Designation Rights. The Certificate of Designation provides that holders of shares of Series C Preferred Stock will have the right, votingseparately as a class, to designate (i) two members of the Company’s board of directors (the “Board”) for as long as the shares of Common Stock issuable onconversion of the outstanding shares of Series C Preferred Stock represent at least 15% of the outstanding shares of Common Stock (giving effect toconversion of all outstanding shares of Series C Preferred Stock) and (ii) one member of the Board for as long as the shares of Common Stock issuable onconversion of the outstanding shares of Series C Preferred Stock represent at least 7.5% of the outstanding shares of Common Stock (giving effect toconversion of all outstanding shares of Series C Preferred Stock). The Securities Purchase Agreement separately grants to the Purchasers substantially identical rights to appoint members of the Board as long as thePurchasers and their affiliates beneficially own (as defined in Rule 13d-3 under the Securities Exchange Act of 1934, as amended) shares of Common Stockissued or issuable upon conversion of shares of Series C Preferred Stock representing the 15% and 7.5% thresholds of the outstanding Common Stockdescribed above. However, the number of members of the Board the Purchasers have the right to designate under the Securities Purchase Agreement will bereduced by the number of directors holders of shares of Series C Preferred Stock have the right to appoint under the Certificate of Designation. The Board members designated by holders of shares of Series C Preferred Stock pursuant to the Certificate of Designation or by the Purchaserspursuant to the Securities Purchase Agreement must be reasonably acceptable to the Board and its Nominating and Corporate Governance Committee, actingin good faith, but any investment professional of Värde Partners, Inc. or its affiliates will be deemed to be reasonably acceptable. In addition, such Boarddesignees must satisfy applicable SEC and stock exchange requirements and comply with the Company’s corporate governance guidelines. In accordance with the Company’s bylaws, the Board has increased the number of directors constituting the entire Board from seven to nine to allowfor the appointment of the Board members designated by the holders of shares of Series C Preferred Stock. The Company will be required to appoint the twoBoard members initially designated by the holders of shares of Series C Preferred Stock within ten business days after notice to the Company from the holdersof the identity of such designees, subject to confirmation that such designees meet the qualifications described above. Voting Rights; Negative Covenants. In addition to the Board designation rights described above, holders of shares of Series C Preferred Stock will beentitled to vote with the holders of shares of Common Stock, as a single class, on all matters submitted for a vote of holders of shares of Common Stock.When voting together with the Common Stock, each share of Series C Preferred Stock will entitle the holder to a number of votes equal to (i) the Stated Valueas of the applicable record date or other determination date divided by (ii) $4.42 (the closing price of the Common Stock on the NYSE American on January30, 2018). The Certificate of Designation provides that, as long as any shares of Series C Preferred Stock are outstanding, the Company may not, without theprior affirmative vote or prior written consent of the holders of a majority of the outstanding shares of Series C Preferred Stock: 129  ·amend the Company’s articles of incorporation or bylaws in any manner that materially and adversely affects any rights, preferences, privileges orvoting powers of the Series C Preferred Stock or holders of shares of Series C Preferred Stock; ·issue, authorize or create, or increase the issued or authorized amount of, the Series C Preferred Stock, any class or series of capital stock rankingsenior to or in parity with the Series C Preferred Stock, or any security convertible into or evidencing the right to purchase any shares of Series CPreferred Stock or any such senior or parity stock, other than equity, the proceeds of which, are used to immediately redeem all of the outstandingshares of Series C Preferred Stock 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 toredeem or repurchase, shares of Common Stock or any other shares of capital stock of the Company ranking junior to the Series C Preferred Stock,subject to certain exceptions; ·authorize, issue or transfer, or permit any of its controlled subsidiaries to authorize, issue or transfer, any equity (including any obligation or securityconvertible into, exchangeable for or evidencing the right to purchase any such equity) in any subsidiary of the Company other than (i) equityissued or transferred to the Company or another wholly-owned subsidiary of the Company or (ii) equity, the proceeds of which, are used toimmediately redeem all of the outstanding shares of Series C Preferred Stock pursuant to the Company’s optional redemption rights describedabove; or ·subject to certain exceptions, modify the number of directors constituting the entire Board at any time when holders of shares of Series C PreferredStock have the right to designate a member of the Board. The Certificate of Designation further provides that, as long as shares of Series C Preferred Stock having an aggregate Optional Redemption Amountof at least $50,000,000 are outstanding, the Company may not, and may not permit any of its controlled subsidiaries to, without the prior affirmative vote orprior written consent of the holders of a majority of the outstanding shares of Series C 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 Series C Preferred Stock under any credit facility, indenture or other similar instrument of the Company that would be more restrictive onthe payment of dividends on, or redemption of, shares of Series C Preferred Stock than those existing as of the date on which shares of Series CPreferred 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 gasproperties outside the Permian Basin; or ·enter into certain transactions with affiliates of the Company unless made on an arm’s-length basis and approved by a majority of the disinterestedmembers of the Board. Transfer Restrictions. The Certificate of Designation provides that shares of Series C Preferred Stock and shares of Common Stock issued onconversion of shares of Series C Preferred Stock may not be transferred by the holder of such shares, other than to an affiliate of such holder, prior to July 31,2018. On and after July 31, 2018, such shares will be freely transferable, subject to applicable securities laws. Standstill. The Securities Purchase Agreement includes a customary standstill provision pursuant to which the Purchasers agreed that they will not,directly or indirectly, take certain actions with respect to the Company or its securities until the earlier of (i) the date on which the Purchasers and theiraffiliates are no longer entitled to designate any member of the Board pursuant to the Certificate of Designation or the Securities Purchase Agreement and (ii)the failure of the Company to pay dividends on the Series C Preferred Stock in full in cash on any dividend payment date occurring after April 26, 2021. Other Terms. The Securities Purchase Agreement contains other terms, including representations, warranties and covenants, that are customary for atransaction of this sort. 130  Registration Rights Agreement On January 31, 2018, in connection with the closing of the issuance of shares of Series C Preferred Stock pursuant to the Securities PurchaseAgreement, the Company entered into a Registration Rights Agreement (the “Registration Rights Agreement ”) by and between the Company and thePurchasers pursuant to which, among other matters, the Company will be required to file with the SEC a registration statement under the Securities Actregistering for resale the shares of Common Stock issuable upon conversion of shares of Series C Preferred Stock. The Registration Rights Agreement alsogrants to the Purchasers demand and piggyback rights with respect to certain underwritten offerings of Common Stock and contains customary covenants andindemnification and contribution provisions. Riverstone First Lien Credit Agreement On January 30, 2018, the Company entered into an Amended and Restated Senior Secured Term Loan Credit Agreement (the “Riverstone First LienCredit Agreement”) by and among the Company, the subsidiaries of the Company party thereto as guarantors, Riverstone Credit Management LLC, asadministrative agent and collateral agent, and the lenders party thereto. Effective at closing under the Riverstone First Lien Credit Agreement, whichoccurred on January 31, 2018, the Riverstone First Lien Credit Agreement amended and restated the First Lien Credit Agreement. Pursuant to the Riverstone First Lien Credit Agreement, the lenders thereunder agreed to make term loans to the Company in the aggregate principalamount of $50 million (the “Riverstone First Lien Loans”), all of which were funded in full at closing at an original issue discount of 1.0% of the principalamount. The Riverstone First Lien Credit Agreement provides the potential for additional term loans of up to $30 million, as requested by the Company andsubject to certain conditions, which additional loans were uncommitted at closing. The Company used approximately $31.5 million of the proceeds of the Riverstone First Lien Loans to repay in full its obligations under and retirethe First Lien Credit Agreement during the first quarter of 2018. Amendment to Second Lien Credit Agreement On January 31, 2018, the Company entered into a fourth amendment to the Second Lien Credit Agreement, among the Company, the guarantorsparty thereto, the lenders party thereto, including Värde Partners, Inc., as lead lender, and Wilmington Trust, National Association, as administrative agent(“Amendment No. 4 to the Second Lien Credit Agreement”). The purpose of Amendment No. 4 to the Second Lien Credit Agreement was to, among other matters: ·permit the Company to enter the Riverstone First Lien Credit Agreement and incur the Riverstone First Lien Loans and related liens; ·permit the Company to issue the Series C Preferred Stock; and ·after the issuance of the Series C Preferred Stock pursuant to the Securities Purchase Agreement, reduce from two to one the maximum number ofmembers of the Board the lenders under the Second Lien Credit Agreement will have the right to appoint following the conversion of theconvertible loans under the Second Lien Credit Agreement. Amendments to Riverstone First Lien Credit Agreement and Second Lien Credit Agreement On February 20, 2018, Lilis Energy, Inc. (the “Company”) entered into the following amendments to its existing credit agreements (collectively, the“Amendments”): (i) Amendment No. 1 to the Riverstone First Lien Credit Agreement and (ii) Amendment No. 5 to the Second Lien Credit Agreement.Pursuant to the Amendments and a consent letter received from the Purchasers , in their capacity as the holders of all of the issued and outstanding shares ofSeries C Preferred Stock, the Company has been granted the right to repurchase shares of its Common Stock for an aggregate purchase price up to$10,000,000 (subject to certain exceptions and conditions). The commencement of any repurchase of shares of Common Stock is subject to compliance with applicable law, Board approval, and marketconditions. Departure of Executive Officers On February 16, 2018, Ariella Fuchs ceased serving as the Company's Executive Vice President, General Counsel and Secretary. The Companyentered into an agreement with Ms. Fuchs pursuant to which she will receive severance and other consideration pursuant to the terms of her employmentagreement and the accelerated vesting of 247,500 stock options and 198,000 shares of restricted stock under stock award agreements plus additional nominalconsideration. On March 6, 2018, Brennan Short ceased serving as our Chief Operating Officer. His responsibilities have been assumed by our current managementand our existing consultants. 131  Lilis Energy, Inc. and SubsidiariesSupplementary 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 December 31, 2017 2016 (In thousands) Acquisition costs: Unproved properties $78,111 $4,798 Proved properties 2,245 3,346 Exploration costs 42,033 7,136 Development costs 28,113 1,478 Total $150,502 $16,758 132  Reserve Quantity Information The following table provides a roll forward of the total proved reserves for the years ended December 31, 2017 and 2016, as well as proveddeveloped and proved undeveloped reserves at the beginning and end of each respective year: Crude Oil(Bbls) Natural Gas(Mcf) NGLs(Mcf) January 1, 2016 33,430 141,450 - Extensions and discoveries - - - Purchase of reserves 413,780 2,333,200 - Sale of reserves - - - Revisions of previous estimates 164,583 1,729,499 14,566 Production (61,088) (332,643) (11,355)December 31, 2016 550,705 3,871,506 3,211 Extensions and discoveries 6,791,945 14,438,471 1,455,620 Purchase of reserves - - - Sale of reserves (92,293) (364,712) (3,211)Revisions of previous estimates 292,975 (1,109,174) 222,825 Production (371,993) (776,165) (73,875)December 31, 2017 7,171,339 16,059,926 1,604,570 Proved Developed Reserves, included above: Balance, January 1, 2016 33,430 141,450 - Balance, December 31, 2016 550,705 3,871,506 3,211 Balance, December 31, 2017 2,531,397 6,594,446 644,102 Proved Undeveloped Reserves, included above: Balance, January 1, 2016 - - - Balance, December 31, 2016 - - - Balance, December 31, 2017 4,639,942 9,465,480 960,468 Extensions and discoveries of 10,653 MBOE during the year ended December 31, 2017, resulted primarily from the drilling of new wells during theyear and from new proved undeveloped locations added during the year. 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 oiland natural gas reserves of the properties. An estimate of fair value would take into account, among other things, the recovery of reserves not presentlyclassified 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, 2017 and 2016 are based on the unweightedarithmetic average first-day-of-the-month price for the preceding 12-month period. Estimated future production of proved reserves and estimated futureproduction and development costs of proved reserves are based on current costs and economic conditions which are held constant throughout the life of theproperties. All wellhead prices are held flat over the forecast period for all reserve categories. The estimated future net cash flows are then discounted at a rateof 10% 133  The standardized measure of discounted future net cash flows relating to proved oil, natural gas and NGL reserves is as follows: As of December 31, 2017 2016 (In thousands) Future cash inflows $397,531 $28,514 Future production costs (151,456) (15,939)Future development costs (113,727) (3,388)Future income tax expense - - Future net cash flows 132,348 9,187 10% discount to reflect timing of cash flows (63,536) (2,531)Total $68,812 $6,656 In the foregoing determination of future cash inflows, sales prices used for oil, natural gas and NGLs for December 31, 2017 and 2016, wereestimated using the average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-month price for eachmonth. Prices were adjusted by lease for quality, transportation fees and regional price differentials. Future costs of developing and producing the proved gasand oil reserves reported at the end of each year shown were based on costs determined at each such year-end, assuming the continuation of existingeconomic conditions. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which areinherently 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 thedeterminations 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, 2017 2016 (In thousands) Standardized measure of discounted future net cash flows, beginning of the year $6,656 $608 Sales of oil and natural gas, net of production costs and taxes (13,402) (1,989)Extensions and discoveries, net of future development costs 57,163 - Purchase of minerals in place - 7,919 Sales of minerals in place (1,296) - Net changes in prices and production costs 8,311 (309)Previously estimated development costs incurred during the period 4,968 (8,942)Changes in estimated future development costs (1,580) 4,617 Revisions of previous quantity estimates 1,683 1,087 Net change in income taxes - - Accretion of discount 666 35 Net changes in timing of production and other 5,643 3,630 Standardized measure of discounted future net cash flows at the end of the year $68,812 $6,656 134  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 onits behalf by the undersigned, thereunto duly authorized. LILIS ENERGY, INC. Date: March 9, 2018By:/s/ James L. Linville James L. Linville Chief Executive Officer(Authorized Signatory) 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 theregistrant in the capacities and on the dates indicated. Signature Title Date /s/ James L. Linville Chief Executive Officer, Director March 9, 2018James L. Linville (Principal Executive Officer) /s/ Joseph C. Daches Executive Vice President and Chief Financial Officer March 9, 2018Joseph C. Daches (Principal Financial and Accounting Officer) /s/ Ronald D. Ormand Executive Chairman of the Board March 9, 2018Ronald D. Ormand /s/ Peter Benz Director March 9, 2018Peter Benz /s/ Mark Christensen Director March 9, 2018Mark Christensen /s/ Nuno Brandolini Director March 9, 2018Nuno Brandolini /s/ R. Glenn Dawson Director March 9, 2018R. Glenn Dawson /s/ General Merrill McPeak Director March 9, 2018General Merrill McPeak /s/ G. Tyler Runnels Director March 9, 2018G. Tyler Runnels Director March 9, 2018Markus Specks Director March 9, 2018John Johanning 135  Exhibit Index The following exhibits are either filed herewith or incorporated herein by reference 2.1Agreement 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).2.2First Amendment to Agreement and Plan of Merger, dated as of January 20, 2016, among Lilis Energy, Inc., Lilis Merger Sub, Inc. andBrushy 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).2.3Second Amendment to Agreement and Plan of Merger, dated as of March 24, 2016, among Lilis Energy, Inc., Lilis Merger Sub, Inc. andBrushy 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).2.4Third Amendment to Agreement and Plan of Merger, dated as of June 22, 2016, among Lilis Energy, Inc., Lilis Merger Sub, Inc. and BrushyResources, Inc. (incorporated herein by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on June 28, 2016).2.5Purchase 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).3.1Amended and Restated Articles of Incorporation of Recovery Energy, Inc., dated as of October 10, 2011 (incorporated herein by referenceto Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on October 20, 2011).3.2Certificate 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).3.3Certificate of Designation of Preferences, Rights, and Limitations of Series A 8% Convertible Preferred Stock, dated as of May 30, 2014(incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 4, 2014).3.4Amendment to Certificate of Designation of Preferences, Rights, and Limitations of Series A 8% Convertible Preferred Stock, dated as ofJune 12, 2014 (incorporated herein by reference to Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q for the quarter endedMarch 31, 2014, filed on June 17, 2014).3.5Certificate of Designation of Preferences, Rights and Limitations of 6% Redeemable Preferred Stock, dated as of August 29, 2014(incorporated herein by reference to Exhibit 3.3 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2014, filedon November 26, 2014).3.6Certificate of Designation of Preferences, Rights and Limitations of Series B 6% Convertible Preferred Stock, dated as of June 15, 2016(incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 16, 2016).3.7Certificate of Change of Lilis Energy, Inc., dated as of June 21, 2016 (incorporated herein by reference to Exhibit 3.1 to the Company’sCurrent Report on Form 8-K filed on June 28, 2016).3.8Amended and Restated Bylaws (incorporated herein by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed onJune 18, 2010).3.9Amended and Restated Certificate of Designations of Preferences, Rights and Limitations of Series B 6% Convertible Preferred Stock, datedApril 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).3.10Certificate of Designation of Preferences, Rights and Limitations of Series C 9.75% Convertible Participating Preferred Stock, datedJanuary 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).4.1Form 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).4.2Form 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).4.3Five Year Warrant to David Castaneda dated January 17, 2014 (incorporated herein by reference to Exhibit 4.1 to the Company’s QuarterlyReport on Form 10-Q for the period ended March 31, 2014, filed on June 17, 2014).4.4Five Year Warrant (Anniversary Warrant) to David Castaneda dated January 17, 2014 (incorporated herein by reference to Exhibit 4.2 to theCompany’s Quarterly Report on Form 10-Q for the period ended March 31, 2014, filed on June 17, 2014).4.5Form of Warrant dated May 30, 2014 (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filedon June 4, 2014). 136  4.6Warrant to Purchase Common Stock issued to Bristol Capital (incorporated herein by reference to Exhibit 4.3 to the Company’s QuarterlyReport on Form 10-Q for the period ended June 30, 2014, filed on November 26, 2014).4.7Warrant to Purchase Common Stock issued to Heartland Bank (incorporated herein by reference to Exhibit 4.3 to the Company’s QuarterlyReport on Form 10-Q, filed on February 26, 2015).4.8Form of Convertible Note (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on January5, 2016).4.9Form 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).4.10Form of Common Stock Purchase Warrant (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-Kfiled on June 16, 2016).4.11Common Stock Purchase Warrant issued to SOSV Investments, LLC on June 23, 2016. (incorporated herein by reference to Exhibit 4.3 tothe Company’s Quarterly Report on Form 10-Q filed on August 25, 2016).4.12Form of Common Stock Certificate (incorporated herein by reference to Exhibit 4.1 to the Company’s Registration Statement on Form S-1filed on September 16, 2016).4.13Form 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).4.14†Lilis Energy, Inc. 2016 Omnibus Incentive Plan and forms of agreement thereunder (incorporated herein by reference to Exhibit 4.1 to theCompany’s Registration Statement on Form S-8 filed on June 28, 2016).4.15†First Amendment to the Lilis Energy, Inc. 2016 Omnibus Incentive Plan, approved on November 3, 2016 (incorporated herein by referenceto Annex C to the Company’s Definitive Proxy filed on September 30, 2016).4.16†Second Amendment to the Company’s 2016 Omnibus Incentive Plan, dated July 13, 2017 (incorporated herein by reference to Annex A ofthe Company’s Definitive Proxy Statement on Schedule 14A, filed on June 19, 2017).10.1†Employment Agreement with Kevin Nanke, dated as of March 6, 2015 (incorporated herein by reference to Exhibit 10.1 to the Company’sCurrent Report on Form 8-K filed on March 12, 2015).10.2†Employment Agreement with Ariella Fuchs, dated as of March 16, 2015 (incorporated herein by reference to Exhibit 10.84 to theCompany’s Annual Report on Form 10-K for the year ended December 31, 2014, filed on April 15, 2015).10.3†Amended and Restated Employment Agreement between the Company and Abraham Mirman, dated as of March 30, 2015 (incorporatedherein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 2, 2015).10.4Recovery Energy, Inc. 2012 Equity Incentive Plan dated August 31, 2012, as amended (incorporated herein by reference to Appendix B tothe Company’s definitive proxy filed on December 15, 2015).10.5Voting Agreement, dated as of December 29, 2015, among Lilis Energy, Inc., Lilis Merger Sub, Inc., Brushy Resources, Inc. andSOSventures, LLC (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 5,2016).10.6Voting Agreement, dated as of December 29, 2015, among Lilis Energy, Inc., Lilis Merger Sub, Inc., Brushy Resources, Inc. and LongviewMarquis Fund LP, LMIF Investments LLC and SMF investments, LLC (incorporated herein by reference to Exhibit 10.2 to the Company’sCurrent Report on Form 8-K filed on January 5, 2016).10.7Debenture Conversion Agreement, dated as of December 29, 2015, among Lilis Energy, Inc., T.R. Winston & Company, acting asplacement agent, and each Debenture holder (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on January 5, 2016).10.8Form of Convertible Note Purchase Agreement (incorporated herein by reference to Exhibit 10.5 to the Company’s Current Report on Form8-K filed on January 5, 2016).10.9Form of Note Exchange Agreement (incorporated herein by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K filedon January 5, 2016).10.10Form of Securities Purchase Agreement (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-Kfiled on June 16, 2016).10.11Form of Registration Rights Agreement (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-Kfiled on June 16, 2016).10.12Convertible Subordinated Promissory Note Conversion Agreement, dated as of June 23, 2016, among Lilis Energy, Inc. and the partiessignatory thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on June 28, 2016).10.13First Amendment to the Convertible Subordinated Promissory Notes, dated as of August 3, 2016, among Lilis Energy, Inc. and the partiessignatory thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on August 5, 2016).10.14†Employment Agreement with Michael Pawelek, dated as of July 5, 2016 (incorporated herein by reference to Exhibit 10.1 to theCompany’s Current Report on Form 8-K filed on July 8, 2016). 137  10.15†Employment Agreement with Edward Shaw, dated as of July 5, 2016 (incorporated herein by reference to Exhibit 10.2 to the Company’sCurrent Report on Form 8-K filed on July 8, 2016).10.16†Employment Agreement with Abraham Mirman, dated as of July 5, 2016 (incorporated herein by reference to Exhibit 10.3 to theCompany’s Current Report on Form 8-K filed on July 8, 2016).10.17†Employment Agreement with Kevin Nanke, dated as of July 5, 2016 (incorporated herein by reference to Exhibit 10.4 to the Company’sCurrent Report on Form 8-K filed on July 8, 2016).10.18†Employment Agreement with Ariella Fuchs, dated as of July 5, 2016 (incorporated herein by reference to Exhibit 10.5 to the Company’sCurrent Report on Form 8-K filed on July 8, 2016).10.19†Employment Agreement with Ronald Ormand, dated as of July 5, 2016 (incorporated herein by reference to Exhibit 10.6 to the Company’sCurrent Report on Form 8-K filed on July 8, 2016).10.20Transaction Fee Agreement, dated as of June 6, 2016, between Lilis Energy, Inc. and T.R. Winston & Company, LLC (incorporated hereinby reference to Exhibit 10.12 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2016 filed on August 25,2016).10.21First Amendment to Transaction Fee Agreement, dated as of June 8, 2016, between Lilis Energy, Inc. and T.R. Winston & Company, LLC(incorporated herein by reference to Exhibit 10.13 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2016filed on August 25, 2016).10.22Escrow Deposit Agreement, dated as of May 26, 2016, by and among Lilis Energy, Inc., T.R. Winston & Company, LLC and SignatureBank (incorporated herein by reference to Exhibit 10.15 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30,2016 filed on August 25, 2016).10.23Texican Crude & Hydrocarbon LLC Purchase Contract, dated as of February 3, 2016, between Texican Crude & Hydrocarbon, LLC andImpetro Operating LLC (incorporated herein by reference to Exhibit 10.65 to Brushy Resources, Inc.’s Registration Statement on Form S-1filed on September 16, 2016).10.24DCP Midstream, LP Gas Purchase Agreement (incorporated herein by reference to Exhibit 10.8 to Brushy Resources, Inc.’s Form 10/A filedon July 26, 2013, which became effective August 6, 2013).10.25Credit and Guarantee Agreement, dated as of September 29, 2016 by and among Lilis Energy, Inc., Brushy Resources, Inc., ImPetroOperating, 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).10.26†Employment Agreement with Joseph C. Daches, dated as of January 23, 2017 (incorporated herein by reference to Exhibit 10.1 to theCompany’s Current Report on Form 8-K filed on January 25, 2017).10.27†Employment Agreement with Brennan Short, dated as of January 27, 2017 (incorporated herein by reference to Exhibit 10.1 to theCompany’s Current Report on Form 8-K filed on January 31, 2017).10.28†Employment Agreement with Seth Blackwell, dated as of December 1, 2016 (incorporated herein by reference to Exhibit 10.28 to theCompany’s Annual Report on Form 10-K filed on March 3, 2017).10.29†Separation and Release Agreement, dated February 13, 2017, between Kevin Nanke and Lilis Energy, Inc. (incorporated herein by referenceto Exhibit 10.1 to the Company’s Current Report on Form 8-K/A filed on February 17, 2017).10.30Securities Subscription Agreement, dated February 28, 2017, by and among the Company and the Purchasers thereto (incorporated hereinby reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on March 2, 2017).10.31Registration Rights Agreement, dated February 28, 2017, by and among the Company and the Purchasers thereto (incorporated herein byreference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on March 2, 2017).10.32†First Amendment to Employment Agreement with Abraham Mirman, dated as of March 9, 2017 (incorporated herein by reference to Exhibit10.1 to the Company’s Current Report on Form 8-K filed on March 10, 2017).10.33†First Amendment to Employment Agreement with Ronald D. Ormand, dated as of March 9, 2017 (incorporated herein by reference toExhibit 10.2 to the Company’s Current Report on Form 8-K filed on March 10, 2017).10.34†First Amendment to Employment Agreement with Ariella Fuchs, dated as of March 9, 2017 (incorporated herein by reference to Exhibit10.3 to the Company’s Current Report on Form 8-K filed on March 10, 2017).10.35First Amendment to Credit and Guarantee Agreement, dated April 24, 2017 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 filed April 27, 2017).10.36Second Amendment to Credit and Guarantee Agreement, dated April 26, 2017 by and among Lilis Energy, Inc., Brushy Resources, Inc.,ImPetro Operating, LLC, ImPetro Resources, LLC, the Lenders party thereto and Deans Knight Capital Management Ltd. acting ascollateral agent (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed April 27, 2017). 138  10.37Third Amendment to Credit and Guarantee Agreement, dated July 25, 2017 by and among the Company, Brushy Resources, Inc., ImPetroOperating, LLC, ImPetro Resources, LLC, Lilis Operating Company, LLC, the Lenders party thereto and Deans Knight CapitalManagement Ltd., as collateral agent (incorporated herein by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Qfiled August 14, 2017).10.38Credit Agreement, dated April 26, 2017 by and among Lilis Energy, Inc., the Guarantors party thereto, the Lenders party thereto andWilmington Trust, National Association acting as administrative agent (incorporated herein by reference to Exhibit 10.3 to the Company’sCurrent Report on Form 8-K filed April 27, 2017).10.39Registration Rights Agreement, dated April 26, 2017 by and among the Lender party thereto (incorporated herein by reference to Exhibit10.4 to the Company’s Current Report on Form 8-K filed April 27, 2017).10.40Series 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).10.41†Second Amendment to Employment Agreement with Abraham Mirman, dated as of May 5, 2017 (incorporated herein by reference toExhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 8, 2017)10.42†First Amendment to Employment Agreement with Joseph Daches, dated as of May 5, 2017 (incorporated herein by reference to Exhibit 10.2to the Company’s Current Report on Form 8-K filed on May 8, 2017)10.43†Second Amendment to Employment Agreement with Ariella Fuchs, dated as of May 5, 2017 (incorporated herein by reference to Exhibit10.3 to the Company’s Current Report on Form 8-K filed on May 8, 2017)10.44†Employment Agreement with James Linville, dated as of June 26, 2017 (incorporated herein by reference to Exhibit 10.1 to the Company’sCurrent Report on Form 8-K filed on June 26, 2017).10.45†Separation and Consulting Agreement, dated August 3, 2017, by and between Lilis Energy, Inc. and Abraham Mirman (incorporated hereinby reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on August 4, 2017).10.46†First Amendment of Executive Employment Agreement, dated August 4, 2017, by and between Lilis Energy, Inc. and Jim Linville(incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on August 4, 2017).10.47Letter Agreement dated August 12, 2017 between the Company and Värde Partners, Inc. (incorporated herein by reference to Exhibit 10.14on the Company’s Quarterly Report on Form 10-Q filed on August 14, 2017).10.48Gas 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). Specificitems in this exhibit have been redacted, as marked by two asterisks (**), because confidential treatment for those items has granted. Theredacted material has been separately filed with the SEC.10.49*Amendment No. 1 to the Gas Gathering, Processing and Purchase Agreement, dated October 1, 2017 by and among the Company and LucidEnergy Delaware.10.50Amendment 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 Exhibit10.1 to the Company’s Current Report on Form 8-K filed on October 10, 2017).10.51Amendment No. 4 and Joinder to Credit and Guarantee Agreement, dated October 19, 2017 by and among the Company, the Guarantorsparty thereto, the Lenders party thereto and Deans Knight Capital Management Ltd., as collateral agent (incorporated herein by reference toExhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 24, 2017).10.52Amendment 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 Exhibit10.2 to the Company’s Current Report on Form 8-K filed on October 24, 2017).10.53Amendment No. 3 to Second Lien Credit Agreement, dated November 10, 2017 by and among Lilis Energy, Inc., the Guarantors partythereto, the Lenders party thereto and Wilmington Trust, National Association, as administrative agent (incorporated herein by reference toExhibit 10.1 to the Company’s Current Report on Form 8-K filed on November 14, 2017).10.54Securities 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).10.55Registration 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).10.56Amended and Restated Senior Secured Term Loan Credit Agreement, dated as of January 30, 2018, by and among Lilis Energy, Inc., thesubsidiaries 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 onFebruary 1, 2018). 139  10.57Amendment No. 4 to Second Lien Credit Agreement, dated as of January 31, 2018, by and among Lilis Energy, Inc., the guarantors partythereto, the lenders party thereto and Wilmington Trust, National Association, as administrative agent (incorporated herein by reference toExhibit 10.4 to the Company’s Current Report on Form 8-K filed on February 1, 2018).10.58*Amendment No. 5 to Second Lien Credit Agreement, dated as of February 20, 2018, by and among Lilis Energy, Inc., the guarantors partythereto, the lenders party thereto and Wilmington Trust, National Association, as administrative agent.10.59*Amendment No. 1 to the Amended and Restated Senior Secured Term Loan Credit Agreement, dated as of February 20, 2018, by and amongLilis Energy, Inc., the subsidiaries of the Company party thereto as guarantors, Riverstone Credit Management LLC, as administrative agentand collateral agent, and the lenders party thereto.16.1Letter from Marcum LLP dated April 14, 2017 (incorporated herein by reference to Exhibit 16.1 to the Company’s Current Report on Form8-K filed April 14, 2017).21.1*List of Subsidiaries of the Company.23.1*Consent of BDO USA, LLP for the Company.23.2*Consent of Marcum LLP 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 2002.31.2*Certifications Pursuant to Section 302 of Sarbanes Oxley Act of 2002.32.1*Certifications Pursuant to Section 906 of Sarbanes Oxley Act of 2002.32.2*Certifications Pursuant to Section 906 of Sarbanes Oxley Act of 2002.99.1*Report of Cawley, Gillespie & Associates, Inc., dated January 10, 2018, for the Company.101.INS*XBRL Instance Document101.SCH*XBRL Taxonomy Extension Schema Document101.CAL*XBRL Taxonomy Extension Calculation Linkbase Document101.DEF*XBRL Taxonomy Extension Definition Linkbase Document101.LAB*XBRL Taxonomy Extension Label Linkbase Document101.PRE*XBRL Taxonomy Extension Presentation Linkbase Document *Filed herewith.†Indicates management contract or compensatory plan.+To be filed by amendment. 140  Exhibit 10.49 Amendment No. 1toGAS GATHERING, PROCESSING AND PURCHASE AGREEMENT This Amendment No. 1 to Gas Gathering, Processing and Purchase Agreement (this “Amendment No. 1”) is made and entered into as of the 1st day ofOctober, 2017 (the “Amendment No. 1 Effective Date”), by and between Lucid Energy Delaware, LLC, a Delaware limited liability company (“Buyer”) andLilis Energy, Inc., a Nevada corporation (“Seller”). Buyer and Seller are sometimes referred to in this Amendment No. 1 individually as a “Party” andcollectively as the “Parties.” Capitalized terms used herein but not defined herein will have the meanings set forth in the Agreement. Background: Buyer and Seller are parties to that certain Gas Gathering, Processing and Purchase Agreement with an Effective Date of August 10, 2017 (the“Agreement”). Agreement: In consideration of the premises and of the mutual covenants set forth in this Amendment, the Parties agree as follows: Section 1. Amendment to the Agreement. (a) Exhibit D to the Agreement is hereby deleted in its entirety and replaced with the attached Exhibit D-1. As of the Amendment No. 1Effective Date, all references in the Agreement to Exhibit D will be references to Exhibit D-1. (b) Exhibit E to the Agreement is hereby deleted in its entirety and replaced with the attached Exhibit E-1. As of the Amendment No. 1Effective Date, all references in the Agreement to Exhibit E will be references to Exhibit E-1. Section 2. Miscellaneous. (a) Except as amended by this Amendment No. 1, all of the terms and provisions of the Agreement will remain in full force and effect. (b) Each capitalized term used in this Amendment No. 1 that is not otherwise defined in this Amendment No. 1 has the meaning assigned tosuch term in the Agreement. (c) This Amendment No. 1 may be executed by the Parties in counterparts (including without limitation facsimile counterparts), each ofwhich will be deemed an original. (d) This Amendment No. 1 is effective on the Amendment No. 1 Effective Date and is binding upon and will inure to the benefit of theParties and their respective successors and permitted assigns.  (e) This Amendment No. 1 will be governed by and construed in accordance with the laws of the State of Texas. IN WITNESS WHEREOF, the Parties have caused this Amendment No. 1 to be executed in duplicate originals by their duly authorized officers onthe dates indicated below but as of the Amendment No. 1 Effective Date. SELLER: BUYER: LILIS ENERGY, INC. LUCID ENERGY DELAWARE, LLC By:/s/ Jim Linville By:/s/ Scott BrownName:Jim Linville Name:Scott BrownTitle:Chief Executive Officer Title:Executive Vice President and CCODate:11/9/17 Date:11/10/17  EXHIBIT D-1toGAS GATHERING, PROCESSING AND PURCHASE AGREEMENTdated as of October 1, 2017betweenLUCID ENERGY DELAWARE, LLC(Buyer)andLILIS ENERGY, INC.(Seller) LOW PRESSURE RECEIPT POINTS Meter NumberPoints of Receipt NameCounty, StateLat/LongTBDCrittendon Field Station LPWinkler, TexasTBD HIGH PRESSURE RECEIPT POINTS Meter NumberPoints of Receipt NameCounty, StateLat/LongTBDWild HogLea, New MexicoTBDTBDPrize HogLea, New MexicoTBDTBDCrittendon NorthWinkler, TexasTBDTBDCrittendon Field Station HPWinkler, TexasTBDTBDCrittendon EastWinkler, TexasTBD DELIVERY POINTS Meter NumberPoints of Delivery NameCounty, StateLat/Long37914El Paso/Kinder MorganLea, New Mexico32.2888°/-103.6478°95720TranswesternLea, New Mexico32.2111°/-103.5948° PLANT PRODUCTS DELIVERY POINTS Meter NumberPoints of Delivery NameCounty, StateLat/LongTBDRed Hills Tailgate with redelivery toONEOK West TexasLea, New Mexico32.3651°/-103.1537°TBDEnterprise PipelineLea, New Mexico32.2168°/-103.5246°TBDEnterprise PipelineEddy, New Mexico32.2665°/-104.1180°TBDDCP Sand Hills1Lea, New MexicoTBD 1 – Should Seller request to Take-In-Kind, per Article 4.5 of the Agreement, and deliver to DCP Sand Hills, Seller’s ability to deliver to such Delivery Pointshall be subject to Seller entering into all Plant Product transportation agreements. ** Exhibit D will be amended to add meter numbers and locations of facilities if/when Buyer establishes such Plant Products Delivery Points. END OF EXHIBIT D-1 Amendment No. 1 dated October 1, 2017To Gas Gathering, Processing and Purchase Agreement effective August 10, 2017  EXHIBIT E-1toGAS GATHERING, PROCESSING AND PURCHASE AGREEMENTdated as of October 1, 2017betweenLUCID ENERGY DELAWARE, LLC(Buyer)andLILIS ENERGY, INC.(Seller) INTERESTS IN THE DEDICATED ACREAGE StateCountyDescriptionNew MexicoLeaSection 21, Township 26 S, Range 35 ENew MexicoLeaSection 19, Township 26 S, Range 36 ENew MexicoLeaSection 20, Township 26 S, Range 36 ETexasLovingBlock C24, Section 4, PSL, Cowden C C, A-1401TexasWinklerBlock C24, Section 4, PSL, Cowden C C, A-1397TexasWinklerBlock C23, Section 21, PSL, Cowden C C & L, A-1391TexasWinklerBlock C24, Section 2, PSL, Cowden C C, A-1396TexasWinklerBlock C23, Section 25, PSL, Cowden C C, A-1394TexasWinklerBlock C23, Section 22, PSL, Cowden C C, A-1414TexasWinklerBlock C24, Section 1, PSL, Cowden C C, A-1395TexasWinklerBlock C23, Section 24, PSL, Cowden C C, A-1393TexasWinklerBlock C23, Section 23, PSL, Cowden C C, A-1392TexasWinklerBlock C23, Section 16, PSL, Beckham W L, A-1324TexasWinklerBlock C23, Section 15, PSL, Beckham W L, A-1323TexasWinklerBlock 75, Section 1, PSL, Cowden C C, A-1381TexasWinklerBlock 74, Section 9, PSL, Cowden C C, A-1377TexasWinklerBlock 74, Section 7, PSL, Desmond J L, A-714TexasWinklerBlock 74, Section 6, PSL, Moreland R E, A-521TexasWinklerBlock 74, Section 5, PSL, Moreland R E, A-614TexasWinklerBlock 74, Section 5, PSL, Moreland R E, A-613TexasWinklerBlock 74, Section 23, Desmond, J L, A-1021TexasWinklerBlock 74, Section 32, Desmond, J L, A-1022TexasWinklerBlock 74, Section 30, Leck, R A, A-1099TexasWinklerBlock 74, Section 29, Leck, R A, A-1100TexasWinklerBlock 74, Section 25, Leck, R A, A-1102TexasWinklerBlock 74, Section 11, Cowden, C C, A-1379TexasWinklerBlock C23, Section 10, Cowden, C C, A-1383TexasWinklerBlock C23, Section 11, Cowden, C C, A-1384TexasWinklerBlock C23, Section 13, Cowden, C C, A-1386TexasWinklerBlock C23, Section 14, Cowden, C C, A-1387TexasWinklerBlock C23, Section 17, Cowden, C C, A-1388TexasWinklerBlock C23, Section 26, Cowden, C C, A-1415TexasWinklerBlock 74, Section 4, Daugherty, L, A-1482TexasWinklerBlock 74, Section 22, Daugherty, L, A-1487TexasWinklerBlock 74, Section 33, Daugherty, L, A-1488TexasWinklerBlock C23, Section 9, Daugherty, L, A-1491TexasWinklerBlock 74, Section 12, Daugherty, L, A-1495 Amendment No. 1 dated October 1, 2017To Gas Gathering, Processing and Purchase Agreement effective August 10, 2017   TexasWinklerBlock 74, Section 14, Leck, M J, A-1683TexasWinklerBlock 74, Section 15, Leck, M J, A-1684TexasWinklerBlock 74, Section 23, Scarborough, W F, A-1926TexasWinklerBlock 74, Section 31, Simpson, J S, A-628TexasWinklerBlock 74, Section 24, Cline, C, A-955TexasWinklerBlock 74, Section 26, Shafer, J B, A-972TexasWinklerBlock 74, Section 10, Cowden, C C, A-1378TexasWinklerBlock 74, Section 27, Cowden, C C, A-1380TexasWinklerBlock 75, Section 1, Cowden, C C, A-1381TexasWinklerBlock C23, Section 18, Cowden, C C, A-1389TexasWinklerBlock C23, Section 19, Cowden, C C, A-1390TexasLovingBlock C24, Section 3, Cowden, C C, A-1402TexasWinklerBlock 74, Section 8, Cowden, C C, A-1412TexasWinklerBlock C23, Section 20, Cowden, C C, A-1413TexasWinklerBlock C23, Section 27, Cowden, C C, A-1416TexasWinklerBlock C24, Section 3, Cowden, C C, A-1417TexasWinklerBlock 74, Section 13, Daugherty, L, A-1483 DEDICATED ACREAGE MAP Amendment No. 1 dated October 1, 2017To Gas Gathering, Processing and Purchase Agreement effective August 10, 2017  CONFLICTING DEDICATION The Parties acknowledge and agree that the Interests are, as of the Effective Date, subject to prior written dedications and commitments for gathering,processing and purchase of Gas pursuant to the certain agreements provided below and that Seller shall be entitled to comply with such prior writtendedications or commitments in accordance with the provisions of this Agreement. 1)Gas Gathering Agreement dated July 2, 2012, as amended by and between Regency Field Services LLC (predecessor-in-interest to ETC FieldServices LLC) and Permian Atlantis LLC (predecessor-in-interest to Lilis Energy, Inc.) with an expiration date of February 1, 2018. 2)Gas Gathering Agreement dated August 1, 2008, as amended by and between Regency Field Services LLC (predecessor-in-interest to ETC FieldServices LLC) and Lakehills Production, Inc. (predecessor-in-interest to Lilis Energy, Inc.) with an expiration date of February 1, 2018. 3)Gas Gathering Agreement effective July 1, 2012, as amended by and between Anadarko Gathering Company LLC and SWEPI LP (predecessor-in-interest to Lilis Energy, Inc.) with an expiration date of December 31, 2017. The Parties acknowledge and agree that the following wellbores are, as of the Effective Date, subject to prior written dedications and alternative commitmentsfor gathering, processing and purchase of Gas and therefore, such wellbores are excluded from the Dedication. StateCountyWellbore NameAPITexasWinklerA.G. Hill42-495-30914TexasWinklerTubb 1 Unit #142-495-30070TexasWinklerTubb 22 Unit #1R42-495-10934TexasWinklerTubb 9 Unit #142-495-10933TexasWinklerTubb Estate 1-75 #142-495-30127TexasWinklerTubb Estate 21 #242-495-30285TexasWinklerTubb Estate 25 #142-495-10811TexasWinklerTubb Estate 25 #342-495-32097TexasWinklerWolfe Unit #142-495-10744TexasWinklerWolfe Unit #542-495-32750TexasWinklerWolfe Unit #642-495-32768TexasWinklerShammo42-301-31378 END OF EXHIBIT E-1 Amendment No. 1 dated October 1, 2017To Gas Gathering, Processing and Purchase Agreement effective August 10, 2017  Exhibit 10.57 AMENDMENT NO. 5 TO CREDIT AGREEMENT This Amendment No. 5 to Credit Agreement (this “Amendment”) dated as of February 20, 2018 (the “Effective Date”) is among Lilis Energy, Inc.(the “Borrower”), certain subsidiaries of the Borrower party hereto (each, a “Guarantor” and collectively, the “Guarantors”), Wilmington Trust, NationalAssociation, as administrative agent (the “Administrative Agent”), Värde Partners, Inc., (“Värde”) in its capacity as the Lead Lender (as defined in the CreditAgreement (as defined below)) and the other Lenders (as defined below) party hereto. INTRODUCTION Whereas, the Borrower, the Guarantors, the Administrative Agent, Värde as the Lead Lender (as defined therein) and the other lenders party theretofrom time to time (the “Lenders”) are parties to that certain Credit Agreement dated as of April 26, 2017 (as amended, restated, amended and restated,supplemented or otherwise modified from time to time, the “Credit Agreement”). Whereas, the Borrower has requested that Administrative Agent and the Lenders amend the Credit Agreement in certain respects as set forth herein,and the Administrative Agent and the Lenders have agreed to the foregoing, on the terms and conditions set forth herein. NOW THEREFORE, in consideration of the premises and the mutual covenants, representations and warranties contained herein, and for other goodand valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto hereby agree as follows: Section 1. Defined Terms; Other Definitional Provisions. As used in this Amendment, each of the terms defined in the opening paragraph and theRecitals above shall have the meanings assigned to such terms therein. Each term defined in the Credit Agreement and used herein without definition shallhave the meaning assigned to such term in the Credit Agreement, unless expressly provided to the contrary. Article, Section, Schedule, and Exhibit referencesare to Articles and Sections of and Schedules and Exhibits to this Amendment, unless otherwise specified. The words “hereof”, “herein”, and “hereunder” andwords of similar import when used in this Amendment shall refer to this Amendment as a whole and not to any particular provision of this Amendment. Theterm “including” means “including, without limitation”. Paragraph headings have been inserted in this Amendment as a matter of convenience for referenceonly and it is agreed that such paragraph headings are not a part of this Amendment and shall not be used in the interpretation of any provision of thisAmendment. Section 2. Amendments to the Credit Agreement. Subject to the satisfaction of the conditions set forth in Section 4 below, and in reliance on therepresentations and warranties contained in Section 3 below, the Credit Agreement is hereby amended as follows: (a) Section 1.01 of the Credit Agreement is hereby amended by inserting the following definitions in the appropriate alphabetical order: “Amendment No. 5 Effective Date” means February 20, 2018. (b) Section 6.09 of the Credit Agreement is hereby amended by (i) deleting the word “and” at the end of clause (b), (ii) replacing “.” at the end ofclause (c) with “; and”, and (iii) adding a new clause (d) as set forth below: (d) at any time on or after the Amendment No. 5 Effective Date, the Borrower may repurchase shares of its common stock for an aggregatepurchase price not to exceed $10,000,000; provided that the Borrower may not purchase any of its common stock pursuant to this clause (d) that isowned by any (A) Affiliate of the Borrower or current employee, officer, or director of the Borrower or any Affiliate thereof and/or (B) formeremployee, former officer or former director of the Borrower or any Affiliate thereof unless such purchase made pursuant to this clause (B) is at amarket price and on arm's length terms.  Section 3. Representations and Warranties. Each Credit Party hereby represents and warrants that: (a) after giving effect to this Amendment, therepresentations and warranties contained in Article III of the Credit Agreement and in each other Loan Document are true and correct in all material respects,except for any representation and warranty that is qualified by materiality or reference to Material Adverse Effect, which such representation and warrantyshall be true and correct in all respects, on and as of the Effective Date, except to the extent that such representations and warranties specifically refer to anearlier date, in which case they shall be true and correct in all material respects, except for any representation and warranty that is qualified by materiality orreference to Material Adverse Effect, which such representation and warranty shall be true and correct in all respects, as of such earlier date; (b) after givingeffect to this Amendment, no Default has occurred and is continuing; (c) the execution, delivery and performance of this Amendment are within the corporateor limited liability company power and authority of such Credit Party and have been duly authorized by appropriate corporate or limited liability companyaction and proceedings; (d) this Amendment constitutes the legal, valid, and binding obligation of such Credit Party enforceable in accordance with its terms,except as limited by applicable bankruptcy, insolvency, reorganization, moratorium, or similar laws affecting the rights of creditors generally and generalprinciples of equity; (e) there are no governmental or other third party consents, licenses and approvals required in connection with the execution, delivery,performance, validity and enforceability of this Amendment; and (f) the Liens under the Loan Documents are valid and subsisting and secure the CreditParties’ obligations under such Loan Documents. Section 4. Conditions to Effectiveness. This Amendment shall become effective on the Effective Date and enforceable against the parties heretoupon the satisfaction of the following conditions precedent: (a) the Administrative Agent and the Lead Lender shall have received this Amendment duly executed by the Borrower, the Guarantors, theAdministrative Agent, the Lenders party hereto (which constitute all Lenders party to the Credit Agreement) and the Lead Lender; (b) the Borrower shall have paid on or about the Effective Date all costs and expenses which are payable pursuant to Section 10.03 of the CreditAgreement and which have been invoiced no later than one Business Days prior to the date hereof; and (c) the Lead Lender and the Administrative Agent shall have received executed copies of any amendments to the Permitted First Lien CreditAgreement executed on or about the date hereof. Section 5. Acknowledgments and Agreements. (a) Each Credit Party acknowledges that on the date hereof, all outstanding Obligations are payable in accordance with their terms and each CreditParty waives any defense, offset, counterclaim or recoupment, in each case existing on the date hereof, with respect to such Obligations. Each Credit Partydoes hereby adopt, ratify, and confirm the Credit Agreement and acknowledges and agrees that the Credit Agreement is and remains in full force and effect,and each Credit Party acknowledges and agrees that its respective liabilities and obligations under the Credit Agreement are not impaired in any respect bythis Amendment. 2  (b) This Amendment is a Loan Document for the purposes of the provisions of the other Loan Documents. Without limiting the foregoing, anybreach of representations, warranties, and covenants under this Amendment shall be a Default or Event of Default, as applicable, under the Credit Agreement. Section 6. Reaffirmation of Guaranty. Each Guarantor hereby ratifies, confirms, and acknowledges that its obligations under the Credit Agreementare in full force and effect and that each Guarantor continues to unconditionally and irrevocably, jointly and severally, guarantee the full and punctualpayment, when due, whether at stated maturity or earlier by acceleration or otherwise, of all of the Obligations, and its execution and delivery of thisAmendment does not indicate or establish an approval or consent requirement by the Guarantors in connection with the execution and delivery ofamendments, consents or waivers to the Credit Agreement or any of the other Loan Documents. Section 7. Reaffirmation of Liens. Each Credit Party (a) is party to certain Security Documents securing and supporting the Obligations under theLoan Documents, (b) represents and warrants that it has no defenses to the enforcement of the Security Documents and that according to their terms theSecurity Documents will continue in full force and effect to secure the Obligations under the Loan Documents, as the same may be amended, supplemented,or otherwise modified, and (c) acknowledges, represents, and warrants that the liens and security interests created by the Security Documents are valid andsubsisting and create an acceptable security interest in the collateral to secure the Obligations under the Loan Documents, as the same may be amended,supplemented, or otherwise modified. Section 8. Counterparts. This Amendment may be signed in any number of counterparts and by different parties hereto in separate counterparts,each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement. Transmissionby facsimile or other electronic transmission of an executed counterpart of this Amendment shall be deemed to constitute due and sufficient delivery of suchcounterpart. Section 9. Successors and Assigns. This Amendment shall be binding upon and inure to the benefit of the parties hereto and their respectivesuccessors and assigns permitted pursuant to the Credit Agreement. Section 10. Invalidity. In the event that any one or more of the provisions contained in this Amendment shall for any reason be held invalid, illegalor unenforceable in any respect, such invalidity, illegality or unenforceability shall not affect any other provision of this Amendment. Section 11. Governing Law. This Amendment shall be governed by and construed in accordance with the laws of the State of New York. Section10.09 of the Credit Agreement is hereby incorporated by reference herein mutatis mutandis. Section 12. Instruction to Administrative Agent. The Lenders hereby (i) authorize and instruct the Administrative Agent to execute and deliver thisAmendment and that certain Letter Agreement, dated as of the date hereof, by and between the Administrative Agent and Riverstone Credit ManagementLLC and (ii) acknowledge and agree that the instruction set forth in this Section 12 constitutes an instruction from the Lenders under the Loan Documents,including Section 9.03 and Section 9.04 of the Credit Agreement. 3  Section 13. RELEASE. For good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, each Credit Partyhereby, for itself and its successors and assigns, fully and without reserve, releases, acquits, and forever discharges each Secured Party, its respectivesuccessors and assigns, officers, directors, employees, representatives, trustees, attorneys, agents and affiliates (collectively the “Released Parties” andindividually a “Released Party”) from any and all actions, claims, demands, causes of action, judgments, executions, suits, debts, liabilities, costs,damages, expenses or other obligations of any kind and nature whatsoever, direct and/or indirect, at law or in equity, whether now existing or hereafterasserted, whether absolute or contingent, whether due or to become due, whether disputed or undisputed, whether known or unknown (INCLUDING,WITHOUT LIMITATION, ANY OFFSETS, REDUCTIONS, REBATEMENT, CLAIMS OF USURY OR CLAIMS WITH RESPECT TO THENEGLIGENCE OF ANY RELEASED PARTY) (collectively, the “Released Claims”), for or because of any matters or things occurring, existing oractions done, omitted to be done, or suffered to be done by any of the Released Parties, in each case, on or prior to the Effective Date and are in any waydirectly or indirectly arising out of or in any way connected to any of this Amendment, the Credit Agreement, any other Loan Document, or any of thetransactions contemplated hereby or thereby (collectively, the “Released Matters”). Each Credit Party, by execution hereof, hereby acknowledges andagrees that the agreements in this Section 13 are intended to cover and be in full satisfaction for all or any alleged injuries or damages arising inconnection with the Released Matters herein compromised and settled. Each Credit Party hereby further agrees that it will not sue any Released Partyon the basis of any Released Claim released, remised and discharged by the Credit Parties pursuant to this Section 13. In entering into this Amendment,each Credit Party consulted with, and has been represented by, legal counsel and expressly disclaim any reliance on any representations, acts oromissions by any of the Released Parties and hereby agrees and acknowledges that the validity and effectiveness of the releases set forth herein do notdepend in any way on any such representations, acts and/or omissions or the accuracy, completeness or validity hereof. The provisions of this Section13 shall survive the termination of this Amendment, the Credit Agreement and the other Loan Documents and payment in full of the Obligations. Section 14. Entire Agreement. THIS AMENDMENT, THE CREDIT AGREEMENT AND THE OTHER LOAN DOCUMENTS CONSTITUTETHE ENTIRE UNDERSTANDING AMONG THE PARTIES HERETO WITH RESPECT TO THE SUBJECT MATTER HEREOF AND SUPERSEDEANY PRIOR AGREEMENTS, WRITTEN OR ORAL, WITH RESPECT THERETO. THERE ARE NO UNWRITTEN ORAL AGREEMENTS AMONG THE PARTIES. [The remainder of this page has been left blank intentionally.] 4  EXECUTED to be effective as of the date first above written. BORROWER: LILIS ENERGY, INC. By:/s/ Joseph C. Daches Name:Joseph C. Daches Title: EVP, Chief Financial Officer and Treasurer GUARANTORS: BRUSHY RESOURCES, INC. HURRICANE RESOURCES LLC LILIS OPERATING COMPANY, LLC IMPETRO OPERATING, LLC IMPETRO RESOURCES, LLC By:/s/ Joseph C. Daches Name: Joseph C. Daches Title: Chief Financial Officer and Treasurer Signature Page to Amendment No. 5 to Credit Agreement  ADMINISTRATIVE AGENT: WILMINGTON TRUST, NATIONAL ASSOCIATION, as Administrative Agent By:/s/ Alisha Clendaniel Name: Alisha Clendaniel Title: Assistant Vice President LEAD LENDER: VÄRDE PARTNERS, INC. By:/s/ Markus Specks Name:Markus Specks Title:Managing Director Signature Page to Amendment No. 5 to Credit Agreement  SEVERALLY AND NOT JOINTLY FOR EACHENTITY LISTED BELOW: By:/s/ Markus Specks Name: Markus Specks Title: Managing Director THE VÄRDE FUND VI-A, L.P. ByVärde Investment Partners G.P., LLC, ItsGeneral Partner ByVärde Partners, L.P., Its Managing Member ByVärde Partners, Inc., Its General Partner VÄRDE INVESTMENT PARTNERS, L.P. ByVärde Investment Partners G.P., LLC, ItsGeneral Partner ByVärde Partners, L.P., Its Managing Member ByVärde Partners, Inc., Its General Partner THE VÄRDE FUND XI (MASTER), L.P. ByVärde Fund XI G.P., LLC, Its General Partner ByVärde Partners, L.P., Its Managing Member ByVärde Partners, Inc., Its General Partner VÄRDE INVESTMENT PARTNERS (OFFSHORE)MASTER, L.P. ByVärde Investment Partners G.P., LLC, ItsGeneral Partner ByVärde Partners, L.P., Its Managing Member ByVärde Partners, Inc., Its General Partner THE VÄRDE SKYWAY MASTER FUND, L.P. ByThe Värde Skyway Fund G.P., LLC, Its GeneralPartner ByVärde Partners, L.P., Its Managing Member ByVärde Partners, Inc., Its General Partner THE VÄRDE FUND XII (MASTER), L.P. ByThe Värde Fund XII G.P., L.P., Its GeneralPartner By:The Värde Fund XII UGP, LLC, its GeneralPartner ByVärde Partners, L.P., Its Managing Member ByVärde Partners, Inc., Its General Partner Signature Page to Amendment No. 5 to Credit Agreement  Exhibit 10.58 AMENDMENT NO. 1 TO CREDIT AGREEMENT This Amendment No. 1 to Credit Agreement (this “Amendment”) dated as of February 20, 2018 (the “Effective Date”) is among Lilis Energy, Inc.(the “Borrower”), certain subsidiaries of the Borrower party hereto (each, a “Guarantor” and collectively, the “Guarantors”) and Riverstone CreditManagement LLC, as Administrative Agent (in such capacity, the “Administrative Agent”) and as Collateral Agent (as defined in the Credit Agreement (asdefined below)) and the Lenders (as defined below) party hereto. INTRODUCTION Whereas, the Borrower, the Guarantors, the Administrative Agent, the Collateral Agent (as defined therein) and the lenders party thereto from time totime (the “Lenders”) are parties to that certain Amended and Restated Senior Secured Term Loan Credit Agreement dated as of January 30, 2018 (as amended,restated, amended and restated, supplemented or otherwise modified from time to time, the “Credit Agreement”). Whereas, the Borrower has requested that the Administrative Agent and the Lenders amend the Credit Agreement in certain respects as set forthherein, and the Administrative Agent and the Lenders have agreed to the foregoing, on the terms and conditions set forth herein. NOW THEREFORE, in consideration of the promises and the mutual covenants, representations and warranties contained herein, and for other goodand valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto hereby agree as follows: Section 1. Defined Terms; Other Definitional Provisions. As used in this Amendment, each of the terms defined in the opening paragraph and theIntroduction above shall have the meanings assigned to such terms therein. Each term defined in the Credit Agreement and used herein without definitionshall have the meaning assigned to such term in the Credit Agreement, unless expressly provided to the contrary. Article, Section, Schedule, and Exhibitreferences are to Articles and Sections of and Schedules and Exhibits to this Amendment, unless otherwise specified. Section 1.2 of the Credit Agreement ishereby incorporated by reference herein mutatis mutandis. Section 2. Amendments to the Credit Agreement. Subject to the satisfaction of the conditions set forth in Section 4 below, and in reliance on therepresentations and warranties contained in Section 3 below, the Credit Agreement is hereby amended as follows: (a) Section 1.1 of the Credit Agreement is hereby amended by inserting the following definition in the appropriate alphabetical order: “Amendment No. 1 Effective Date” means February 20, 2018. (b) Section 8.9(d) of the Credit Agreement is hereby amended to read as follows: (d) Payments permitted pursuant to Section 9.6(a) or Section 9.6(b); 1  (c) Section 9.6 of the Credit Agreement is hereby amended by (i) deleting the word “and” at the end of clause (a), (ii) replacing “.” at the end ofclause (b) with “; and”, and (iii) adding a new clause (c) as set forth below: (c) any time on or after the Amendment No. 1 Effective Date, the Borrower may repurchase shares of its common stock for an aggregatepurchase price not to exceed $10,000,000; provided that the Borrower may not purchase any of its common stock pursuant to this clause (c) that isowned by any (A) Affiliate of the Borrower or current employee, officer, or director of the Borrower or any Affiliate thereof and/or (B) formeremployee, former officer, or former director of the Borrower or any Affiliate thereof unless such purchase made pursuant to this clause (B) is at amarket price and on arm’s length terms. Section 3. Representations and Warranties. Each Credit Party hereby represents and warrants that: (a) after giving effect to this Amendment, therepresentations and warranties contained in Article VII of the Credit Agreement and in each other Credit Document are true and correct in all materialrespects, except for any representation and warranty that is qualified by materiality or reference to Material Adverse Effect, which such representation andwarranty shall be true and correct in all respects, on and as of the Effective Date, except to the extent that such representations and warranties specificallyrefer to an earlier date, in which case they shall be true and correct in all material respects, except for any representation and warranty that is qualified bymateriality or reference to Material Adverse Effect, which such representation and warranty shall be true and correct in all respects, as of such earlier date; (b)after giving effect to this Amendment, no Default or Event of Default has occurred and is continuing; (c) the execution, delivery and performance of thisAmendment are within the corporate or limited liability company power and authority of such Credit Party and have been duly authorized by appropriatecorporate or limited liability company action and proceedings; (d) this Amendment constitutes the legal, valid, and binding obligation of such Credit Partyenforceable in accordance with its terms, except as limited by applicable bankruptcy, insolvency, reorganization, moratorium, or similar laws affecting therights of creditors generally and general principles of equity; (e) there are no governmental or other third party consents, licenses and approvals required inconnection with the execution, delivery, performance, validity and enforceability of this Amendment; and (f) the Liens under the Credit Documents are validand subsisting and secure the Credit Parties’ obligations under such Credit Documents. Section 4. Conditions to Effectiveness. This Amendment shall become effective on the Effective Date and enforceable against the parties heretoupon the satisfaction of the following conditions precedent: (a) the Administrative Agent shall have received this Amendment duly executed by the Borrower, the Guarantors, the Administrative Agent, and theLenders party hereto (which constitute all Lenders party to the Credit Agreement); (b) the Borrower shall have paid on the Effective Date (i) all costs and expenses which are payable pursuant to Section 12.5 of the Credit Agreementand which have been invoiced no later than one Business Day prior to the date hereof and (ii) an amendment fee as provided for in that certain Fee Letter,dated as of the Effective Date, by and between Lilis and the Administrative Agent; (c) the Administrative Agent shall have received executed copies of any amendments to the Permitted Second Lien Credit Agreement executed on orabout the date hereof; and (d) the Administrative Agent shall have entered into that certain Letter Agreement, dated as of the Effective Date, by and between the AdministrativeAgent, in its capacity as Priority Lien Agent (as defined in the Amended and Restated Intercreditor Agreement), and Wilmington Trust, National Association,in its capacity as Second Lien Agent (as defined in the Amended and Restated Intercreditor Agreement), and such Letter Agreement shall be in form andsubstance satisfactory to the Administrative Agent. 2  Section 5. Acknowledgments and Agreements. (a) Each Credit Party acknowledges that on the date hereof, all outstanding Obligations are payable in accordance with their terms and each CreditParty waives any defense, offset, counterclaim or recoupment, in each case existing on the date hereof, with respect to such Obligations. Each Credit Partydoes hereby adopt, ratify, and confirm the Credit Agreement and acknowledges and agrees that the Credit Agreement is and remains in full force and effect,and each Credit Party acknowledges and agrees that its respective liabilities and obligations under the Credit Agreement are not impaired in any respect bythis Amendment. (b) This Amendment is a Credit Document for the purposes of the provisions of the other Credit Documents. Without limiting the foregoing, anybreach of representations, warranties, and covenants under this Amendment shall be a Default or Event of Default, as applicable, under the Credit Agreement. Section 6. Reaffirmation of Guaranty. Each Guarantor hereby ratifies, confirms, and acknowledges that its obligations under the Credit Agreementare in full force and effect and that each Guarantor continues to unconditionally and irrevocably, jointly and severally, guarantee the full and punctualpayment, when due, whether at stated maturity or earlier by acceleration or otherwise, of all of the Obligations, and its execution and delivery of thisAmendment does not indicate or establish an approval or consent requirement by the Guarantors in connection with the execution and delivery ofamendments, consents or waivers to the Credit Agreement or any of the other Credit Documents. Section 7. Reaffirmation of Liens. Each Credit Party (a) is party to certain Security Documents securing and supporting the Obligations under theCredit Documents, (b) represents and warrants that it has no defenses to the enforcement of the Security Documents and that according to their terms theSecurity Documents will continue in full force and effect to secure the Obligations under the Credit Documents, as the same may be amended, supplemented,or otherwise modified, and (c) acknowledges, represents, and warrants that the liens and security interests created by the Security Documents are valid andsubsisting and create an acceptable security interest in the collateral to secure the Obligations under the Credit Documents, as the same may be amended,supplemented, or otherwise modified. Section 8. Miscellaneous. Sections 12.3, 12.6, 12.9, 12.10, 12.11, 12.12, 12.13, 12.14 and 12.15 of the Credit Agreement are hereby incorporated byreference herein mutatis mutandis. 3  Section 9. RELEASE. For good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, and withoutlimitation or curtailment of any of the provisions of Section 12.5 of the Credit Agreement, each Credit Party hereby, for itself and its successors andassigns, fully and without reserve, releases, acquits, and forever discharges each Secured Party, its respective successors and assigns, officers, directors,employees, representatives, trustees, attorneys, agents and affiliates (collectively the “Released Parties” and individually a “Released Party”) from anyand all actions, claims, demands, causes of action, judgments, executions, suits, debts, liabilities, costs, damages, expenses or other obligations of anykind and nature whatsoever, direct and/or indirect, at law or in equity, whether now existing or hereafter asserted, whether absolute or contingent,whether due or to become due, whether disputed or undisputed, whether known or unknown (INCLUDING, WITHOUT LIMITATION, ANY OFFSETS,REDUCTIONS, REBATEMENT, CLAIMS OF USURY OR CLAIMS WITH RESPECT TO THE NEGLIGENCE OF ANY RELEASED PARTY)(collectively, the “Released Claims”), for or because of any matters or things occurring, existing or actions done, omitted to be done, or suffered to bedone by any of the Released Parties, in each case, on or prior to the Effective Date and are in any way directly or indirectly arising out of or in any wayconnected to any of this Amendment, the Credit Agreement, any other Credit Document, or any of the transactions contemplated hereby or thereby(collectively, the “Released Matters”). Each Credit Party, by execution hereof, hereby acknowledges and agrees that the agreements in this Section 9are intended to cover and be in full satisfaction for all or any alleged injuries or damages arising in connection with the Released Matters hereincompromised and settled. Each Credit Party hereby further agrees that it will not sue any Released Party on the basis of any Released Claim released,remised and discharged by the Credit Parties pursuant to this Section 9. In entering into this Amendment, each Credit Party consulted with, and hasbeen represented by, legal counsel and expressly disclaim any reliance on any representations, acts or omissions by any of the Released Parties andhereby agrees and acknowledges that the validity and effectiveness of the releases set forth herein do not depend in any way on any such representations,acts and/or omissions or the accuracy, completeness or validity hereof. The provisions of this Section 9 shall survive the termination of thisAmendment, the Credit Agreement and the other Credit Documents and payment in full of the Obligations. [The remainder of this page has been left blank intentionally.] 4  EXECUTED to be effective as of the date first above written. BORROWER: LILIS ENERGY, INC. By:/s/ Joseph C. Daches Name:Joseph C. Daches Title: EVP, Chief Financial Officer and Treasurer GUARANTORS: BRUSHY RESOURCES, INC. HURRICANE RESOURCES LLC LILIS OPERATING COMPANY, LLC IMPETRO OPERATING, LLC IMPETRO RESOURCES, LLC By:/s/ Joseph C. Daches Name: Joseph C. Daches Title: Chief Financial Officer and Treasurer Signature Page to Amendment No. 1 to Credit Agreement  ADMINISTRATIVE AGENT: RIVERSTONE CREDIT MANAGEMENT LLC, as Administrative Agent and Collateral Agent By: Riverstone Equity Partners LP, its sole member By: Riverstone Holdings LLC, its general partner By:/s/ Thomas J. Walker Name: Thomas J. Walker Title: Chief Financial Officer; Authorized Person Signature Page to Amendment No. 1 to Credit Agreement  LENDERS: RIVERSTONE CREDIT PARTNERS – DIRECT, L.P., as Lender By: RCP F2 GP, L.P., its general partner By: RCP F1 GP, L.L.C., its general partner By:/s/ Thomas J. Walker Name: Thomas J. Walker Title: Manager Signature Page to Amendment No. 1 to Credit Agreement  RIVERSTONE CREDIT PARTNERS II – DIRECT, L.P., as Lender By: RCP F2 GP, L.P., its general partner By: RCP F1 GP, L.L.C., its general partner By:/s/ Thomas J. Walker Name: Thomas J. Walker Title: Manager Signature Page to Amendment No. 1 to Credit Agreement  RIVERSTONE STRATEGIC CREDIT PARTNERS A-1AIV, L.P., as Lender By: RCP Strategic Credit Partners (A-2) GP, L.P., itsgeneral partner By: RCP Strategic Credit Partners (A) GP, L.L.C., itsgeneral partner By:/s/ Thomas J. Walker Name: Thomas J. Walker Title: Manager Signature Page to Amendment No. 1 to Credit Agreement  RIVERSTONE STRATEGIC CREDIT PARTNERS A-2AIV, L.P., as Lender By: RCP Strategic Credit Partners (A-2) GP, L.P., itsgeneral partner By: RCP Strategic Credit Partners (A) GP, L.L.C., itsgeneral partner By:/s/ Thomas J. Walker Name: Thomas J. Walker Title: Manager Signature Page to Amendment No. 1 to Credit Agreement  Exhibit 21.1 Subsidiaries of the Registrant Name of Subsidiary Jurisdiction of IncorporationBrushy Resources, Inc. DelawareLilis Operating Company, LLC TexasImPetro Resources, LLC DelawareImPetro Operating, LLC DelawareHurricane Resources, LLC Texas  Exhibit 23.1 Consent of Independent Registered Public Accounting Firm Lilis Energy, Inc. and SubsidiariesSan Antonio, Texas We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (No. 333-185122, No. 333-212285 and No. 333-214822) ofLilis Energy, Inc. of our reports dated March 9, 2018, relating to the consolidated financial statements and the effectiveness of Lilis Energy, Inc.'s internalcontrol over financial reporting, which appear in this Form 10-K. Our report on the effectiveness of internal control over financial reporting expresses anadverse opinion on the effectiveness of the Company's internal control over financial reporting as of December 31, 2017. /s/ BDO USA, LLP Dallas, TexasMarch 9, 2018  Exhibit 23.2 INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM’S CONSENT We consent to the incorporation by reference in the Registration Statement of Lilis Energy, Inc. on Forms S-8 (File No. 333-185122, File No. 333-212285 and File No. 333-214822) of our report dated March 3, 2017, with respect to our audit of the consolidated financial statements of Lilis Energy, Inc.and Subsidiaries as of December 31, 2016 and for the year ended December 31, 2016, which report is included in this Annual Report on Form 10-K of LilisEnergy, Inc. for the year ended December 31, 2017. /s/ Marcum LLP New York, NYMarch 9, 2018  Exhibit 23.3 Petroleum Engineer Consent and Report Certificate of Qualification Cawley, Gillespie & Associates, Inc. here by consents to the use of the name, to references to our firm in the form and context in which they appear inthe Annual Report on Form 10-K of Lilis Energy, Inc. for the year ended December 31, 2017 (the “Annual Report”). We hereby further consent to theinclusion in the Annual Report of estimates of oil and natural natural gas reserves contained in our report dated January 15, 2018, and to the inclusion of ourreport as an exhibit to the Annual Report and in all current and future registration statements of the Company that incorporate by reference such AnnualReport. /s/ Cawley, Gillespie & Associates, Inc. Cawley, Gillespie & Associates, Inc. Texas Registered Engineering Firm F-693 March 9, 2018  Exhibit 31.1 CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO 18 U.S.C. SECTION 1350,AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, James (Jim) L. Linville, certify that: 1.I have reviewed this Form 10-K of Lilis Energy, Inc.; 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 thestatements 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 thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4.The registrant's other certifying officer(s) and I am responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange 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 our supervision, to ensurethat material information relating to the registrant, including its consolidated subsidiaries, is made known to us 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 oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for externalpurposes in accordance with generally accepted accounting principles; c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectivenessof 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 fiscalquarter (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.The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant's auditors and the audit committee of the 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 reasonablylikely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b)Any fraud, whether or not material, that involved management or other employees who have a significant role in the registrant's internal control overfinancial reporting. By:/s/James (Jim) L. Linville James (Jim) L. Linville Chief Executive Officer March 9, 2018  Exhibit 31.2 CERTIFICATION OF CHIEF EXECUTIVE 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 Form 10-K of Lilis Energy, Inc.; 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 thestatements 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 thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4.The registrant's other certifying officer(s) and I am responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange 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 our supervision, to ensurethat material information relating to the registrant, including its consolidated subsidiaries, is made known to us 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 oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for externalpurposes in accordance with generally accepted accounting principles; c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectivenessof 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 fiscalquarter (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.The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant's auditors and the audit committee of the 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 reasonablylikely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b)Any fraud, whether or not material, that involved management or other employees who have a significant role in the registrant's internal control overfinancial reporting. By:/s/ Joseph C. Daches Joseph C. Daches Executive Vice President and Chief Financial Officer March 9, 2018  Exhibit 32.1 OFFICER'S CERTIFICATIONPURSUANT TOSECTION 906 OF THE SARBANES-OXLEY ACT OF 2002(18 U.S.C 1350) The undersigned, James (Jim) L. Linville, the Chief Executive Officer of Lilis Energy, Inc., (the "Corporation"), in connection with the Corporation'sYearly Report on Form 10-K for the year ended December 31, 2017, as filed with the Securities and Exchange Commission on the date hereof (the "Report"),does hereby represent, warrant and certify pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, as amended, that, to the best of his knowledge: 1.The Report is in full compliance with the reporting 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 operation of the Corporation. By:/s/ James (Jim) L. Linville James (Jim) L. Linville Chief Executive Officer March 9, 2018  Exhibit 32.2 OFFICER'S CERTIFICATIONPURSUANT TOSECTION 906 OF THE SARBANES-OXLEY ACT OF 2002(18 U.S.C 1350) The undersigned, Joseph C. Daches, the Executive Vice President and Chief Financial Officer of Lilis Energy, Inc., (the "Corporation"), inconnection with the Corporation's Yearly Report on Form 10-K for the year ended December 31, 2017, as filed with the Securities and Exchange Commissionon the date hereof (the "Report"), does hereby represent, warrant and certify pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, as amended, that, tothe best of his knowledge: 1.The Report is in full compliance with the reporting 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 operation of the Corporation. By:/s/ Joseph C. Daches Joseph C. Daches Executive Vice President and Chief Financial Officer March 9, 2018  Exhibit 99.1 EVALUATION SUMMARY LILIS ENERGY, INC. INTERESTS DELAWARE BASIN PROPERTIES IN TEXAS AND NEW MEXICO TOTAL PROVED RESERVES AS OF DECEMBER 31, 2017 Pursuant to the Guidelines of theSecurities and Exchange Commission forReporting Corporate Reserves andFuture Net Revenue  EVALUATION SUMMARY LILIS ENERGY, INC. INTERESTS DELAWARE BASIN PROPERTIES IN TEXAS AND NEW MEXICO TOTAL PROVED RESERVES AS OF DECEMBER 31, 2017 Pursuant to the Guidelines of the Securities and Exchange Commission forReporting Corporate Reserves and Future Net Revenue CAWLEY, GILLESPIE & ASSOCIATES, INC. PETROLEUM CONSULTANTS TEXAS REGISTERED ENGINEERING FIRM F-693 W. TODD BROOKER, P.E. PRESIDENT MATTHEW K. REGAN, P.E. PARTNER  CAWLEY, GILLESPIE & ASSOCIATES, INC. PETROLEUM CONSULTANTS 13640 BRIARWICK DRIVE, SUITE 100306 WEST SEVENTH STREET, SUITE 3021000 LOUISIANA STREET, SUITE 1900AUSTIN, TEXAS 78729-1107FORT WORTH, TEXAS 76102-4987HOUSTON, TEXAS 77002-5008512-249-7000817- 336-2461713-651-9944 www.cgaus.com January 10, 2018 Lilis Energy, Inc.300 E. Sonterra Blvd, Suite 1220San Antonio, TX 78258 Re:Evaluation Summary Lilis Energy, Inc. Interests Total Proved Reserves As of December 31, 2017 Pursuant to the Guidelines of the Securities and Exchange Commission for Reporting Corporate Reserves and Future Net Revenue Ladies and Gentlemen: As requested, this report was prepared on January 10, 2018 for Lilis Energy, Inc. (“LEI”) for the purpose of submitting ourestimates of proved reserves and forecasts of economics attributable to the subject interests. We have evaluated 100% of LEI reserves,which are made up of oil and gas properties in the Delaware Basin. This evaluation utilized an effective date of December 31, 2017,was prepared using constant prices and costs, and conforms to Item 1202(a)(8) of Regulation S-K and other rules of the Securities andExchange Commission (SEC). The results of this evaluation are presented in the accompanying tabulations, with a composite summaryof the values presented below: ProvedDevelopedProducingProvedDevelopedNon-ProducingProvedUndevelopedProvedDevelopedTotalProvedNet Reserves Oil- Mbbl1,674.2857.24,639.92,531.47,171.3Gas - MMcf4,298.82,295.69,465.56,594.416,059.9NGL- Mbbl422.2221.9960.5644.11,604.6Revenue Oil- M$ 79,902.340,928.5221,539.6120,830.8342,370.4Gas- M$ 11,188.35,953.824,789.017,142.141,931.0NGL- M$ 3,278.11,568.88,382.64,846.913,229.5 Severance Taxes- M$ 5,266.92,442.813,786.57,709.721,496.1Ad Valorem Taxes- M$ 2,925.41,211.37,573.24,136.611,709.8Operating Expenses- M$ 24,469.710,521.752,467.434,991.387,458.7Other Deductions- M$ 6,994.43,884.619,912.210,879.030,791.2Investments- M$ 0.06,266.4107,460.56,266.4113,726.9 Net Cash Flows- M$ 54,712.424,124.453,511.478,836.7132,348.2 Discounted @ 10%- M$ 40,043.316,609.012,159.756,652.368,812.0(Present Worth)  Lilis Energy, Inc. InterestsJanuary 10, 2018Page 2 Future revenue is prior to deducting state production taxes and ad valorem taxes. Future net cash flow is after deducting thesetaxes, future capital costs and operating expenses, but before consideration of federal income taxes. In accordance with SEC guidelines,the future net cash flow has been discounted at an annual rate of ten percent to determine its “present worth”. The present worth isshown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.The oil reserves include oil and condensate. Oil and NGL volumes are expressed in barrels (42 U.S. gallons). Gas volumes areexpressed in thousands of standard cubic feet (Mcf) at contract temperature and pressure base. Our estimates are for proved reserves only and do not include any probable or possible reserves nor have any values beenattributed to interest in acreage beyond the location for which undeveloped reserves have been estimated. The Proved Developedcategory is the summation of the Proved Developed Producing and Proved Developed Non-Producing estimates. PresentationThis report is divided into four main sections: Summary (Total Proved and Proved Developed), Proved Developed Producing(“PDP”), Proved Developed Non-Producing (“PDNP”) and Proved Undeveloped (“PUD”). Within each section are Tables I andSummary Plots. Tables II and Individual Figures and Tables are also included in the PDP, PDNP and PUD sections. The Tables I presentcomposite reserve estimates and economic forecasts for the particular reserve category or property grouping. The Summary Plots arecomposite rate-time history-forecast curves for the corresponding Table I. Following certain Summary Plots are Table II “oneline”summaries that present estimates of ultimate recovery, gross and net reserves, ownership, revenue, expenses, investments, net incomeand discounted cash flow for the individual properties that make up the corresponding Table I. Individual Figures and Tables presentreserve estimates, economic forecasts and rate-time plots on a lease or well level. For a more detailed explanation of the report layout,please refer to the Table of Contents following this letter. Hydrocarbon PricingThe base SEC oil and gas prices calculated for December 31, 2017 were $51.34/Bbl and $2.976/MMBTU, respectively. Asspecified by the SEC, a company must use a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The base oil price is based uponWTI-Cushing spot prices (Bloomberg) from January - December 2017 and the base gas price is based upon Henry Hub spot prices (GasDaily) from January - December 2017. The base prices shown above were adjusted for differentials on a per-property basis, which may include local basis differentials,transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. Natural gas liquid (NGL)prices were applied as a percentage of WTI. After these adjustments, the net realized prices for the SEC price case over the life of theproved properties was estimated to be $47.741 per barrel for oil, $2.611 per MCF for gas and $8.245 per barrel for NGLs. All economicfactors were held constant in accordance with SEC guidelines. Economic ParametersOwnership was accepted as furnished and has not been independently confirmed. Oil and gas price differentials, gas shrinkage,ad valorem taxes, severance taxes, lease operating expenses and investments were calculated and prepared by LEI and were reviewedby us for accuracy and completeness. In some cases, data was accepted as provided. Lease operating expenses were either determinedat the area or individual well level using averages calculated from historical lease operating statements. All economic parameters,including lease operating expenses and investments, were held constant (not escalated) throughout the life of these properties.  Lilis Energy, Inc. InterestsJanuary 10, 2018Page 3 SEC Conformance and RegulationsThe reserve classifications and the economic considerations used herein conform to the criteria of the SEC as defined in pages 3and 4 of the Appendix. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes androyalties currently in effect except as noted herein. The possible effects of changes in legislation or other Federal or State restrictiveactions which could affect the reserves and economics have not been considered. However, we do not anticipate nor are we aware ofany legislative changes or restrictive regulatory actions that may impact the recovery of reserves. This evaluation includes 20 proved undeveloped locations. Each of the drilling locations proposed conform to the provedundeveloped standards as set forth by the SEC. In our opinion, LEI has indicated they have every intent to complete this developmentplan as scheduled. Furthermore, LEI has indicated that they have the proper company staffing, financial backing and prior developmentsuccess to ensure this development plan will be fully executed. Reserve Estimation MethodsThe methods employed in estimating reserves are described in page 2 of the Appendix. Reserves for proved developedproducing wells were estimated using production performance methods. Certain new producing properties with little production historywere forecast using a combination of production performance and analogy to similar production, both of which are considered toprovide a relatively high degree of accuracy. Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using a combination ofvolumetric and analogy methods. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for LEI properties. The assumptions, data, methods and procedures used herein areappropriate for the purpose served by this report. General DiscussionThe estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. Tosome extent information from public records has been used to check and/or supplement these data. The basic engineering andgeological data were subject to third party reservations and qualifications. Nothing has come to our attention, however, that wouldcause us to believe that we are not justified in relying on such data. All estimates represent our best judgment based on the dataavailable at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and geologic conditions,it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual costincurred could be more or less than the estimated amounts. An on-site field inspection of the properties has not been performed. The mechanical operation or condition of the wells andtheir related facilities have not been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possibleenvironmental liability related to the properties has not been investigated nor considered. The cost of plugging and the salvage value ofequipment at abandonment have not been included.  Lilis Energy, Inc. InterestsJanuary 10, 2018Page 4 Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registeredprofessional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 50 years.This evaluation was supervised by W. Todd Brooker, President at Cawley, Gillespie & Associates, Inc. and a State of Texas LicensedProfessional Engineer (License #83462). We do not own an interest in the properties or Lilis Energy, Inc. and are not employed on acontingent basis. We have used all methods and procedures that we consider necessary under the circumstances to prepare this report.Our work-papers and related data utilized in the preparation of these estimates are available in our office. Yours very truly, CAWLEY, GILLESPIE & ASSOCIATES, INC. TEXAS REGISTERED ENGINEERING FIRM F-693 W. Todd Brooker, P. E. President  TABLE OF CONTENTSLilis Energy, Inc. InterestsDelaware Basin Properties in Texas and New MexicoAs of December 31, 2017 REPORT LETTER TABLE OF CONTENTS SUMMARY TAB·Table I & Summary Plot – TP·Table I & Summary Plot – PD PROVED DEVELOPED PRODUCING·Table I & Summary Plot – PDP·Table II – PDP (One-Line Summary Alphabetical by Lease Name)·Individual Figures and Tables 1-21 PROVED DEVELOPED NON-PRODUCING·Table I & Summary Plot – PDNP·Table II – PDNP (One-Line Summary Alphabetical by Lease Name)·Individual Figures and Tables 1-5 PROVED UNDEVELOPED·Table I & Summary Plot – PUD·Table II – PUD (One-Line Summary Alphabetical by Lease Name)·Individual Figures and Tables 1-20 APPENDIX TAB·Page 1 – Explanatory Comments for Summary Tables·Page 2 – Methods Employed in the Estimation of Reserves·Pages 3–4 – Reserve Definitions and Classifications·Page 5 – Professional Qualifications of Primary Technical Person Note:Table I’s are Grand Total Summaries of Reserves and EconomicsTable II’s are “One–Line” Lease Summaries of Economics for wells/leases in corresponding Table I’s. Summary Plots are Grand Total Rate–Time History–Forecast Curves based on the corresponding Table I. i  Table I - TPComposite Reserve Estimates and Economic Forecasts Lilis Energy, Inc. InterestsDelaware Basin Properties in Texas and New Mexico Total Proved ReservesAs of December 31, 2017(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGL EndProductionProductionProductionProductionSalesProductionPricePricePrice Mo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL 12-20181,421.34,678.7317.9851.0201,895.276189.87747.7412.6128.321 12-20191,287.64,258.9289.6760.2671,698.439170.08947.7402.6128.296 12-20201,684.95,367.6366.8939.6542,040.168204.88547.7402.6138.401 12-20211,567.54,946.1338.2805.2191,744.817175.04547.7402.6138.380 12-20221,028.43,308.9225.5545.2991,205.989120.53947.7382.6118.263 12-2023802.12,611.8177.6430.385963.82596.11847.7362.6108.191 12-2024669.82,198.6149.4361.778817.06081.35947.7352.6098.143 12-2025572.31,902.6129.1310.271710.25870.64847.7432.6098.110 12-2026504.31,687.9114.5274.175632.05862.82647.7462.6088.089 12-2027452.71,520.3103.1246.611570.55456.69047.7462.6088.076 12-2028409.51,386.994.0222.957521.27051.78347.7462.6088.070 12-2029372.91,266.285.8203.090476.28547.31047.7462.6088.067 12-2030342.61,163.578.9186.636437.76443.48247.7462.6088.067 12-2031315.21,070.472.6171.703402.74140.00447.7462.6088.066 12-2032290.8987.466.9158.391371.51636.90247.7462.6088.066 12-2033266.7905.861.4145.313340.84133.85547.7462.6088.066 12-2034245.4833.456.5133.695313.59231.14947.7462.6088.066 12-2035222.4751.151.0120.961282.39928.05047.7462.6088.052 12-2036194.6635.043.2104.346234.70123.36647.7462.6098.145 S Tot12,651.041,481.22,822.06,971.77215,659.5521,563.97747.7412.6118.232 After400.71,186.781.7199.567400.37540.59247.7462.6198.728 Total13,051.642,667.92,903.67,171.33916,059.9271,604.57047.7412.6118.245 Cum2,501.679,422.6.0 Ult15,553.2122,090.52,903.6 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/ BOE6 Mo-YearM$M$M$M$M$M$M$M$ 12-201840,628.1594,950.6591,579.9610.0000.00047,158.7792,563.8151,428.8724.693 12-201936,295.2904,435.9811,411.1340.0000.00042,142.4052,343.7111,322.3905.455 12-202044,859.3955,331.9321,721.1870.0000.00051,912.5132,803.2541,524.7305.634 12-202138,441.1004,559.3931,466.8520.0000.00044,467.3452,361.4061,261.5226.668 12-202226,031.3043,149.093996.0090.0000.00030,176.4061,617.013870.4888.411 12-202320,544.9672,515.646787.3500.0000.00023,847.9641,282.495692.1529.847 12-202417,269.6002,131.950662.5320.0000.00020,064.0821,081.100584.14311.143 12-202514,813.3071,852.875572.9780.0000.00017,239.160930.922503.35412.241 12-202613,090.8321,648.645508.1970.0000.00015,247.674824.393445.96413.361 12-202711,774.7211,488.105457.8510.0000.00013,720.678742.076401.43514.494 12-202810,645.3441,359.509417.8820.0000.00012,422.735672.196363.39215.431 12-20299,696.7741,242.165381.6570.0000.00011,320.595612.911331.41316.578 12-20308,911.1671,141.696350.7520.0000.00010,403.614563.314304.61817.791 12-20318,198.1611,050.355322.6880.0000.0009,571.204518.245280.24719.094 12-20327,562.552968.920297.6700.0000.0008,829.142478.065258.52020.463 12-20336,938.131888.919273.0920.0000.0008,100.142438.592237.17422.051 12-20346,383.445817.852251.2590.0000.0007,452.556403.528218.21323.723 12-20355,775.419736.436225.8650.0000.0006,737.719365.152197.79225.407 12-20364,982.143612.375190.3140.0000.0005,784.831314.494171.69427.048 S Tot332,841.81140,882.50512,875.2290.0000.000386,599.54420,916.68111,398.11310.315 After9,528.5561,048.535354.2760.0000.00010,931.366579.445311.68430.489 Total342,370.36741,931.03913,229.5040.0000.000397,530.91121,496.12611,709.79710.858 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash Flow EndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. % Mo-YearM$CountM$M$M$M$M$M$M$ 12-20182,401.0642519.70.0000.0003,655.00232,988.4094,121.6184,121.6183,341.770 12-20193,092.3902922.60.0000.0003,201.84238,783.407-6,601.336-2,479.718-2,408.935 12-20203,976.4493727.10.0000.0003,984.00741,955.067-2,330.995-4,810.713-4,307.497 12-20214,572.0103727.50.0000.0003,494.574.00032,777.83427,967.12119,283.317 12-20224,589.8353727.50.0000.0002,346.323.00020,752.74748,719.86732,838.394 12-20234,589.8353727.50.0000.0001,845.323.00015,438.15864,158.02641,999.679 12-20244,589.8353727.50.0000.0001,548.079.00012,260.92576,418.95148,611.585 12-20254,471.9973727.50.0000.0001,337.075.0009,995.81386,414.76453,510.381 12-20264,431.8163526.10.0000.0001,184.652.0008,360.84994,775.61357,235.079 12-20274,420.2903526.10.0000.0001,066.417.0007,090.459101,866.07260,106.564 12-20284,334.0883425.20.0000.000966.304.0006,086.756107,952.82862,347.356 12-20294,312.7083324.30.0000.000879.946.0005,183.617113,136.44564,081.934 12-20304,312.7083324.30.0000.000808.604.0004,414.371117,550.81665,424.948 12-20314,312.7083223.50.0000.000743.901.0003,716.102121,266.91866,452.890 12-20324,312.7083223.50.0000.000686.226.0003,093.623124,360.54167,230.985 12-20334,312.7083223.50.0000.000629.566.0002,482.101126,842.64267,798.491 12-20344,312.7083223.50.0000.000579.234.0001,938.873128,781.51568,201.608 12-20354,208.5073223.50.0000.000523.719.0001,442.549130,224.06468,474.374 12-20363,840.4903122.70.0000.000450.686.0001,007.467131,231.53168,647.748 S Tot79,394.855 0.0000.00029,931.480113,726.884131,231.531131,231.53168,647.748 After8,063.861 0.0000.000859.725.0001,116.651132,348.18268,812.012 Total87,458.716 0.0000.00030,791.205113,726.884132,348.182132,348.18268,812.012 SEC Pricing YE2017 PercentCum. Disc. WTI CushingHenry Hub 5.0093,465.060 YearOil $/STBGas $/MMBTU 8.0077,447.306 201851.342.976 10.0068,812.012 ThereafterFlatFlat 12.0061,444.979 Cap51.342.976 15.0052,274.588 20.0040,670.721 12 Months in first year 25.065 Year Life (01/2043) THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.TEXAS REGISTERED ENGINEERING FIRM F-693.1/10/2018 10:34:17Summary Cawley, Gillespie & Associates, Inc.   Table I - PDComposite Reserve Estimates and Economic Forecasts Lilis Energy, Inc. InterestsDelaware Basin Properties in Texas and New Mexico Proved Developed ReservesAs of December 31, 2017(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGL EndProductionProductionProductionProductionSalesProductionPricePricePrice Mo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL 12-2018955.43,280.8221.5594.9851,372.964136.87847.7332.6098.145 12-2019535.82,003.8134.0333.593828.02481.76747.7252.6047.848 12-2020378.41,448.296.3235.285603.25559.08147.7112.6017.645 12-2021297.41,135.975.2184.836479.23546.62647.7062.5987.490 12-2022247.8967.063.9153.969407.67639.53447.7022.5977.393 12-2023213.5846.055.8132.666356.47834.49047.6992.5967.326 12-2024188.8755.549.7117.257318.23630.74347.6972.5957.281 12-2025164.2678.544.7102.205285.80327.57947.7322.5957.250 12-2026147.4617.540.691.852260.11725.08547.7462.5947.235 12-2027134.7566.337.383.839238.50022.99647.7462.5947.232 12-2028121.3522.234.475.247219.94121.20747.7462.5947.232 12-2029110.5479.131.568.529201.78119.45647.7462.5947.232 12-2030101.7440.829.063.050185.64917.90047.7462.6128.425 12-203193.5405.626.758.010170.80616.46947.7462.6178.728 12-203286.4374.124.653.512157.56415.19247.7462.6178.728 12-203379.2343.222.649.094144.55413.93847.7462.6178.728 12-203472.8315.820.845.169132.99712.82347.7462.6178.728 12-203563.7274.918.139.511116.24411.19047.7462.6178.728 12-203648.2195.712.829.21281.4277.81347.7462.6158.728 S Tot4,040.815,650.61,039.72,511.8216,561.249640.76747.7262.6037.758 After33.284.35.619.57733.1963.33447.7462.6198.728 Total4,073.915,734.91,045.32,531.3976,594.446644.10247.7262.6037.764 Cum2,501.679,422.60.0 Ult6,575.695,157.51,045.3 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/ BOE6 Mo-YearM$M$M$M$M$M$M$M$ 12-201828,403.4553,582.7871,117.4030.0000.00033,103.6461,759.560961.6652.203 12-201915,923.2262,156.468640.2970.0000.00018,719.9911,000.332540.2733.994 12-202011,228.4361,568.828448.6600.0000.00013,245.923717.284382.8935.363 12-20218,820.1731,244.987346.0570.0000.00010,411.217564.058301.0586.686 12-20227,346.7831,058.406289.0250.0000.0008,694.214471.549251.3587.966 12-20236,330.002925.076249.4850.0000.0007,504.564407.330216.9209.196 12-20245,594.628825.590220.7750.0000.0006,640.994360.636191.92510.366 12-20254,878.936741.278197.0820.0000.0005,817.295316.957168.57611.055 12-20264,385.548674.576178.8080.0000.0005,238.932285.829151.97111.976 12-20274,002.996618.495163.7850.0000.0004,785.276260.899138.55313.014 12-20283,592.738570.365151.0270.0000.0004,314.129235.288124.54513.658 12-20293,272.002523.271138.5570.0000.0003,933.828214.748113.65914.767 12-20303,010.413481.437127.4800.0000.0003,619.328197.579104.57316.050 12-20312,769.738442.947117.2870.0000.0003,329.973181.78396.21217.445 12-20322,554.999408.605108.1940.0000.0003,071.797167.69088.75318.911 12-20332,344.039374.86799.2610.0000.0002,818.167153.84581.42520.613 12-20342,156.639344.89891.3250.0000.0002,592.862141.54574.91522.404 12-20351,886.534301.29278.7170.0000.0002,266.544124.11465.95024.050 12-20361,394.767210.96854.5750.0000.0001,660.31092.14450.07425.555 S Tot119,896.05117,055.1434,817.7970.0000.000141,768.9907,653.1694,105.2988.498 After934.73286.93729.1030.0000.0001,050.77256.49231.33329.844 Total120,830.78217,142.0814,846.9000.0000.000142,819.7637,709.6614,136.6318.642 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash Flow EndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. % Mo-YearM$CountM$M$M$M$M$M$M$ 12-20182,010.4552016.10.0000.0002,558.8346,266.40919,546.72419,546.72418,579.723 12-20192,095.5721915.30.0000.0001,426.8060.00013,657.00933,203.73230,467.687 12-20202,006.9551814.30.0000.0001,002.5300.0009,136.26142,339.99337,687.922 12-20211,972.4321713.90.0000.000783.8030.0006,789.86749,129.85942,562.783 12-20221,972.4321713.90.0000.000650.5860.0005,348.29154,478.15046,052.651 12-20231,972.4321713.90.0000.000559.1380.0004,348.74458,826.89448,631.950 12-20241,972.4321713.90.0000.000493.3340.0003,622.66562,449.55950,584.956 12-20251,854.5931713.90.0000.000440.4170.0003,036.75465,486.31352,072.912 12-20261,814.4131512.50.0000.000399.4230.0002,587.29668,073.60753,225.364 12-20271,802.8861512.50.0000.000365.7130.0002,217.22470,290.83154,123.217 12-20281,716.6841411.50.0000.000330.6530.0001,906.95872,197.78954,825.254 12-20291,695.3051310.70.0000.000301.0260.0001,609.08973,806.88055,363.734 12-20301,695.3051310.70.0000.000276.9600.0001,344.91275,151.79255,772.955 12-20311,695.305129.90.0000.000254.8180.0001,101.85476,253.64556,077.800 12-20321,695.305129.90.0000.000235.0620.000884.98877,138.63356,300.453 12-20331,695.305129.90.0000.000215.6530.000671.94077,810.57356,454.139 12-20341,695.305129.90.0000.000198.4130.000482.68478,293.25956,554.553 12-20351,591.103129.90.0000.000173.3430.000312.03578,605.29356,613.617 12-20361,223.087119.00.0000.000127.4750.000167.53078,772.82356,642.563 S Tot34,177.305 0.0000.00010,793.9866,266.40978,772.82378,772.82356,642.563 After814.045 0.0000.00084.9900.00063.91278,836.73556,652.286 Total34,991.349 0.0000.00010,878.9766,266.40978,836.73578,836.73556,652.286 SEC Pricing YE2017 PercentCum. Disc. WTI CushingHenry Hub 5.0065,629.632 YearOil $/STBGas $/MMBTU 8.0059,869.324 201851.342.976 10.0056,652.286 ThereafterFlatFlat 12.0053,829.641 Cap51.342.976 15.0050,191.214 20.0045,322.838 12 Months in first year 21.656 Year Life (08/2039) THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.TEXAS REGISTERED ENGINEERING FIRM F-693.1/10/2018 10:34:19Summary Cawley, Gillespie & Associates, Inc.   Table I - PDPComposite Reserve Estimates and Economic Forecasts Lilis Energy, Inc. InterestsDelaware Basin Properties in Texas and New MexicoProved Developed Producing ReservesAs of December 31, 2017(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGL EndProductionProductionProductionProductionSalesProductionPricePricePrice Mo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL 12-2018594.92,156.8144.9368.734897.34889.37347.7332.6098.145 12-2019342.71,352.190.0211.963552.01054.52347.7252.6047.848 12-2020251.4992.865.8155.336410.73840.25047.7112.6017.645 12-2021201.3775.851.2124.337327.17831.84247.7062.5987.490 12-2022169.6664.543.8104.729280.01527.17447.7022.5977.393 12-2023147.2583.538.490.903245.76123.80247.6992.5967.326 12-2024130.8522.434.380.759219.96121.27547.6972.5957.281 12-2025112.8469.730.969.856197.80619.11247.7322.5957.250 12-2026101.1428.128.162.672180.27117.40947.7462.5947.235 12-202792.4393.025.857.217165.47515.97847.7462.5947.232 12-202884.4362.523.852.139152.63214.73847.7462.5947.232 12-202977.4332.621.847.834140.02913.52147.7462.5947.232 12-203071.2239.416.144.009101.26610.11047.7462.6128.425 12-203165.5208.214.140.49188.1758.88047.7462.6178.728 12-203260.5192.013.037.35281.3398.19147.7462.6178.728 12-203355.5176.211.934.26874.6237.51547.7462.6178.728 12-203451.0162.111.031.52868.6576.91447.7462.6178.728 12-203543.6133.59.126.96157.0475.75347.7462.6178.728 12-203629.782.05.517.67433.7533.38547.7462.6158.728 S Tot2,683.210,227.0679.61,658.7624,274.082419.74647.7262.6037.758 After26.564.14.215.42624.7282.47547.7462.6198.728 Total2,709.610,291.1683.81,674.1874,298.810422.22147.7262.6037.764 Cum2,501.679,422.6.0 Ult5,211.389,713.7683.8 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/ BOE6 Mo-YearM$M$M$M$M$M$M$M$ 12-201817,600.8162,341.184727.9330.0000.00020,669.9341,147.159650.8225.307 12-201910,115.8691,437.635427.8820.0000.00011,981.386666.019371.8087.054 12-20207,411.1701,068.354307.7070.0000.0008,787.231492.786271.4268.283 12-20215,931.553850.165238.4960.0000.0007,020.214392.893216.2839.547 12-20224,995.767727.204200.9030.0000.0005,923.874331.453182.09910.784 12-20234,335.994637.999174.3750.0000.0005,148.368288.015158.01511.984 12-20243,852.003570.873154.9050.0000.0004,577.781256.057140.34513.133 12-20253,334.394513.258138.5660.0000.0003,986.218224.085122.79913.638 12-20262,992.331467.709125.9590.0000.0003,585.999201.962110.64814.466 12-20272,731.898429.312115.5490.0000.0003,276.759184.348100.84015.458 12-20282,489.415395.991106.5780.0000.0002,991.984167.88291.49116.344 12-20292,283.871363.29597.7780.0000.0002,744.943154.02083.93717.582 12-20302,101.281264.51485.1770.0000.0002,450.971136.09075.36420.272 12-20311,933.289230.73277.5000.0000.0002,241.521124.19269.00122.117 12-20321,783.400212.84371.4910.0000.0002,067.734114.56463.65123.734 12-20331,636.149195.26965.5890.0000.0001,897.007105.10558.39625.611 12-20341,505.343179.65860.3450.0000.0001,745.34696.70253.72727.587 12-20351,287.308149.26350.2140.0000.0001,486.78582.85646.45629.473 12-2036843.88388.27129.5420.0000.000961.69655.58932.60930.733 S Tot79,165.73411,123.5293,256.4860.0000.00093,545.7495,221.7772,899.71711.638 After736.52864.75921.6030.0000.000822.89045.10925.63632.825 Total79,902.26111,188.2893,278.0900.0000.00094,368.6405,266.8862,925.35311.806 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash Flow EndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. % Mo-YearM$CountM$M$M$M$M$M$M$ 12-20181,524.9491511.90.0000.0001,534.043.00015,812.96115,812.96115,183.947 12-20191,519.0121411.10.0000.000875.110.0008,549.43724,362.39822,622.415 12-20201,430.3951310.10.0000.000639.949.0005,952.67530,315.07327,325.808 12-20211,395.872129.70.0000.000509.445.0004,505.72234,820.79430,560.390 12-20221,395.872129.70.0000.000427.296.0003,587.15538,407.94932,900.919 12-20231,395.872129.70.0000.000369.759.0002,936.70741,344.65634,642.637 12-20241,395.872129.70.0000.000327.832.0002,457.67443,802.33035,967.546 12-20251,278.033129.70.0000.000293.729.0002,067.57345,869.90336,980.590 12-20261,237.853108.30.0000.000267.107.0001,768.42947,638.33137,768.274 12-20271,226.326108.30.0000.000244.996.0001,520.24849,158.57938,383.882 12-20281,198.53097.30.0000.000225.975.0001,308.10550,466.68438,865.457 12-20291,198.53097.30.0000.000207.317.0001,101.13851,567.82339,233.957 12-20301,176.81397.30.0000.000190.742.000871.96252,439.78539,499.393 12-20311,172.76186.50.0000.000175.493.000700.07353,139.85839,693.091 12-20321,172.76186.50.0000.000161.887.000554.87153,694.72939,832.705 12-20331,172.76186.50.0000.000148.520.000412.22554,106.95439,927.003 12-20341,172.76186.50.0000.000136.647.000285.50954,392.46439,986.414 12-20351,068.55986.50.0000.000116.515.000172.39954,564.86340,019.065 12-2036708.45775.70.0000.00075.237.00089.80454,654.66740,034.550 S Tot23,841.988 0.0000.0006,927.600.00054,654.66754,654.66740,034.550 After627.671 0.0000.00066.779.00057.69554,712.36240,043.286 Total24,469.659 0.0000.0006,994.379.00054,712.36254,712.36240,043.286 SEC Pricing YE2017 PercentCum. Disc. WTI CushingHenry Hub 5.0045,984.035 YearOil $/STBGas $/MMBTU 8.0042,172.462 201851.342.976 10.0040,043.286 ThereafterFlatFlat 12.0038,175.239 Cap51.342.976 15.0035,768.002 20.0032,549.673 12 Months in first year 21.656 Year Life (08/2039) THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.TEXAS REGISTERED ENGINEERING FIRM F-693.1/10/2018 10:34:19Summary Cawley, Gillespie & Associates, Inc.   Table II - PDPLease Reserve SummaryLilis Energy, Inc. InterestsDelaware Basin Properties in Texas and New MexicoProved Developed Producing ReservesAs of December 31, 2017 CurrentWellCntUltimateGrossNetOil RevenueProd TaxExpensesFuture NetCash FlowOPERATORInterestLifeRecoveryReservesReservesGas RevenueAdv. TaxInvestmentsCash FlowDisc.@ 10.0LEASE NAMEStart % _____________MBBL / MMCF______________M$ / M$M$ / M$M$ / M$M$M$TableClassMajorWell No.DateASNPHANTOM (WOLFCAMP) -- WINKLER COUNTY, TEXASIMPETRO OPERATING LLC BISON #1H 59.2198 NI1636.4451.8267.612,774.8697.54,550.38,604.35,965.71PDPOil1H 33177.7399 WI21.71,508.51,084.3411.01,076.3355.20.0 GRIZZLY #1H 61.0414 NI1381.9285.5174.38,321.1520.93,768.45,596.04,098.62PDPOil1H33286.6526 WI17.41,713.11,334.7521.41,365.6253.50.0 CHEYENNE (ATOKA) -- WINKLER COUNTY, TEXASTRATON OPERATING COMPANY HILL, A. G. 1 58.3125 NI11.10.00.00.0120.4313.31,451.4966.83 PDPGas114077.7500 WI12.25,632.61,727.6715.31,809.348.30.0 PHANTOM (WOLFCAMP B) -- WINKLER COUNTY, TEXASLILIS ENERGY, INC. HIPPO #1H 75.1094 NI1396.1291.1218.610,438.0604.24,187.46,971.25,138.14PDPOil1H224100.0000 WI18.21,072.4852.5461.01,207.4301.60.0 PHANTOM (WOLFCAMP) -- WINKLER COUNTY, TEXASIMPETRO OPERATING LLC KUDU #1H 60.1633 NI1227.7133.380.23,828.6230.91,803.62,400.71,624.75PDPOil1H2879.2604 WI19.01,021.9508.7211.2546.8113.70.0 PHANTOM (WOLFCAMP B) -- WINKLER COUNTY, TEXASLILIS ENERGY, INC. LION #1H 65.9402 NI1369.2314.8207.69,910.5618.14,171.46,954.35,149.06PDPOil31992.4753 WI18.11,544.51,358.3609.01,595.0301.10.0 JABALINA (WOLFCAMP, SOUTHWEST) -- LEA COUNTY, NEW MEXICOIMPETRO OPERATING, LLC MEXICO P FEDERAL 001 75.7412 NI130.318.614.1671.547.6381.7208.6160.27PDPOil00113397.0634 WI9.782.40.00.00.033.60.0 TBD (WOLFCAMP B) -- LEA COUNTY, NEW MEXICOLILIS ENERGY, INC. PRIZE HOG BWZ ST COM1H 52.8125 NI1433.3416.3219.910,497.4823.33,360.86,734.15,016.18PDPOil#1H31765.0000 WI19.8823.2791.0284.1743.9574.60.0 HALEY (LWR. WOLFCAMP-PENN CONS.) -- LOVING COUNTY, TEXASIMPETRO OPERATING LLC SHAMMO C24-4 1 37.5264 NI00.9 Non-Commercial 9PDPGas16850.0000 WI0.0342.7 PHANTOM (WOLFCAMP B) -- WINKLER COUNTY, TEXASLILIS ENERGY, INC. TIGER 1H 71.0940 NI1380.3364.6259.212,376.1747.94,284.29,323.17,124.910PDPOil32287.1825 WI19.41,445.21,385.5669.81,754.1368.10.0 CRITTENDON (ATOKA OOLITIC) -- WINKLER COUNTY, TEXASIMPETRO OPERATING LLC TUBB 1 UNIT 1 34.6270 NI00.2 Non-Commercial 11PDPGas12446.4836 WI0.0713.2 CRITTENDON (MORROW) -- WINKLER COUNTY, TEXASIMPETRO OPERATING LLC TUBB 22 UNIT 1R 60.7747 NI00.6 Non-Commercial 12PDPGas 1R10484.1536 WI0.02,462.5 THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.TEXAS REGISTERED ENGINEERING FIRM F-693.Scenario: .0001/10/2018 10:34:19 AM Cawley, Gillespie & Associates, Inc. Page 1  Table II - PDP (cont.)Lease Reserve SummaryLilis Energy, Inc. InterestsDelaware Basin Properties in Texas and New MexicoProved Developed Producing ReservesAs of December 31, 2017 CurrentWellCntUltimateGrossNetOil RevenueProd TaxExpensesFuture NetCash FlowOPERATORInterestLifeRecoveryReservesReservesGas RevenueAdv. TaxInvestmentsCash FlowDisc.@ 10.0LEASE NAMEStart % _____________MBBL / MMCF______________M$ / M$M$ / M$M$ / M$M$M$TableClassMajorWell No.DateASNCRITTENDON (MORROW) -- WINKLER COUNTY, TEXASIMPETRO OPERATING LLC TUBB 9 UNIT 1 36.5956 NI03.0 Non-Commercial 13PDPGas1 9448.7061 WI0.01,418.6 CRITTENDON (BRUSHY CANYON) -- WINKLER COUNTY, TEXASIMPETRO OPERATING LLC TUBB ESTATE 1-75 1 42.7447 NI074.3 Non-Commercial 14PDPOil1 2355.3225 WI0.089.7 TUBB ESTATE 21 2 64.2033 NI028.5 Non-Commercial 15PDPOil2 8888.5433 WI0.019.5 CRITTENDON (ELLEN. 21450) -- WINKLER COUNTY, TEXASIMPETRO OPERATING LLC TUBB ESTATE 25 1 54.8634 NI00.0 Non-Commercial 16PDPGas1 9967.9589 WI0.060.5 CRITTENDON (BRUSHY CANYON) -- WINKLER COUNTY, TEXASIMPETRO OPERATING LLC TUBB ESTATE 25 3 74.0852 NI114.33.02.2109.75.392.911.811.117PDPOil3 7191.5312 WI1.914.51.80.82.22.80.0 TBD (WOLFCAMP B) -- LEA COUNTY, NEW MEXICOLILIS ENERGY, INC. WILD HOG BWX ST COM1H 52.8125 NI1424.9367.9194.39,277.2753.33,209.75,994.04,408.118PDPOil#1H 31465.0000 WI19.41,012.2956.6343.5899.7524.10.0 CRITTENDON (BRUSHY CANYON) -- WINKLER COUNTY, TEXASIMPETRO OPERATING LLC WOLFE UNIT #3H 68.9935 NI132.90.10.02.20.10.21.81.819PDPOil3H 11185.4277 WI1.00.00.00.00.00.10.0 CRITTENDON (PENN.) -- WINKLER COUNTY, TEXASIMPETRO OPERATING LLC WOLFE UNIT 1 38.7307 NI1766.70.00.00.017.3193.812.811.820PDPGas1 5048.1433 WI2.467,841.6273.065.6171.75.70.0 CRITTENDON (BELL CANYON) -- WINKLER COUNTY, TEXASIMPETRO OPERATING LLC WOLFE UNIT 4,5&6 57.8050 NI21,008.662.836.31,695.179.91,146.3448.0366.121PDPOil5,6&7 1568.5740 WI7.3895.017.16.116.442.90.0 GRAND TOTAL 155,211.32,709.61,674.279,902.35,266.931,464.054,712.440,043.3 89,713.710,291.14,298.811,188.32,925.40.0 THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.TEXAS REGISTERED ENGINEERING FIRM F-693.Scenario: .0001/10/2018 10:34:19 AM Cawley, Gillespie & Associates, Inc. Page 2  Rate-Time History-Forecast CurvesAndTabular Reserves and EconomicsBy Property Cawley, Gillespie & Associates, Inc.Petroleum Consultants   Table 1Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Developed Producing ReservesIMPETRO OPERATING LLC -- BISON #1H 1HPHANTOM \(WOLFCAMP\) FIELD -- Winkler COUNTY, TEXAS(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGL EndProductionProductionProductionProductionSalesProductionPricePricePrice Mo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL 12-201883.5200.512.749.47075.9857.54847.7462.6198.728 12-201953.7128.98.231.80648.8554.85347.7462.6198.728 12-202040.597.36.223.99736.8593.66147.7462.6198.728 12-202132.778.55.019.37929.7662.95747.7462.6198.728 12-202227.766.44.216.38625.1692.50047.7462.6198.728 12-202324.157.83.714.25421.8932.17547.7462.6198.728 12-202421.451.43.312.68319.4811.93547.7462.6198.728 12-202519.246.22.911.39317.5001.73847.7462.6198.728 12-202617.542.12.710.38515.9511.58447.7462.6198.728 12-202716.138.72.59.54114.6551.45647.7462.6198.728 12-202814.935.72.38.80213.5191.34347.7462.6198.728 12-202913.632.72.18.07512.4031.23247.7462.6198.728 12-203012.530.11.97.42911.4111.13347.7462.6198.728 12-203111.527.71.86.83510.4991.04347.7462.6198.728 12-203210.625.61.66.3059.685.96247.7462.6198.728 12-20339.823.41.55.7858.885.88347.7462.6198.728 12-20349.021.61.45.3228.175.81247.7462.6198.728 12-20358.319.81.34.8977.521.74747.7462.6198.728 12-20367.618.31.24.5176.938.68947.7462.6198.728 S Tot434.41,042.666.3257.261395.15239.25147.7462.6198.728 After17.441.72.710.29615.8151.57147.7462.6198.728 Total451.81,084.368.9267.557410.96840.82247.7462.6198.728 Cum184.6424.2.0 Ult636.41,508.568.9 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6 Mo-YearM$M$M$M$M$M$M$M$ 12-20182,361.982198.99665.8730.0000.0002,626.852128.97265.6715.613 12-20191,518.638127.94542.3530.0000.0001,688.93682.92242.2236.896 12-20201,145.74896.52931.9540.0000.0001,274.23062.56131.8568.065 12-2021925.25877.95325.8040.0000.0001,029.01550.52225.7259.200 12-2022782.38265.91521.8200.0000.000870.11742.72021.75310.277 12-2023680.55257.33618.9800.0000.000756.86837.16018.92211.320 12-2024605.55251.01816.8880.0000.000673.45833.06516.83612.313 12-2025543.99345.83115.1710.0000.000604.99629.70415.12513.333 12-2026495.84641.77513.8290.0000.000551.45027.07513.78614.307 12-2027455.55938.38112.7050.0000.000506.64524.87512.66615.280 12-2028420.23935.40511.7200.0000.000467.36422.94611.68416.286 12-2029385.54132.48210.7520.0000.000428.77521.05210.71917.455 12-2030354.71829.8859.8930.0000.000394.49619.3699.86218.685 12-2031326.35927.4969.1020.0000.000362.95717.8209.07420.021 12-2032301.05625.3648.3960.0000.000334.81616.4398.37021.426 12-2033276.19923.2707.7030.0000.000307.17215.0817.67923.057 12-2034254.11821.4097.0870.0000.000282.61413.8767.06524.774 12-2035233.80219.6986.5200.0000.000260.02012.7666.50026.639 12-2036215.67518.1716.0150.0000.000239.86011.7775.99728.601 S Tot12,283.2181,034.857342.5650.0000.00013,660.639670.701341.51611.743 After491.61241.41813.7100.0000.000546.74126.84413.66932.708 Total12,774.8301,076.275356.2750.0000.00014,207.380697.545355.18412.550 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash Flow EndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. % Mo-YearM$CountM$M$M$M$M$M$M$ 12-2018154.85810.80.0000.000221.447.0002,055.9042,055.9041,970.292 12-2019154.85810.80.0000.000142.379.0001,266.5533,322.4573,071.785 12-2020154.85810.80.0000.000107.419.000917.5364,239.9933,796.607 12-2021154.85810.80.0000.00086.747.000711.1624,951.1554,307.067 12-2022154.85810.80.0000.00073.352.000577.4335,528.5894,683.780 12-2023154.85810.80.0000.00063.805.000482.1236,010.7124,969.684 12-2024154.85810.80.0000.00056.773.000411.9256,422.6375,191.715 12-2025154.85810.80.0000.00051.002.000354.3076,776.9445,365.292 12-2026154.85810.80.0000.00046.488.000309.2437,086.1875,503.016 12-2027154.85810.80.0000.00042.711.000271.5357,357.7225,612.957 12-2028154.85810.80.0000.00039.399.000238.4767,596.1995,700.739 12-2029154.85810.80.0000.00036.146.000206.0007,802.1995,769.667 12-2030154.85810.80.0000.00033.256.000177.1507,979.3495,823.560 12-2031154.85810.80.0000.00030.598.000150.6078,129.9565,865.218 12-2032154.85810.80.0000.00028.225.000126.9248,256.8805,897.139 12-2033154.85810.80.0000.00025.895.000103.6588,360.5385,920.837 12-2034154.85810.80.0000.00023.825.00082.9908,443.5285,938.089 12-2035154.85810.80.0000.00021.920.00063.9758,507.5035,950.182 12-2036154.85810.80.0000.00020.221.00047.0098,554.5125,958.266 S Tot2,942.3010.0000.0001,151.608.0008,554.5128,554.512 5,958.266 After410.3010.0000.00046.091.00049.8378,604.348 5,965.748 Total3,352.6030.0000.0001,197.699.0008,604.3488,604.348 5,965.748 Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeinDef InitialFinalUnits InitialFinal 5.007,006.537 Oil Rate9,430.487.bbls/mo 56.1%1.200.0% 16,598.16,598.$/w/mo Expense77.739977.7399 8.006,334.257 Gas Rate22,632.1,169.Mcf/mo 0.0%0.000.0% Revenue 10.005,965.748 GOR2,400.2,400.scf/bbl Oil59.219859.2198 12.005,646.640 NGL Rate1,419.76.bbls/mo Gas59.219859.2198 15.005,241.246 NGL Yield62.765.4bbl/MMcf 20.004,709.444 Gas Shrinkage38.035.5% Oil Severance4.64.6% Gas Severance7.57.5% NGL Severance7.57.5% Ad Valorem39.4 % 12 Months in first year 21.656 Year Life (08/2039) THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.TEXAS REGISTERED ENGINEERING FIRM F-693.ASN 331DEFAULT 1/10/2018 10:34:19OIL PDPTable 1 Cawley, Gillespie & Associates, Inc.   Table 2Reserve Estimates and Economic Forecasts as of December 31, 2017 Lilis Energy, Inc. InterestsProved Developed Producing Reserves IMPETRO OPERATING LLC -- GRIZZLY #1H 1HPHANTOM \(WOLFCAMP\) FIELD -- Winkler COUNTY, TEXAS(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGL EndProductionProductionProductionProductionSalesProductionPricePricePrice Mo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL 12-201855.3258.616.433.766101.02910.03547.7462.6198.728 12-201936.1168.910.722.05565.9886.55547.7462.6198.728 12-202027.4128.28.216.74550.1034.97747.7462.6198.728 12-202122.2103.96.613.57040.6014.03347.7462.6198.728 12-202218.888.15.611.50034.4073.41847.7462.6198.728 12-202316.476.74.910.01829.9742.97747.7462.6198.728 12-202414.668.34.38.92426.7012.65247.7462.6198.728 12-202513.161.53.98.02424.0072.38547.7462.6198.728 12-202612.056.03.67.31821.8972.17547.7462.6198.728 12-202711.051.53.36.72620.1231.99947.7462.6198.728 12-202810.247.53.06.20418.5631.84447.7462.6198.728 12-20299.343.62.85.69217.0301.69247.7462.6198.728 12-20308.640.12.55.23715.6691.55647.7462.6198.728 12-20317.936.92.34.81814.4161.43247.7462.6198.728 12-20327.334.02.24.44513.2981.32147.7462.6198.728 12-20336.731.22.04.07812.2001.21247.7462.6198.728 12-20346.128.71.83.75211.2251.11547.7462.6198.728 05-20352.310.8.71.4064.206.41847.7462.6198.728 12-2036 S Tot285.51,334.784.9174.277521.43651.79447.7462.6198.728 After.0.0.0.000.000.000.000.000.000 Total285.51,334.784.9174.277521.43651.79447.7462.6198.728 Cum96.3378.4.0 Ult381.91,713.184.9 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6 Mo-YearM$M$M$M$M$M$M$M$ 12-20181,612.209264.58287.5830.0000.0001,964.374100.91949.1095.663 12-20191,053.033172.81557.2060.0000.0001,283.05465.91632.0767.258 12-2020799.534131.21343.4350.0000.000974.18150.04824.3558.716 12-2021647.917106.33035.1980.0000.000789.44540.55719.73610.133 12-2022549.07090.10929.8280.0000.000669.00734.37016.72511.478 12-2023478.33078.49925.9850.0000.000582.81529.94214.57012.783 12-2024426.08969.92623.1470.0000.000519.16326.67212.97914.024 12-2025383.09962.87120.8120.0000.000466.78223.98111.67015.299 12-2026349.42657.34518.9830.0000.000425.75321.87310.64416.517 12-2027321.12152.70017.4450.0000.000391.26520.1019.78217.738 12-2028296.22448.61416.0920.0000.000360.93018.5439.02319.006 12-2029271.76644.60014.7640.0000.000331.12917.0128.27820.477 12-2030250.03941.03413.5830.0000.000304.65615.6527.61622.025 12-2031230.04937.75412.4970.0000.000280.30014.4007.00723.708 12-2032212.21334.82711.5280.0000.000258.56813.2846.46425.477 12-2033194.69131.95110.5770.0000.000237.21912.1875.93027.530 12-2034179.12629.3979.7310.0000.000218.25311.2135.45629.691 05-203567.11911.0153.6460.0000.00081.7804.2012.04530.987 12-2036 S Tot8,321.0541,365.579452.0420.0000.00010,138.675520.871253.46712.781 After.000.000.0000.0000.000.000.000.000.000 Total8,321.0541,365.579452.0420.0000.00010,138.675520.871253.46712.781 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash Flow EndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. % Mo-YearM$CountM$M$M$M$M$M$M$ 12-2018171.57210.90.0000.000151.949.0001,490.8241,490.8241,428.673 12-2019171.57210.90.0000.00099.248.000914.2412,405.0652,223.831 12-2020171.57210.90.0000.00075.355.000652.8513,057.9162,739.624 12-2021171.57210.90.0000.00061.066.000496.5143,554.4303,096.060 12-2022171.57210.90.0000.00051.749.000394.5903,949.0203,353.524 12-2023171.57210.90.0000.00045.082.000321.6484,270.6683,544.294 12-2024171.57210.90.0000.00040.159.000267.7814,538.4493,688.658 12-2025171.57210.90.0000.00036.107.000223.4534,761.9023,798.148 12-2026171.57210.90.0000.00032.933.000188.7314,950.6333,882.217 12-2027171.57210.90.0000.00030.265.000159.5455,110.1783,946.829 12-2028171.57210.90.0000.00027.919.000133.8735,244.0513,996.124 12-2029171.57210.90.0000.00025.614.000108.6535,352.7054,032.494 12-2030171.57210.90.0000.00023.566.00086.2505,438.9554,058.746 12-2031171.57210.90.0000.00021.682.00065.6385,504.5924,076.914 12-2032171.57210.90.0000.00020.001.00047.2475,551.8394,088.812 12-2033171.57210.90.0000.00018.349.00029.1795,581.0184,095.496 12-2034171.57210.90.0000.00016.882.00013.1305,594.1484,098.239 05-203567.37110.90.0000.0006.326.0001.8385,595.9864,098.597 12-2036 S Tot2,984.0980.0000.000784.253.0005,595.9865,595.9864,098.597 After.0000.0000.0000.000.000.000 5,595.9864,098.597 Total2,984.0980.0000.000784.253.0005,595.986 5,595.9864,098.597 Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeinDef InitialFinalUnits InitialFinal 5.00 4,712.875 Oil Rate6,156.475.bbls/mo 53.9%1.200.0% 16,499.16,262.$/w/mo Expense86.652686.6526 8.00 4,319.970 Gas Rate28,781.2,222.Mcf/mo 0.0%0.000.0% Revenue 10.00 4,098.597 GOR4,670.4,670.scf/bbl Oil61.041461.0414 12.00 3,903.301 NGL Rate1,809.140.bbls/mo Gas61.041461.0414 15.00 3,650.240 NGL Yield62.963.2bbl/MMcf 20.00 3,309.723 Gas Shrinkage37.935.5% Oil Severance4.64.6% Gas Severance7.57.5% NGL Severance7.57.5% Ad Valorem42.0 % 12 Months in first year 17.396 Year Life (05/2035) THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.TEXAS REGISTERED ENGINEERING FIRM F-693.ASN 332DEFAULT 1/10/201810:34:19OIL PDPTable 2Cawley, Gillespie & Associates, Inc.   Table 3Reserve Estimates and Economic Forecasts as of December 31, 2017 Lilis Energy, Inc. InterestsProved Developed Producing ReservesTRATON OPERATING COMPANY -- HILL, A. G. 1 1CHEYENNE \(ATOKA\) FIELD -- Winkler COUNTY, TEXAS(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGL EndProductionProductionProductionProductionSalesProductionPricePricePrice Mo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL 12-2018.0216.813.0.00089.7477.584.0002.5302.054 12-2019.0199.412.0.00082.5726.978.0002.5302.054 12-2020.0184.011.0.00076.1706.437.0002.5302.054 12-2021.0168.810.1.00069.8815.905.0002.5302.054 12-2022.0155.39.3.00064.2945.433.0002.5302.054 12-2023.0142.98.6.00059.1544.999.0002.5302.054 12-2024.0131.87.9.00054.5684.611.0002.5302.054 12-2025.0120.97.3.00050.0624.231.0002.5302.054 12-2026.0111.36.7.00046.0603.892.0002.5302.054 12-2027.0102.46.1.00042.3773.581.0002.5302.054 12-2028.094.45.7.00039.0923.304.0002.5302.054 12-2029.086.65.2.00035.8643.031.0002.5302.054 02-2030.013.1.8.0005.429.459.0002.5302.054 12-2031 12-2032 12-2033 12-2034 12-2035 12-2036 S Tot.01,727.6103.7.000715.26960.445.0002.5302.054 After.0.0.0.000.000.000.000.000.000 Total.01,727.6103.7.000715.26960.445.0002.5302.054 Cum1.13,905.0.0 Ult1.15,632.6103.7 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6 Mo-YearM$M$M$M$M$M$M$M$ 12-2018.000227.02415.5750.0000.000242.598.0906.0651.296 12-2019.000208.87414.3300.0000.000223.2039.7285.5801.408 12-2020.000192.67913.2190.0000.000205.89815.5195.1471.527 12-2021.000176.77012.1270.0000.000188.89814.2374.7221.664 12-2022.000162.63811.1580.0000.000173.79613.0994.3451.809 12-2023.000149.63610.2660.0000.000159.90112.0523.9981.966 12-2024.000138.0349.4700.0000.000147.50411.1173.6882.131 12-2025.000126.6378.6880.0000.000135.32510.1993.3832.323 12-2026.000116.5137.9930.0000.000124.5069.3843.1132.525 12-2027.000107.1987.3540.0000.000114.5528.6342.8642.744 12-2028.00098.8876.7840.0000.000105.6717.9642.6422.975 12-2029.00090.7226.2240.0000.00096.9467.3072.4243.243 02-2030.00013.733.9420.0000.00014.6751.106.3673.369 12-2031 12-2032 12-2033 12-2034 12-2035 12-2036 S Tot.0001,809.344124.1280.0000.0001,933.472120.43648.3371.977 After.000.000.0000.0000.000.000.000.000.000 Total.0001,809.344124.1280.0000.0001,933.472120.43648.3371.977 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash Flow EndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. % Mo-YearM$CountM$M$M$M$M$M$M$ 12-201825.76910.80.0000.0000.000.000210.674210.674201.079 12-201925.76910.80.0000.0000.000.000182.126392.800359.288 12-202025.76910.80.0000.0000.000.000159.463552.262485.077 12-202125.76910.80.0000.0000.000.000144.168696.431588.455 12-202225.76910.80.0000.0000.000.000130.582827.013673.586 12-202325.76910.80.0000.0000.000.000118.082945.095743.574 12-202425.76910.80.0000.0000.000.000106.9291,052.025801.188 12-202525.76910.80.0000.0000.000.00095.9731,147.998848.194 12-202625.76910.80.0000.0000.000.00086.2401,234.238886.596 12-202725.76910.80.0000.0000.000.00077.2851,311.523917.885 12-202825.76910.80.0000.0000.000.00069.2951,380.818943.388 12-202925.76910.80.0000.0000.000.00061.4461,442.263963.945 02-20304.05210.80.0000.0000.000.0009.1501,451.413966.838 12-2031 12-2032 12-2033 12-2034 12-2035 12-2036 S Tot313.2860.0000.0000.000.0001,451.4131,451.413 966.838 After.0000.0000.0000.000.000.000 1,451.413 966.838 Total313.2860.0000.0000.000.0001,451.4131,451.413 966.838 Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeinDef InitialFinalUnits InitialFinal 5.004,712.875 Gas Rate18,835.6,835.Mcf/mo 8.0%0.000.0% 2,761.2,761.$/w/mo Expense77.750077.7500 8.001,037.958 Oil Rate0.0.bbls/mo 0.0%0.000.0% Revenue 10.00966.838 NGL Rate1,147.421.bbls/mo Oil58.312558.3125 12.00904.520 Cond Rate0.00.0bbl/MMcf Gas58.312558.3125 15.00824.587 NGL Yield60.961.7bbl/MMcf 20.00719.053 Gas Shrinkage29.228.3% Oil Severance0.00.0% Gas Severance0.07.5% NGL Severance0.07.5% Ad Valorem19.7 % 12 Months in first year 12.159 Year Life (02/2030) THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.TEXAS REGISTERED ENGINEERING FIRM F-693.ASN 140DEFAULT 1/10/201810:34:19GAS PDPTable 3Cawley, Gillespie & Associates, Inc.   Table 4Reserve Estimates and Economic Forecasts as of December 31, 2017 Lilis Energy, Inc. InterestsProved Developed Producing Reserves LILIS ENERGY, INC. -- HIPPO #1H 1HPHANTOM (WOLFCAMP B) FIELD -- WINKLER COUNTY, TEXAS(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGL EndProductionProductionProductionProductionSalesProductionPricePricePrice Mo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL 12-201862.0181.713.646.59398.25810.23547.7462.6198.728 12-201937.2109.18.227.97558.9956.14547.7462.6198.728 12-202027.480.26.020.57643.3934.52047.7462.6198.728 12-202121.863.94.816.39534.5753.60247.7462.6198.728 12-202218.353.64.013.74828.9933.02047.7462.6198.728 12-202315.846.43.511.89125.0762.61247.7462.6198.728 12-202414.041.13.110.53622.2202.31547.7462.6198.728 12-202512.636.82.89.43619.8982.07347.7462.6198.728 12-202611.433.52.58.57918.0921.88547.7462.6198.728 12-202710.530.72.37.87216.6021.72947.7462.6198.728 12-20289.728.32.17.26215.3141.59547.7462.6198.728 12-20298.926.01.96.66214.0501.46447.7462.6198.728 12-20308.223.91.86.13012.9261.34747.7462.6198.728 12-20317.522.01.65.64011.8931.23947.7462.6198.728 12-20326.920.31.55.20210.9711.14347.7462.6198.728 12-20336.418.61.44.77310.0651.04847.7462.6198.728 12-20345.817.11.34.3919.260.96547.7462.6198.728 12-20355.415.81.24.0408.520.88847.7462.6198.728 03-20361.23.6.3.9141.928.20147.7462.6198.728 S Tot291.1852.563.9218.614461.03148.02447.7462.6198.728 After.0.0.0.000.000.000.000.000.000 Total291.1852.563.9218.614461.03148.02447.7462.6198.728 Cum105.0219.9.0 Ult396.11,072.463.9 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6 Mo-YearM$M$M$M$M$M$M$M$ 12-20182,224.617257.32689.3290.0000.0002,571.272128.77964.2825.456 12-20191,335.688154.50253.6340.0000.0001,543.82477.32038.5967.153 12-2020982.449113.64239.4500.0000.0001,135.54256.87228.3898.681 12-2021782.78890.54731.4330.0000.000904.76845.31422.61910.154 12-2022656.41275.92926.3580.0000.000758.69837.99818.96711.550 12-2023567.73265.67122.7970.0000.000656.20032.86516.40512.900 12-2024503.07558.19220.2010.0000.000581.46729.12214.53714.185 12-2025450.51152.11218.0900.0000.000520.71326.07913.01815.501 12-2026409.62347.38216.4480.0000.000473.45423.71211.83616.758 12-2027375.86843.47715.0930.0000.000434.43821.75810.86118.003 12-2028346.72240.10613.9230.0000.000400.75020.07110.01919.272 12-2029318.09436.79512.7730.0000.000367.66118.4149.19220.745 12-2030292.66333.85311.7520.0000.000338.26816.9428.45722.295 12-2031269.26531.14610.8120.0000.000311.22415.5877.78123.980 12-2032248.38928.7329.9740.0000.000287.09514.3797.17725.751 12-2033227.88026.3599.1500.0000.000263.39013.1926.58527.807 12-2034209.66224.2528.4190.0000.000242.33312.1376.05829.971 12-2035192.90022.3137.7460.0000.000222.95911.1675.57432.323 03-203643.6555.0501.7530.0000.00050.4582.5271.26133.494 S Tot10,437.9931,207.385419.1360.0000.00012,064.513604.236301.61312.819 After.000.000.0000.0000.000.000.000.000.000 Total10,437.9931,207.385419.1360.0000.00012,064.513604.236301.61312.819 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash Flow EndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. % Mo-YearM$CountM$M$M$M$M$M$M$ 12-2018177.60011.00.0000.000202.227.0001,998.3841,998.3841,917.116 12-2019177.60011.00.0000.000121.420.0001,128.8893,127.2732,899.283 12-2020177.60011.00.0000.00089.309.000783.3723,910.6453,518.286 12-2021177.60011.00.0000.00071.159.000588.0764,498.7203,940.485 12-2022177.60011.00.0000.00059.671.000464.4624,963.1824,243.553 12-2023177.60011.00.0000.00051.609.000377.7215,340.9034,467.584 12-2024177.60011.00.0000.00045.732.000314.4775,655.3804,637.121 12-2025177.60011.00.0000.00040.953.000263.0625,918.4424,766.019 12-2026177.60011.00.0000.00037.237.000223.0686,141.5114,865.381 12-2027177.60011.00.0000.00034.168.000190.0516,331.5624,942.344 12-2028177.60011.00.0000.00031.519.000161.5426,493.1045,001.821 12-2029177.60011.00.0000.00028.916.000133.5406,626.6435,046.516 12-2030177.60011.00.0000.00026.604.000108.6656,735.3085,079.585 12-2031177.60011.00.0000.00024.477.00085.7796,821.0875,103.323 12-2032177.60011.00.0000.00022.580.00065.3596,886.4465,119.773 12-2033177.60011.00.0000.00020.715.00045.2986,931.7445,130.141 12-2034177.60011.00.0000.00019.059.00027.4786,959.2235,135.864 12-2035177.60011.00.0000.00017.535.00011.0836,970.3055,137.972 03-203641.79111.00.0000.0003.968.000.9096,971.2145,138.134 S Tot3,238.5910.0000.000948.859.0006,971.2146,971.214 5,138.134 After.0000.0000.0000.000.000.0006,971.214 5,138.134 Total3,238.5910.0000.000948.859.0006,971.2146,971.214 5,138.134 Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeinDef InitialFinalUnits InitialFinal 5.00 5,886.663 Oil Rate7,475.421.bbls/mo 65.7%1.200.0% 14,800.14,101.$/w/mo Expense100.0000100.0000 8.00 5,407.389 Gas Rate21,897.1,235.Mcf/mo 0.0%0.000.0% Revenue 10.00 5,138.134 GOR2,920.2,920.scf/bbl Oil75.109475.1094 12.00 4,901.002 NGL Rate1,606.89.bbls/mo Gas75.109475.1094 15.00 4,594.203 NGL Yield73.372.1bbl/MMcf 20.00 4,181.953 Gas Shrinkage30.927.5% Oil Severance4.64.6% Gas Severance7.57.5% NGL Severance7.57.5% Ad Valorem42.0% 12 Months in first year 18.237 Year Life (03/2036) THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.TEXAS REGISTERED ENGINEERING FIRM F-693.ASN 224DEFAULT 1/10/201810:34:19OIL PDPTable 4Cawley, Gillespie & Associates, Inc.   Table 5Reserve Estimates and Economic Forecasts as of December 31, 2017 Lilis Energy, Inc. InterestsProved Developed Producing Reserves IMPETRO OPERATING LLC -- KUDU #1H 1HPHANTOM \(WOLFCAMP\) FIELD -- Winkler COUNTY, TEXAS(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGL EndProductionProductionProductionProductionSalesProductionPricePricePrice Mo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL 12-201818.174.24.810.89330.8122.90347.7462.5898.728 12-201914.456.73.78.64023.5492.21847.7462.5898.728 12-202012.046.53.07.22919.2851.81747.7462.5898.728 12-202110.339.42.66.21416.3461.54047.7462.5898.728 12-20229.134.42.25.48014.2721.34447.7462.5898.728 12-20238.230.62.04.91312.7011.19647.7462.5898.728 12-20247.427.71.84.47311.4961.08347.7462.5898.728 12-20256.825.21.64.08910.466.98647.7462.5898.728 12-20266.323.21.53.7629.621.90647.7462.5898.728 12-20275.821.31.43.4628.852.83447.7462.5898.728 12-20285.319.71.33.1938.166.76947.7462.5898.728 12-20294.918.01.22.9297.492.70647.7462.5898.728 12-20304.516.61.12.6956.893.64947.7462.5898.728 12-20314.115.31.02.4806.342.59747.7462.5898.728 12-20323.814.1.92.2885.850.55147.7462.5898.728 12-20333.512.9.82.0995.367.50647.7462.5898.728 12-20343.211.9.81.9314.938.46547.7462.5898.728 12-20353.010.9.71.7774.543.42847.7462.5898.728 12-20362.710.1.71.6394.191.39547.7462.5898.728 S Tot133.3508.733.180.187211.18019.89447.7462.5898.728 After.0.0.0.000.000.000.000.000.000 Total133.3508.733.180.187211.18019.89447.7462.5898.728 Cum94.5513.2.0 Ult227.71,021.933.1 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6 Mo-YearM$M$M$M$M$M$M$M$ 12-2018520.12179.77525.3320.0000.000625.22931.91915.6317.129 12-2019412.50760.97219.3620.0000.000492.84125.08712.3218.328 12-2020345.15549.93015.8550.0000.000410.94020.88310.2739.438 12-2021296.71742.32113.4390.0000.000352.47717.8938.81210.536 12-2022261.66136.95111.7340.0000.000310.34515.7427.75911.579 12-2023234.59732.88410.4420.0000.000277.92214.0906.94812.594 12-2024213.57529.7659.4520.0000.000252.79212.8106.32013.558 12-2025195.25627.0988.6050.0000.000230.95811.7005.77414.562 12-2026179.63624.9117.9100.0000.000212.45710.7625.31115.563 12-2027165.27422.9197.2780.0000.000195.4729.9024.88716.645 12-2028152.46021.1426.7140.0000.000180.3179.1344.50817.783 12-2029139.87219.3976.1590.0000.000165.4288.3804.13619.104 12-2030128.69017.8465.6670.0000.000152.2037.7103.80520.495 12-2031118.40116.4195.2140.0000.000140.0347.0943.50122.006 12-2032109.22215.1464.8100.0000.000129.1776.5443.22923.594 12-2033100.20313.8964.4130.0000.000118.5126.0032.96325.438 12-203492.19212.7854.0600.0000.000109.0375.5232.72627.379 12-203584.82211.7633.7350.0000.000100.3205.0822.50829.488 12-203678.24610.8513.4460.0000.00092.5424.6882.31431.706 S Tot3,828.606546.770173.6250.0000.0004,549.002230.945113.72514.056 After.000.000.0000.0000.000.000.000.000.000 Total3,828.606546.770173.6250.0000.0004,549.002230.945113.72514.056 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash Flow EndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. % Mo-YearM$CountM$M$M$M$M$M$M$ 12-201874.18810.80.0000.00053.530.000449.962449.962430.230 12-201974.18810.80.0000.00042.455.000338.790788.752724.572 12-202074.18810.80.0000.00035.523.000270.0721,058.824937.801 12-202174.18810.80.0000.00030.538.000221.0471,279.8711,096.408 12-202274.18810.80.0000.00026.930.000185.7261,465.5971,217.546 12-202374.18810.80.0000.00024.144.000158.5521,624.1501,311.553 12-202474.18810.80.0000.00021.981.000137.4941,761.6431,385.655 12-202574.18810.80.0000.00020.095.000119.2011,880.8441,444.048 12-202674.18810.80.0000.00018.488.000103.7081,984.5521,490.237 12-202774.18810.80.0000.00017.010.00089.4852,074.0381,526.473 12-202874.18810.80.0000.00015.691.00076.7962,150.8331,554.746 12-202974.18810.80.0000.00014.395.00064.3292,215.1631,576.275 12-203074.18810.80.0000.00013.245.00053.2552,268.4181,592.480 12-203174.18810.80.0000.00012.186.00043.0672,311.4851,604.396 12-203274.18810.80.0000.00011.241.00033.9762,345.4611,612.945 12-203374.18810.80.0000.00010.313.00025.0452,370.5061,618.675 12-203474.18810.80.0000.0009.488.00017.1122,387.6171,622.236 12-203574.18810.80.0000.0008.730.0009.8122,397.4301,624.095 12-203674.18810.80.0000.0008.053.0003.3002,400.7291,624.668 S Tot1,409.5670.0000.000394.035.0002,400.7292,400.729 1,624.668 After.0000.0000.0000.000.000.0002,400.729 1,624.668 Total1,409.5670.0000.000394.035.0002,400.7292,400.729 1,624.668 Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeinDef InitialFinalUnits InitialFinal 5.001,934.777 Oil Rate1,730.217.bbls/mo 26.9%1.200.0% 7,799.7,799.$/w/mo Expense79.260479.2604 8.001,734.978 Gas Rate7,279.805.Mcf/mo 31.8%1.200.0% Revenue 10.001,624.668 GOR4,200.3,700.scf/bbl Oil60.163360.1633 12.001,528.786 NGL Rate474.53.bbls/mo Gas60.163360.1633 15.001,406.644 NGL Yield65.266.4bbl/MMcf 20.001,246.252 Gas Shrinkage32.131.0% Oil Severance4.64.6% Gas Severance7.57.5% NGL Severance7.57.5% Ad Valorem18.9 % 12 Months in first year 19.001 Year Life (01/2037) THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.TEXAS REGISTERED ENGINEERING FIRM F-693.ASN 28DEFAULT 1/10/201810:34:19OIL PDPTable 5Cawley, Gillespie & Associates, Inc.   Table 6Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Developed Producing ReservesLILIS ENERGY, INC. -- LION #1HPHANTOM (WOLFCAMP B) FIELD -- WINKLER COUNTY, TEXAS(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGLEndProductionProductionProductionProductionSalesProductionPricePricePriceMo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL12-201868.4295.220.445.111132.36613.43147.7462.6198.728 12-201940.5174.812.126.70678.3597.95147.7462.6198.728 12-202029.6127.98.819.54857.3595.82047.7462.6198.728 12-202123.6101.77.015.53745.5894.62647.7462.6198.728 12-202219.785.15.913.00938.1713.87347.7462.6198.728 12-202317.073.65.111.24032.9813.34747.7462.6198.728 12-202415.165.14.59.95329.2032.96347.7462.6198.728 12-202513.558.34.08.90826.1372.65247.7462.6198.728 12-202612.353.03.78.09623.7552.41047.7462.6198.728 12-202711.348.63.47.42721.7922.21147.7462.6198.728 12-202810.444.83.16.85120.1022.04047.7462.6198.728 12-20299.541.12.86.28518.4421.87147.7462.6198.728 12-20308.837.82.65.78316.9671.72247.7462.6198.728 12-20318.134.82.45.32015.6111.58447.7462.6198.728 12-20327.432.12.24.90814.4011.46147.7462.6198.728 12-20336.829.52.04.50313.2121.34147.7462.6198.728 12-20346.327.11.94.14312.1551.23347.7462.6198.728 12-20355.824.91.73.81111.1841.13547.7462.6198.728 02-2036.62.8.2.4281.257.12847.7462.6198.728 S Tot314.81,358.393.7207.567609.04261.80047.7462.6198.728 After.0.0.0.000.000.000.000.000.000 Total314.81,358.393.7207.567609.04261.80047.7462.6198.728 Cum54.4186.2.0 Ult369.21,544.593.7 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6Mo-YearM$M$M$M$M$M$M$M$ 12-20182,153.893346.649117.2230.0000.0002,617.765134.32965.4445.073 12-20191,275.087205.21469.3950.0000.0001,549.69579.52138.7426.685 12-2020933.366150.21750.7970.0000.0001,134.38058.21028.3608.132 12-2021741.842119.39340.3740.0000.000901.60846.26522.5409.526 12-2022621.13699.96633.8040.0000.000754.90738.73718.87310.846 12-2023536.67486.37329.2080.0000.000652.25433.47016.30612.122 12-2024475.20276.48025.8620.0000.000577.54429.63614.43913.337 12-2025425.31468.45023.1470.0000.000516.91126.52512.92314.580 12-2026386.54462.21121.0370.0000.000469.79224.10711.74515.768 12-2027354.59857.06919.2990.0000.000430.96622.11510.77416.943 12-2028327.09852.64317.8020.0000.000397.54420.4009.93918.137 12-2029300.09148.29716.3320.0000.000364.71918.7159.11819.524 12-2030276.09944.43615.0260.0000.000335.56117.2198.38920.982 12-2031254.02640.88313.8250.0000.000308.73415.8427.71822.568 12-2032234.33137.71312.7530.0000.000284.79714.6147.12024.235 12-2033214.98334.60011.7000.0000.000261.28213.4086.53226.170 12-2034197.79531.83310.7650.0000.000240.39412.3366.01028.207 12-2035181.98229.2889.9040.0000.000221.17511.3495.52930.420 02-203620.4583.2921.1130.0000.00024.8631.276.62231.349 S Tot9,910.5181,595.008539.3660.0000.00012,044.892618.075301.12211.944 After.000.000.0000.0000.000.000.000.000.000 Total9,910.5181,595.008539.3660.0000.00012,044.892618.075301.12211.944 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulative Cum.Cash FlowEndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. %Mo-YearM$CountM$M$M$M$M$M$M$12-2018177.55310.90.0000.000207.508.0002,032.9322,032.9321,950.642 12-2019177.55310.90.0000.000122.843.0001,131.0363,163.9672,934.737 12-2020177.55310.90.0000.00089.921.000780.3373,944.3043,551.362 12-2021177.55310.90.0000.00071.470.000583.7804,528.0843,970.486 12-2022177.55310.90.0000.00059.841.000459.9034,987.9884,270.584 12-2023177.55310.90.0000.00051.704.000373.2225,361.2104,491.950 12-2024177.55310.90.0000.00045.781.000310.1355,671.3454,659.150 12-2025177.55310.90.0000.00040.975.000258.9365,930.2814,786.027 12-2026177.55310.90.0000.00037.240.000219.1486,149.4284,883.644 12-2027177.55310.90.0000.00034.162.000186.3636,335.7914,959.114 12-2028177.55310.90.0000.00031.513.000158.1406,493.9315,017.339 12-2029177.55310.90.0000.00028.911.000130.4236,624.3535,060.991 12-2030177.55310.90.0000.00026.600.000105.8016,730.1545,093.189 12-2031177.55310.90.0000.00024.473.00083.1476,813.3015,116.199 12-2032177.55310.90.0000.00022.576.00062.9356,876.2365,132.041 12-2033177.55310.90.0000.00020.712.00043.0796,919.3155,141.901 12-2034177.55310.90.0000.00019.056.00025.4406,944.7555,147.201 12-2035177.55310.90.0000.00017.532.0009.2116,953.9655,148.956 02-203620.62910.90.0000.0001.971.000.3666,954.3315,149.021 S Tot3,216.576 0.0000.000954.788.0006,954.3316,954.3315,149.021 After.000 0.0000.0000.000.000.0006,954.3315,149.021 Total3,216.576 0.0000.000954.788.0006,954.3316,954.3315,149.021 Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeinDef InitialFinalUnits InitialFinal 5.005,887.468 Oil Rate8,363.457.bbls/mo 67.6%1.200.0% 15,999.15,999.$/w/mo Expense92.475392.4753 8.005,414.870 Gas Rate36,087.1,974.Mcf/mo 0.0%0.000.0% Revenue 10.005,149.021 GOR4,310.4,310.scf/bbl Oil65.940265.9402 12.004,914.672 NGL Rate2,430.139.bbls/mo Gas65.940265.9402 15.004,611.156 NGL Yield67.370.7bbl/MMcf 20.004,202.721 Gas Shrinkage34.831.7% Oil Severance4.64.6% Gas Severance7.57.5% NGL Severance7.57.5% Ad Valorem44.9 % 12 Months in first year 18.116 Year Life (02/2036)THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.TEXAS REGISTERED ENGINEERING FIRM F-693. ASN 319DEFAULT 1/10/2018 10:34:19 OIL PDP Table 6Cawley, Gillespie & Associates, Inc.   Table 7Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Developed Producing ReservesIMPETRO OPERATING, LLC -- MEXICO P FEDERAL 001 001JABALINA (WOLFCAMP, SOUTHWEST) FIELD -- LEA COUNTY, NEW MEXICO(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGLEndProductionProductionProductionProductionSalesProductionPricePricePriceMo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL12-20182.7.0.02.056.000.00047.746.000.000 12-20192.5.0.01.869.000.00047.746.000.000 12-20202.3.0.01.714.000.00047.746.000.000 12-20212.1.0.01.571.000.00047.746.000.000 12-20221.9.0.01.446.000.00047.746.000.000 12-20231.8.0.01.330.000.00047.746.000.000 12-20241.6.0.01.227.000.00047.746.000.000 12-20251.5.0.01.126.000.00047.746.000.000 12-20261.4.0.01.036.000.00047.746.000.000 09-2027.9.0.0.689.000.00047.746.000.000 12-2028 12-2029 12-2030 12-2031 12-2032 12-2033 12-2034 12-2035 12-2036 S Tot18.6.0.014.064.000.00047.746.000.000 After.0.0.0.000.000.000.000.000.000 Total18.6.0.014.064.000.00047.746.000.000 Cum11.782.4.0 Ult30.382.4.0 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6Mo-YearM$M$M$M$M$M$M$M$ 12-201898.172.000.0000.0000.00098.1726.9604.90919.125 12-201989.215.000.0000.0000.00089.2156.3254.46121.045 12-202081.843.000.0000.0000.00081.8435.8034.09222.940 12-202175.029.000.0000.0000.00075.0295.3203.75125.023 12-202269.031.000.0000.0000.00069.0314.8943.45227.198 12-202363.512.000.0000.0000.00063.5124.5033.17629.561 12-202458.588.000.0000.0000.00058.5884.1542.92932.046 12-202553.750.000.0000.0000.00053.7503.8112.68834.930 12-202649.453.000.0000.0000.00049.4533.5062.47337.965 09-202732.919.000.0000.0000.00032.9192.3341.64640.316 12-2028 12-2029 12-2030 12-2031 12-2032 12-2033 12-2034 12-2035 12-2036 S Tot671.512.000.0000.0000.000671.51247.61033.57627.140 After.000.000.0000.0000.000.000.000.000.000 Total671.512.000.0000.0000.000671.51247.61033.57627.140 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulative Cum.Cash FlowEndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. %Mo-YearM$CountM$M$M$M$M$M$M$12-201839.32211.00.0000.0000.000.00046.98046.98044.866 12-201939.32211.00.0000.0000.000.00039.10686.08778.818 12-202039.32211.00.0000.0000.000.00032.626118.712104.570 12-202139.32211.00.0000.0000.000.00026.636145.348123.681 12-202239.32211.00.0000.0000.000.00021.363166.711137.618 12-202339.32211.00.0000.0000.000.00016.511183.222147.414 12-202439.32211.00.0000.0000.000.00012.182195.404153.988 12-202539.32211.00.0000.0000.000.0007.930203.334157.880 12-202639.32211.00.0000.0000.000.0004.152207.486159.737 09-202727.79611.00.0000.0000.000.0001.143208.629160.209 12-2028 12-2029 12-2030 12-2031 12-2032 12-2033 12-2034 12-2035 12-2036 S Tot381.697 0.0000.0000.000.000208.629208.629160.209 After.000 0.0000.0000.000.000.000208.629160.209 Total381.697 0.0000.0000.000.000208.629208.629160.209 Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeinDef InitialFinalUnits InitialFinal 5.00181.299 Oil Rate237.103.bbls/mo 9.8%0.800.0% 3,375.3,375.$/w/mo Expense97.063497.0634 8.00168.026 Gas Rate0.0.Mcf/mo 0.0%0.000.0% Revenue 10.00160.209 GOR0.0.scf/bbl Oil75.741275.7412 12.00153.099 NGL Rate0.0.bbls/mo Gas75.741275.7412 15.00143.577 NGL Yield0.00.0bbl/MMcf 20.00130.206 Gas Shrinkage0.00.0% Oil Severance7.17.1% Gas Severance0.00.0% NGL Severance0.00.0% Ad Valorem19.1 % 12 Months in first year 9.714 Year Life (09/2027)THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.ASN 133DEFAULT 1/10/2018 10:34:19 TEXAS REGISTERED ENGINEERING FIRM F-693. OIL PDP Table 7Cawley, Gillespie & Associates, Inc.   Table 8Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Developed Producing ReservesLILIS ENERGY, INC. -- PRIZE HOG BWZ ST COM 1H #1HTBD (WOLFCAMP B) FIELD -- LEA COUNTY, NEW MEXICO(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGLEndProductionProductionProductionProductionSalesProductionPricePricePriceMo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL12-2018104.4198.413.755.16071.2667.23147.7462.6198.728 12-201953.2101.07.028.07936.2793.68147.7462.6198.728 12-202037.370.84.919.67725.4222.58047.7462.6198.728 12-202129.055.13.815.30819.7792.00747.7462.6198.728 12-202224.045.53.112.65516.3511.65947.7462.6198.728 12-202320.539.02.710.84214.0081.42147.7462.6198.728 12-202418.134.32.49.54212.3291.25147.7462.6198.728 12-202516.130.62.18.50210.9841.11547.7462.6198.728 12-202614.627.71.97.6999.9481.00947.7462.6198.728 12-202713.325.31.77.0469.104.92447.7462.6198.728 12-202812.323.41.66.4988.396.85247.7462.6198.728 12-202911.321.41.55.9627.702.78247.7462.6198.728 12-203010.419.71.45.4857.087.71947.7462.6198.728 12-20319.618.21.35.0466.520.66247.7462.6198.728 12-20328.816.71.24.6556.015.61047.7462.6198.728 12-20338.115.41.14.2715.518.56047.7462.6198.728 12-20347.414.11.03.9295.077.51547.7462.6198.728 12-20356.813.0.93.6154.671.47447.7462.6198.728 12-20366.312.0.83.3354.309.43747.7462.6198.728 S Tot411.5781.853.9217.308280.76328.48947.7462.6198.728 After4.89.2.62.5503.294.33447.7462.6198.728 Total416.3791.054.6219.858284.05728.82347.7462.6198.728 Cum17.032.2.0 Ult433.3823.254.6 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6Mo-YearM$M$M$M$M$M$M$M$ 12-20182,633.669186.63863.1130.0000.0002,883.420206.557144.1714.844 12-20191,340.68395.00932.1280.0000.0001,467.820105.14973.3916.521 12-2020939.48366.57822.5140.0000.0001,028.57473.68351.4297.981 12-2021730.92151.79817.5160.0000.000800.23557.32640.0129.372 12-2022604.25142.82114.4800.0000.000661.55247.39133.07810.686 12-2023517.67636.68612.4060.0000.000566.76740.60128.33811.955 12-2024455.60832.28710.9180.0000.000498.81435.73324.94113.160 12-2025405.92428.7669.7280.0000.000444.41831.83622.22114.391 12-2026367.61926.0528.8100.0000.000402.48028.83220.12415.567 12-2027336.42823.8418.0620.0000.000368.33126.38618.41716.723 12-2028310.26221.9877.4350.0000.000339.68424.33416.98417.871 12-2029284.64420.1726.8210.0000.000311.63722.32515.58219.200 12-2030261.88818.5596.2760.0000.000286.72220.54014.33620.599 12-2031240.95017.0755.7740.0000.000263.80018.89813.19022.119 12-2032222.26915.7515.3260.0000.000243.34717.43212.16723.717 12-2033203.91714.4514.8870.0000.000223.25515.99311.16325.572 12-2034187.61413.2964.4960.0000.000205.40614.71510.27027.525 12-2035172.61512.2334.1370.0000.000188.98413.5389.44929.647 12-2036159.23211.2843.8160.0000.000174.33212.4888.71731.878 S Tot10,375.652735.283248.6430.0000.00011,359.578813.757567.97911.494 After121.7318.6272.9170.0000.000133.2759.5476.66433.880 Total10,497.384743.910251.5600.0000.00011,492.853823.305574.64311.754 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulative Cum.Cash FlowEndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. %Mo-YearM$CountM$M$M$M$M$M$M$12-2018124.80010.70.0000.000222.676.0002,185.2162,185.2162,101.198 12-2019124.80010.70.0000.000113.354.0001,051.1263,236.3423,016.173 12-2020124.80010.70.0000.00079.433.000699.2293,935.5713,568.798 12-2021124.80010.70.0000.00061.799.000516.2984,451.8693,939.498 12-2022124.80010.70.0000.00051.089.000405.1944,857.0644,203.904 12-2023124.80010.70.0000.00043.769.000329.2595,186.3224,399.193 12-2024124.80010.70.0000.00038.521.000274.8185,461.1404,547.347 12-2025124.80010.70.0000.00034.321.000231.2405,692.3804,660.649 12-2026124.80010.70.0000.00031.082.000197.6425,890.0224,748.683 12-2027124.80010.70.0000.00028.445.000170.2846,060.3064,817.635 12-2028124.80010.70.0000.00026.233.000147.3336,207.6394,871.873 12-2029124.80010.70.0000.00024.067.000124.8646,332.5044,913.658 12-2030124.80010.70.0000.00022.142.000104.9046,437.4084,945.577 12-2031124.80010.70.0000.00020.372.00086.5406,523.9474,969.518 12-2032124.80010.70.0000.00018.793.00070.1546,594.1024,987.167 12-2033124.80010.70.0000.00017.241.00054.0586,648.1604,999.530 12-2034124.80010.70.0000.00015.863.00039.7586,687.9185,007.799 12-2035124.80010.70.0000.00014.595.00026.6026,714.5205,012.833 12-2036124.80010.70.0000.00013.463.00014.8646,729.3845,015.397 S Tot2,371.200 0.0000.000877.257.0006,729.3846,729.3845,015.397 After102.048 0.0000.00010.292.0004.7246,734.1085,016.147 Total2,473.248 0.0000.000887.550.0006,734.1086,734.1085,016.147 Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeinDef InitialFinalUnits InitialFinal 5.005,710.824 Oil Rate15,144.470.bbls/mo 85.6%1.200.0% 16,000.15,769.$/w/mo Expense65.000065.0000 8.005,265.044 Gas Rate28,774.892.Mcf/mo 0.0%0.000.0% Revenue 10.005,016.147 GOR1,900.1,900.scf/bbl Oil52.812552.8125 12.004,797.759 NGL Rate1,883.61.bbls/mo Gas52.812552.8125 15.004,516.181 NGL Yield65.568.7bbl/MMcf 20.004,139.095 Gas Shrinkage36.731.5% Oil Severance7.17.1% Gas Severance7.97.9% NGL Severance7.97.9% Ad Valorem64.6 % 12 Months in first year 19.828 Year Life (10/2037)THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.ASN 317DEFAULT 1/10/2018 10:34:19 TEXAS REGISTERED ENGINEERING FIRM F-693. OIL PDP Table 8Cawley, Gillespie & Associates, Inc.   Table 9Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Developed Producing ReservesIMPETRO OPERATING LLC -- SHAMMO C24-4 1 1HALEY \(LWR. WOLFCAMP-PENN CONS.\) FIELD -- Loving COUNTY, TEXAS(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGLEndProductionProductionProductionProductionSalesProductionPricePricePriceMo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL Non-Commercial Cum.9342.7.0 Ult.9342.7.0 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6Mo-YearM$M$M$M$M$M$M$M$ (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulative Cum.Cash FlowEndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. %Mo-YearM$CountM$M$M$M$M$M$M$ Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc.  InitialFinalUnits DeinDef InitialFinalUnits InitialFinal 5.00.000 Gas Rate947.947.Mcf/mo 8.0%0.000.0% 0.0.$/w/mo Expense65.000065.0000 8.00.000 Oil Rate0.0.bbls/mo 0.0%0.000.0% Revenue 10.00.000 NGL Rate0.0.bbls/mo Oil52.812552.8125 12.00.000 Cond Yield0.00.0bbl/MMcf Gas52.812552.8125 15.00.000 NGL Yield0.00.0bbl/MMcf 20.00.000 Gas Shrinkage100.0100.0% Oil Severance0.00.0% Gas Severance0.00.0% NGL Severance0.00.0% Ad Valorem0.0 % 1 Months in first year .000 Year Life (01/2018)THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.ASN 68DEFAULT 1/10/2018 10:34:19 TEXAS REGISTERED ENGINEERING FIRM F-693. GAS PDP Table 9Cawley, Gillespie & Associates, Inc.   Table 10Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Developed Producing ReservesLILIS ENERGY, INC. -- TIGER 1HPHANTOM (WOLFCAMP B) FIELD -- WINKLER COUNTY, TEXAS(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGLEndProductionProductionProductionProductionSalesProductionPricePricePriceMo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL12-2018103.6393.727.273.659190.33619.31347.7462.6198.728 12-201946.7177.512.233.21185.8188.70847.7462.6198.728 12-202031.9121.28.422.67158.5825.94447.7462.6198.728 12-202124.593.26.417.42845.0354.57047.7462.6198.728 12-202220.176.55.314.30936.9753.75247.7462.6198.728 12-202317.265.24.512.20431.5353.20047.7462.6198.728 12-202415.157.23.910.70727.6662.80747.7462.6198.728 12-202513.450.93.59.51724.5912.49547.7462.6198.728 12-202612.146.03.28.60322.2302.25647.7462.6198.728 12-202711.142.02.97.86220.3162.06147.7462.6198.728 12-202810.238.72.77.24918.7311.90147.7462.6198.728 12-20299.435.52.56.65017.1841.74447.7462.6198.728 12-20308.632.72.36.11815.8101.60447.7462.6198.728 12-20317.930.12.15.62914.5461.47647.7462.6198.728 12-20327.327.81.95.19313.4181.36247.7462.6198.728 12-20336.725.51.84.76412.3101.24947.7462.6198.728 12-20346.223.41.64.38311.3261.14947.7462.6198.728 12-20355.721.61.54.03310.4211.05747.7462.6198.728 12-20365.219.91.43.7209.613.97547.7462.6198.728 S Tot362.81,378.595.1257.911666.44267.62447.7462.6198.728 After1.86.9.51.2963.348.34047.7462.6198.728 Total364.61,385.595.6259.206669.78967.96447.7462.6198.728 Cum15.759.7.0 Ult380.31,445.295.6 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6Mo-YearM$M$M$M$M$M$M$M$ 12-20183,516.950498.466168.5610.0000.0004,183.976212.538104.5993.932 12-20191,585.712224.74776.0000.0000.0001,886.45995.82947.1615.660 12-20201,082.453153.41951.8800.0000.0001,287.75265.41532.1947.124 12-2021832.138117.94139.8830.0000.000989.96250.28824.7498.511 12-2022683.20296.83232.7450.0000.000812.77941.28820.3199.819 12-2023582.68882.58627.9270.0000.000693.20135.21317.33011.079 12-2024511.20072.45424.5010.0000.000608.15530.89315.20412.277 12-2025454.38064.40021.7780.0000.000540.55827.45913.51413.498 12-2026410.75458.21719.6870.0000.000488.65824.82312.21614.665 12-2027375.38953.20517.9920.0000.000446.58522.68611.16515.810 12-2028346.09649.05316.5880.0000.000411.73720.91510.29316.935 12-2029317.52045.00315.2180.0000.000377.74119.1899.44418.233 12-2030292.13541.40514.0010.0000.000347.54117.6548.68919.599 12-2031268.77938.09512.8820.0000.000319.75616.2437.99421.084 12-2032247.94135.14111.8830.0000.000294.96514.9847.37422.645 12-2033227.46932.24010.9020.0000.000270.61113.7476.76524.457 12-2034209.28329.66210.0310.0000.000248.97612.6486.22426.364 12-2035192.55227.2919.2290.0000.000229.07111.6365.72728.436 12-2036177.62325.1758.5130.0000.000211.31110.7345.28330.615 S Tot12,314.2641,745.331590.1990.0000.00014,649.794744.183366.24510.214 After61.8608.7682.9650.0000.00073.5923.7381.84032.029 Total12,376.1241,754.098593.1640.0000.00014,723.386747.921368.08510.323 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulative Cum.Cash FlowEndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. %Mo-YearM$CountM$M$M$M$M$M$M$12-2018167.39010.90.0000.000296.277.0003,403.1723,403.1723,278.697 12-2019167.39010.90.0000.000133.584.0001,442.4944,845.6654,534.766 12-2020167.39010.90.0000.00091.189.000931.5645,777.2295,271.123 12-2021167.39010.90.0000.00070.101.000677.4336,454.6635,757.563 12-2022167.39010.90.0000.00057.555.000526.2276,980.8896,100.970 12-2023167.39010.90.0000.00049.087.000424.1807,405.0696,352.573 12-2024167.39010.90.0000.00043.065.000351.6027,756.6726,542.130 12-2025167.39010.90.0000.00038.278.000293.9178,050.5886,686.149 12-2026167.39010.90.0000.00034.603.000249.6268,300.2146,797.341 12-2027167.39010.90.0000.00031.624.000213.7218,513.9356,883.885 12-2028167.39010.90.0000.00029.156.000183.9818,697.9166,951.618 12-2029167.39010.90.0000.00026.749.000154.9708,852.8867,003.479 12-2030167.39010.90.0000.00024.610.000129.1988,982.0837,042.791 12-2031167.39010.90.0000.00022.643.000105.4869,087.5697,071.976 12-2032167.39010.90.0000.00020.887.00084.3309,171.8997,093.193 12-2033167.39010.90.0000.00019.163.00063.5469,235.4457,107.728 12-2034167.39010.90.0000.00017.631.00045.0839,280.5297,117.107 12-2035167.39010.90.0000.00016.221.00028.0969,308.6257,122.427 12-2036167.39010.90.0000.00014.963.00012.9409,321.5657,124.664 S Tot3,180.416 0.0000.0001,037.385.0009,321.5659,321.5657,124.664 After61.229 0.0000.0005.211.0001.5749,323.1397,124.918 Total3,241.645 0.0000.0001,042.596.0009,323.1399,323.1397,124.918 Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeinDef InitialFinalUnits InitialFinal 5.008,020.337 Oil Rate17,723.404.bbls/mo 95.0%1.200.0% 15,999.15,769.$/w/mo Expense87.182587.1825 8.007,446.892 Gas Rate67,350.1,537.Mcf/mo 0.0%0.000.0% Revenue 10.007,124.918 GOR3,800.3,800.scf/bbl Oil71.094071.0940 12.006,841.262 NGL Rate4,259.105.bbls/mo Gas71.094071.0940 15.006,473.833 NGL Yield63.268.5bbl/MMcf 20.005,978.527 Gas Shrinkage38.831.7% Oil Severance4.64.6% Gas Severance7.57.5% NGL Severance7.57.5% Ad Valorem40.5 % 12 Months in first year 19.370 Year Life (05/2037)THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.ASN 322DEFAULT 1/10/2018 10:34:19 TEXAS REGISTERED ENGINEERING FIRM F-693. OIL PDP Table 10Cawley, Gillespie & Associates, Inc.   Table 11Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Developed Producing ReservesIMPETRO OPERATING LLC -- TUBB 1 UNIT 1 1CRITTENDON \(ATOKA OOLITIC\) FIELD -- Winkler COUNTY, TEXAS(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGLEndProductionProductionProductionProductionSalesProductionPricePricePriceMo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL Non-Commercial Cum.2713.2.0 Ult.2713.2.0 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6Mo-YearM$M$M$M$M$M$M$M$ (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulative Cum.Cash FlowEndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. %Mo-YearM$CountM$M$M$M$M$M$M$ Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeinDef InitialFinalUnits InitialFinal 5.00.000 Gas Rate1,395.1,395.Mcf/mo 8.1%0.900.0% 0.0.$/w/mo Expense87.182587.1825 8.00.000 Oil Rate0.0.bbls/mo 0.0%0.000.0% Revenue 10.00.000 NGL Rate0.0.bbls/mo Oil71.094071.0940 12.00.000 Cond Yield0.00.0bbl/MMcf Gas71.094071.0940 15.00.000 NGL Yield0.00.0bbl/MMcf 20.00.000 Gas Shrinkage100.0100.0% Oil Severance0.00.0% Gas Severance0.00.0% NGL Severance0.00.0% Ad Valorem0.0 % 1 Months in first year .000 Year Life (01/2018)THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.ASN 24DEFAULT 1/10/2018 10:34:19 TEXAS REGISTERED ENGINEERING FIRM F-693. GAS PDP Table 11Cawley, Gillespie & Associates, Inc.   Table 12Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Developed Producing ReservesIMPETRO OPERATING LLC -- TUBB 22 UNIT 1R 1RCRITTENDON \(MORROW\) FIELD -- Winkler COUNTY, TEXAS(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGLEndProductionProductionProductionProductionSalesProductionPricePricePriceMo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL Non-Commercial Cum.62,462.5.0 Ult.62,462.5.0 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6Mo-YearM$M$M$M$M$M$M$M$ (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulative Cum.Cash FlowEndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. %Mo-YearM$CountM$M$M$M$M$M$M$ Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeinDef InitialFinalUnits InitialFinal 5.00.000 Gas Rate1,530.1,530.Mcf/mo 10.0%0.000.0% 0.0.$/w/mo Expense87.182587.1825 8.00.000 Oil Rate0.0.bbls/mo 0.0%0.000.0% Revenue 10.00.000 NGL Rate0.0.bbls/mo Oil71.094071.0940 12.00.000 Cond Yield0.00.0bbl/MMcf Gas71.094071.0940 15.00.000 NGL Yield0.00.0bbl/MMcf 20.00.000 Gas Shrinkage100.0100.0% Oil Severance0.00.0% Gas Severance0.00.0% NGL Severance0.00.0% Ad Valorem0.0 % 1 Months in first year .000 Year Life (01/2018)THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.ASN 104DEFAULT 1/10/2018 10:34:19 TEXAS REGISTERED ENGINEERING FIRM F-693. GAS PDP Table 12Cawley, Gillespie & Associates, Inc.   Table 13Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Developed Producing ReservesIMPETRO OPERATING LLC -- TUBB 9 UNIT 1 1CRITTENDON \(MORROW\) FIELD -- Winkler COUNTY, TEXAS(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGLEndProductionProductionProductionProductionSalesProductionPricePricePriceMo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL Non-Commercial Cum3.01,418.6.0 Ult3.01,418.6.0 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6Mo-YearM$M$M$M$M$M$M$M$ (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulative Cum.Cash FlowEndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. %Mo-YearM$CountM$M$M$M$M$M$M$ Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeinDef InitialFinalUnits InitialFinal 5.00.000 Gas Rate24.24.Mcf/mo 8.0%0.000.0% 0.0.$/w/mo Expense87.182587.1825 8.00.000 Oil Rate0.0.bbls/mo 0.0%0.000.0% Revenue 10.00.000 NGL Rate0.0.bbls/mo Oil71.094071.0940 12.00.000 cond Yield0.00.0bbl/MMcf Gas71.094071.0940 15.00.000 NGL Yield0.00.0bbl/MMcf 20.00.000 Gas Shrinkage100.0100.0% Oil Severance0.00.0% Gas Severance0.00.0% NGL Severance0.00.0% Ad Valorem0.0 % 1 Months in first year .000 Year Life (01/2018)THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.ASN 94DEFAULT 1/10/2018 10:34:19 TEXAS REGISTERED ENGINEERING FIRM F-693. GAS PDP Table 13Cawley, Gillespie & Associates, Inc.   Table 14Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Developed Producing ReservesIMPETRO OPERATING LLC -- TUBB ESTATE 1-75 1 1CRITTENDON \(BRUSHY CANYON\) FIELD -- Winkler COUNTY, TEXAS(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGLEndProductionProductionProductionProductionSalesProductionPricePricePriceMo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL Non-Commercial Cum74.389.7.0 Ult74.389.7.0 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6Mo-YearM$M$M$M$M$M$M$M$ (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulative Cum.Cash FlowEndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. %Mo-YearM$CountM$M$M$M$M$M$M$ Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeinDef InitialFinalUnits InitialFinal 5.00.000 Oil Rate4.4.bbls/mo 22.4%1.200.0% 0.0.$/w/mo Expense87.182587.1825 8.00.000 Gas Rate94.94.Mcf/mo 27.6%1.200.0% Revenue 10.00.000 GOR19,800.19,800.scf/bbl Oil71.094071.0940 12.00.000 NGL Rate0.0.bbls/mo Gas71.094071.0940 15.00.000 NGL Yield0.00.0bbl/MMcf 20.00.000 Gas Shrinkage100.0100.0% Oil Severance0.00.0% Gas Severance0.00.0% NGL Severance0.00.0% Ad Valorem0.0 % 1 Months in first year .000 Year Life (01/2018)THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.ASN 23DEFAULT 1/10/2018 10:34:19 TEXAS REGISTERED ENGINEERING FIRM F-693. OIL PDP Table 14Cawley, Gillespie & Associates, Inc.   Table 15Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Developed Producing ReservesIMPETRO OPERATING LLC -- TUBB ESTATE 21 2 2CRITTENDON \(BRUSHY CANYON\) FIELD -- Winkler COUNTY, TEXAS(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGLEndProductionProductionProductionProductionSalesProductionPricePricePriceMo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL Non-Commercial Cum28.519.5.0 Ult28.519.5.0 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6Mo-YearM$M$M$M$M$M$M$M$ (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulative Cum.Cash FlowEndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. %Mo-YearM$CountM$M$M$M$M$M$M$ Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeinDef InitialFinalUnits InitialFinal 5.00.000 Oil Rate99.99.bbls/mo 8.0%0.00.0% 0.0.$/w/mo Expense87.182587.1825 8.00.000 Gas Rate0.0.Mcf/mo 0.0%0.00.0% Revenue 10.00.000 GOR0.0.scf/bbl Oil71.094071.0940 12.00.000 NGL Rate0.0.bbls/mo Gas71.094071.0940 15.00.000 NGL Yield0.00.0bbl/MMcf 20.00.000 Gas Shrinkage0.00.0% Oil Severance0.00.0% Gas Severance0.00.0% NGL Severance0.00.0% Ad Valorem0.0 % 1 Months in first year .000 Year Life (01/2018)THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.ASN 88DEFAULT 1/10/2018 10:34:19 TEXAS REGISTERED ENGINEERING FIRM F-693. OIL PDP Table 15Cawley, Gillespie & Associates, Inc.   Table 16Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Developed Producing ReservesIMPETRO OPERATING LLC -- TUBB ESTATE 25 1 1CRITTENDON \(ELLEN. 21450\) FIELD -- Winkler COUNTY, TEXAS(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGLEndProductionProductionProductionProductionSalesProductionPricePricePriceMo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL Non-Commercial Cum.060.5.0 Ult.060.5.0 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6Mo-YearM$M$M$M$M$M$M$M$ (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulative Cum.Cash FlowEndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. %Mo-YearM$CountM$M$M$M$M$M$M$ Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeinDef InitialFinalUnits InitialFinal 5.00.000 Gas Rate308.308.Mcf/mo 10.0%0.00.0% 0.0.$/w/mo Expense87.182587.1825 8.00.000 Oil Rate0.0.bbls/mo 0.0%0.00.0% Revenue 10.00.000 NGL Rate0.0.bbls/mo Oil71.094071.0940 12.00.000 Cond Yield0.00.0bbl/MMcf Gas71.094071.0940 15.00.000 NGL Yield0.00.0bbl/MMcf 20.00.000 Gas Shrinkage100.0100.0% Oil Severance0.00.0% Gas Severance0.00.0% NGL Severance0.00.0% Ad Valorem0.0 % 1 Months in first year .000 Year Life (01/2018)THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.ASN 99DEFAULT 1/10/2018 10:34:19 TEXAS REGISTERED ENGINEERING FIRM F-693. GAS PDP Table 16Cawley, Gillespie & Associates, Inc.   Table 17Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Developed Producing ReservesIMPETRO OPERATING LLC -- TUBB ESTATE 25 3 3CRITTENDON \(BRUSHY CANYON\) FIELD -- Winkler COUNTY, TEXAS(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGLEndProductionProductionProductionProductionSalesProductionPricePricePriceMo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL12-20181.71.0.11.253.472.05149.2862.61910.268 11-20191.3.8.1.973.355.03849.2862.61910.268 12-2020 12-2021 12-2022 12-2023 12-2024 12-2025 12-2026 12-2027 12-2028 12-2029 12-2030 12-2031 12-2032 12-2033 12-2034 12-2035 12-2036 S Tot3.01.8.12.226.827.08949.2862.61910.268 After.0.0.0.000.000.000.000.000.000 Total3.01.8.12.226.827.08949.2862.61910.268 Cum11.312.7.0 Ult14.314.5.1 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6Mo-YearM$M$M$M$M$M$M$M$ 12-201861.7721.237.5210.0000.00063.5302.9841.58836.210 11-201947.955.930.3920.0000.00049.2782.3131.23241.143 12-2020 12-2021 12-2022 12-2023 12-2024 12-2025 12-2026 12-2027 12-2028 12-2029 12-2030 12-2031 12-2032 12-2033 12-2034 12-2035 12-2036 S Tot109.7272.167.9140.0000.000112.8075.2972.82038.363 After.000.000.0000.0000.000.000.000.000.000 Total109.7272.167.9140.0000.000112.8075.2972.82038.363 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulative Cum.Cash FlowEndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. %Mo-YearM$CountM$M$M$M$M$M$M$12-201849.42710.90.0000.0000.000.0009.5319.5319.145 11-201943.49010.90.0000.0000.000.0002.24311.77411.123 12-2020 12-2021 12-2022 12-2023 12-2024 12-2025 12-2026 12-2027 12-2028 12-2029 12-2030 12-2031 12-2032 12-2033 12-2034 12-2035 12-2036 S Tot92.916 0.0000.0000.000.00011.77411.77411.123 After.000 0.0000.0000.000.000.00011.77411.123 Total92.916 0.0000.0000.000.00011.77411.77411.123 Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeinDef InitialFinalUnits InitialFinal 5.0011.433 Oil Rate152.118.bbls/mo 15.2%1.600.0% 4,499.4,499.$/w/mo Expense91.531291.5312 8.0011.244 Gas Rate94.68.Mcf/mo 19.0%1.400.0% Revenue 10.0011.123 GOR619.581.scf/bbl Oil74.085274.0852 12.0011.006 NGL Rate6.4.bbls/mo Gas74.085274.0852 15.0010.838 NGL Yield67.368.7bbl/MMcf 20.0010.576 Gas Shrinkage39.839.2% Oil Severance4.64.6% Gas Severance7.57.5% NGL Severance7.57.5% Ad Valorem11.4 % 12 Months in first year 1.878 Year Life (11/2019)THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.ASN 71DEFAULT 1/10/2018 10:34:19 TEXAS REGISTERED ENGINEERING FIRM F-693. OIL PDP Table 17Cawley, Gillespie & Associates, Inc.  Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeinDef InitialFinalUnits InitialFinal 5.005,049.916 Table 18Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Developed Producing ReservesLILIS ENERGY, INC. -- WILD HOG BWX ST COM 1H #1HTBD (WOLFCAMP B) FIELD -- LEA COUNTY, NEW MEXICO(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGLEndProductionProductionProductionProductionSalesProductionPricePricePriceMo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL12-201883.6217.315.044.14678.0517.92047.7462.6198.728 12-201946.8121.78.424.72943.7204.43647.7462.6198.728 12-202033.787.66.017.78631.4453.19147.7462.6198.728 12-202126.569.04.814.01224.7732.51447.7462.6198.728 12-202222.157.54.011.67020.6322.09447.7462.6198.728 12-202319.049.53.410.04717.7631.80247.7462.6198.728 12-202416.843.73.08.87315.6881.59247.7462.6198.728 12-202515.039.02.77.92614.0141.42247.7462.6198.728 12-202613.635.42.47.19312.7171.29047.7462.6198.728 12-202712.532.52.26.59211.6551.18347.7462.6198.728 12-202811.529.92.16.08010.7501.09147.7462.6198.728 12-202910.627.51.95.5789.8621.00147.7462.6198.728 12-20309.725.31.75.1329.074.92147.7462.6198.728 12-20318.923.21.64.7228.349.84747.7462.6198.728 12-20328.221.41.54.3567.701.78147.7462.6198.728 12-20337.619.71.43.9967.065.71747.7462.6198.728 12-20347.018.11.23.6776.501.66047.7462.6198.728 12-20356.416.71.13.3835.981.60747.7462.6198.728 12-20365.915.41.13.1215.517.56047.7462.6198.728 S Tot365.5950.265.6193.019341.25734.62847.7462.6198.728 After2.46.3.41.2842.271.23047.7462.6198.728 Total367.9956.666.0194.303343.52834.85847.7462.6198.728 Cum57.055.6.0 Ult424.91,012.266.0 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6Mo-YearM$M$M$M$M$M$M$M$ 12-20182,107.820204.40669.1220.0000.0002,381.347171.162119.0674.864 12-20191,180.694114.49838.7180.0000.0001,333.91095.87766.6956.437 12-2020849.20582.35227.8480.0000.000959.40468.95847.9707.832 12-2021669.01464.87821.9390.0000.000755.83154.32637.7929.172 12-2022557.18054.03218.2720.0000.000629.48445.24531.47410.438 12-2023479.69546.51815.7310.0000.000541.94438.95327.09711.662 12-2024423.65841.08413.8930.0000.000478.63534.40323.93212.827 12-2025378.44636.70012.4100.0000.000427.55730.73121.37814.017 12-2026343.43033.30411.2620.0000.000387.99627.88819.40015.155 12-2027314.74230.52210.3210.0000.000355.58525.55817.77916.275 12-2028290.31428.1539.5200.0000.000327.98823.57516.39917.404 12-2029266.34425.8298.7340.0000.000300.90721.62815.04518.713 12-2030245.05023.7648.0360.0000.000276.85019.89913.84220.091 12-2031225.45921.8647.3930.0000.000254.71618.30812.73621.588 12-2032207.97920.1696.8200.0000.000234.96816.88911.74823.162 12-2033190.80718.5036.2570.0000.000215.56715.49410.77824.989 12-2034175.55217.0245.7570.0000.000198.33314.2559.91726.912 12-2035161.51715.6635.2970.0000.000182.47713.1169.12429.001 12-2036148.99514.4494.8860.0000.000168.32912.0998.41631.199 S Tot9,215.903893.711302.2160.0000.00010,411.829748.364520.59111.565 After61.3245.9472.0110.0000.00069.2824.9803.46432.703 Total9,277.227899.658304.2270.0000.00010,481.112753.344524.05611.705 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash FlowEndExpenseGross NetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. %Mo-YearM$CountM$M$M$M$M$M$M$12-2018124.80010.70.0000.000178.215.0001,788.1021,788.1021,716.955 12-2019124.80010.70.0000.00099.827.000946.7102,734.8122,540.798 12-2020124.80010.70.0000.00071.800.000645.8763,380.6883,051.193 12-2021124.80010.70.0000.00056.565.000482.3483,863.0363,397.495 12-2022124.80010.70.0000.00047.109.000380.8564,243.8923,646.008 12-2023124.80010.70.0000.00040.558.000310.5364,554.4283,830.188 12-2024124.80010.70.0000.00035.820.000259.6814,814.1083,970.180 12-2025124.80010.70.0000.00031.998.000218.6505,032.7594,077.312 12-2026124.80010.70.0000.00029.037.000186.8725,219.6304,160.548 12-2027124.80010.70.0000.00026.611.000160.8365,380.4664,225.676 12-2028124.80010.70.0000.00024.546.000138.6685,519.1344,276.726 12-2029124.80010.70.0000.00022.519.000116.9145,636.0484,315.851 12-2030124.80010.70.0000.00020.719.00097.5905,733.6384,345.545 12-2031124.80010.70.0000.00019.062.00079.8105,813.4484,367.626 12-2032124.80010.70.0000.00017.585.00063.9465,877.3944,383.714 12-2033124.80010.70.0000.00016.133.00048.3625,925.7564,394.776 12-2034124.80010.70.0000.00014.843.00034.5185,960.2754,401.957 12-2035124.80010.70.0000.00013.656.00021.7815,982.0564,406.081 12-2036124.80010.70.0000.00012.597.00010.4175,992.4734,407.881 S Tot2,371.200 0.0000.000779.201.0005,992.4735,992.4734,407.881 After54.093 0.0000.0005.185.0001.5615,994.0334,408.132 Total2,425.293 0.0000.000784.386.0005,994.0335,994.0334,408.132 Oil Rate10,834.454.bbls/mo 74.8%1.200.0% 16,000.16,000.$/w/mo Expense65.000065.0000 8.004,638.095 Gas Rate28,169.1,181.Mcf/mo 0.0%0.000.0% Revenue 10.004,408.132 GOR2,600.2,600.scf/bbl Oil52.812552.8125 12.004,206.396 NGL Rate1,879.83.bbls/mo Gas52.812552.8125 15.003,946.421 NGL Yield66.770.7bbl/MMcf 20.003,598.704 Gas Shrinkage35.431.7% Oil Severance7.17.1% Gas Severance7.97.9% NGL Severance7.97.9% Ad Valorem66.3 % 12 Months in first year 19.439 Year Life (06/2037) THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.ASN 314DEFAULT1/10/201810:34:19TEXAS REGISTERED ENGINEERING FIRM F-693. OILPDP Table 18 Cawley, Gillespie & Associates, Inc.   Table 19Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Developed Producing ReservesIMPETRO OPERATING LLC -- WOLFE UNIT #3H 3HCRITTENDON \(BRUSHY CANYON\) FIELD -- Winkler COUNTY, TEXAS(1) EndMo-Year(2)Gross OilProductionMBBLS(3)Gross GasProductionMMCF(4)Gross NGLProductionMBBLS(5)Net OilProductionMBBLS(6)Net GasSalesMMCF(7)Net NGLProductionMBBLS(8)Avg OilPrice$/BBL(9)Avg GasPrice$/MCF(10)Avg NGLPrice$/BBL12-2018.1.0.0.046.000.00047.746.000.000 12-2019 12-2020 12-2021 12-2022 12-2023 12-2024 12-2025 12-2026 12-2027 12-2028 12-2029 12-2030 12-2031 12-2032 12-2033 12-2034 12-2035 12-2036 S Tot.1.0.0.046.000.00047.746.000.000 After.0.0.0.000.000.000.000.000.000 Total.1.0.0.046.000.00047.746.000.000 Cum32.9.0.0 Ult32.9.0.0 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6Mo-YearM$M$M$M$M$M$M$M$ 12-20182.209.000.0000.0000.0002.209.102.055.000 12-2019 12-2020 12-2021 12-2022 12-2023 12-2024 12-2025 12-2026 12-2027 12-2028 12-2029 12-2030 12-2031 12-2032 12-2033 12-2034 12-2035 12-2036 S Tot2.209.000.0000.0000.0002.209.102.0554.618 After.000.000.0000.0000.000.000.000.000.000 Total2.209.000.0000.0000.0002.209.102.0554.618 (21)(22)(23) (24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash FlowEndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. %Mo-YearM$CountM$M$M$M$M$M$M$12-2018.00010.80.0000.0000.214.0001.8381.8381.830 12-2019 12-2020 12-202112-2022 12-2023 12-2024 12-2025 12-2026 12-2027 12-2028 12-2029 12-2030 12-2031 12-2032 12-2033 12-2034 12-2035 12-2036 S Tot.000 0.0000.0000.214.0001.8381.8381.830 Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeinDef InitialFinalUnits InitialFinal 5.001.834 Oil Rate147.0.bbls/mo 49.1%1.200.0% 0.0.$/w/mo Expense85.427785.4277 8.001.832 Gas Rate0.0.Mcf/mo 0.0%0 000.0% Revenue 10.00 1.830 GOR0.0.scf/bbl Oil68.993568.9935 12.001.829 NGL Rate0.0.bbls/mo Gas68.993568.9935 15.001.827 NGL Yield0.00.0bbl/MMcf 20.001.823 Gas Shrinkage0.00.0% Oil Severance4.60.0% Gas Severance0.00.0% NGL Severance0.00.0% Ad Valorem0.0 % 12 Months in first year .999 Year Life (12/2018) After.000 0.0000.0000.000.000.0001.8381.830 Total.000 0.0000.0000.214.0001.8381.8381.830 THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.ASN 111DEFAULT1/10/201810:34:19TEXAS REGISTERED ENGINEERING FIRM F-693. OILPDP Table 19Cawley, Gillespie & Associates, Inc.   Table 20Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Developed Producing ReservesIMPETRO OPERATING LLC -- WOLFE UNIT 1 1CRITTENDON \(PENN.\) FIELD -- Winkler COUNTY, TEXAS(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGLEndProductionProductionProductionProductionSalesProductionPricePricePriceMo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL12-2018.0116.17.7.00027.8822.998.0002.6198.214 12-2019.0110.37.4.00026.4892.848.0002.6198.214 06-2020.046.63.1.00011.1901.203.0002.6198.214 12-2021 12-2022 12-2023 12-2024 12-2025 12-2026 12-2027 12-2028 12-2029 12-2030 12-2031 12-2032 12-2033 12-2034 12-2035 12-2036 S Tot.0273.018.2.00065.5617.050.0002.6198.214 After.0.0.0.000.000.000.000.000.000 Total.0273.018.2.00065.5617.050.0002.6198.214 Cum766.767,568.6.0 Ult766.767,841.618.2 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6Mo-YearM$M$M$M$M$M$M$M$ 12-2018.00073.02024.6270.0000.00097.6477.3432.44112.076 12-2019.00069.37123.3960.0000.00092.7686.9762.31912.711 06-2020.00029.3069.8840.0000.00039.1902.947.98013.042 12-2021 12-2022 12-2023 12-2024 12-2025 12-2026 12-2027 12-2028 12-2029 12-2030 12-2031 12-2032 12-2033 12-2034 12-2035 12-2036 S Tot.000171.69857.9070.0000.000229.60517.2665.74012.497 After.000.000.0000.0000.000.000.000.000.000 Total.000171.69857.9070.0000.000229.60517.2665.74012.497 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash FlowEndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. %Mo-YearM$CountM$M$M$M$M$M$M$12-201879.65010.50.0000.0000.000.0008.2128.2127.851 12-201979.65010.50.0000.0000.000.0003.82212.03511.180 06-202034.52310.50.0000.0000.000.000.74012.77511.782 12-2021 12-2022 12-2023 12-2024 12-2025 12-2026 12-2027 12-2028 12-2029 12-2030 12-2031 12-2032 12-203312-2034 12-2035 12-2036 S Tot193.824 0.0000.0000.000.00012.77512.77511.782 After.000 0.0000.0000.000.000.00012.77511.782 Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeiNDef InitialFinalUnits InitialFinal 5.0012.251 Gas Rate9,931.8,765.Mcf/mo 5.0%0.000.0% 13,785.13,785.$/w/mo Expense48.143348.1433 8.0011.963 Oil Rate0.0.bbls/mo 0.0%0.000.0% Revenue 10.0011.782 NGL Rate673.597.bbls/mo Oil38.730738.7307 12.0011.607 Cond Yield0.00.0bbl/MMcf Gas38.730738.7307 15.0011.358 NGL Yield67.868.1bbl/MMcf 20.00210.971 Gas Shrinkage38.137.9% Oil Severance0.00.0% Gas Severance7.57.5% NGL Severance7.57.5% Ad Valorem18.8 % 12 Months in first year 2.437 Year Life (06/2020) Total193.824 0.0000.0000.000.00012.77512.77511.782 THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.ASN 50DEFAULT1/10/201810:34:19TEXAS REGISTERED ENGINEERING FIRM F-693. GASPDP Table 20Cawley, Gillespie & Associates, Inc.   Table 21Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Developed Producing ReservesIMPETRO OPERATING LLC -- WOLFE UNIT 4,5&6 4,5,6&7CRITTENDON \(BELL CANYON\) FIELD -- Winkler COUNTY, TEXAS(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGLEndProductionProductionProductionProductionSalesProductionPricePricePriceMo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL12-201811.43.2.26.5801.145.12346.7192.6788.728 12-201910.22.9.25.9221.030.11146.7192.6788.728 12-20209.32.6.25.393.930.10046.7192.6788.728 12-20218.52.3.24.921.834.09046.7192.6788.728 12-20227.82.1.14.526.751.08146.7192.6788.728 12-20237.21.9.14.164.676.07346.7192.6788.728 12-20246.61.7.13.841.610.06646.7192.6788.728 04-20251.6.4.0.936.147.01646.7192.6788.728 12-2026 12-2027 12-2028 12-2029 12-2030 12-2031 12-2032 12-2033 12-2034 12-2035 12-2036 S Tot62.817.11.136.2826.122.65846.7192.6788.728 After.0.0.0.000.000.000.000.000.000 Total62.817.11.136.2826.122.65846.7192.6788.728 Cum945.8877.9.0 Ult1,008.6895.01.1 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6Mo-YearM$M$M$M$M$M$M$M$ 12-2018307.4033.0661.0740.0000.000311.54314.5057.78923.067 12-2019276.6592.759.9670.0000.000280.38513.0557.01025.630 12-2020251.9352.490.8720.0000.000255.29711.8866.38228.155 12-2021229.9282.235.7830.0000.000232.94510.8445.82430.870 12-2022211.4422.011.7050.0000.000214.1589.9675.35433.597 12-2023194.5381.810.6340.0000.000196.9839.1664.92536.546 12-2024179.4551.634.5720.0000.000181.6618.4524.54239.649 04-202543.720.392.1380.0000.00044.2502.0591.10641.403 12-2026 12-2027 12-2028 12-2029 12-2030 12-2031 12-2032 12-2033 12-203412-2035 12-2036 S Tot1,695.07916.3985.7460.0000.0001,717.22379.93442.93130.382 After.000.000.0000.0000.000.000.000.000.000 Total1,695.07916.3985.7460.0000.0001,717.22379.93442.93130.382 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash FlowEndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. %Mo-YearM$CountM$M$M$M$M$M$M$12-2018158.01921.40.0000.0000.000.000131.230131.230125.372 12-2019158.01921.40.0000.0000.000.000102.302233.531214.231 12-2020158.01921.40.0000.0000.000.00079.010312.541276.633 12-2021158.01921.40.0000.0000.000.00058.259370.800318.459 12-2022158.01921.40.0000.0000.000.00040.818411.618345.113 12-2023158.01921.40.0000.0000.000.00024.872436.491359.896 12-2024158.01921.40.0000.0000.000.00010.649447.139365.679 04-202540.18121.40.0000.0000.000.000.905448.044366.139 12-2026 12-2027 12-2028 12-2029 12-2030 12-2031 12-2032 12-2033 12-2034 12-2035 12-2036 S Tot1,146.315 0.0000.0000.000.000448.044448.044366.139 After.000 0.0000.0000.000.000.000448.044366.139 Evaluation Parameter (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeinDef InitialFinalUnits InitialFinal 5.00402.837 Oil Rate1,003.518.bbls/mo 11.0%0.900.0% 0.0.$/w/mo Expense68.574068.5740 8.00379.944 Gas Rate280.130.Mcf/mo 10.0%0.000.0% 19,202.19,202.$/mo Revenue 10.00366.139 GOR279.251.scf/bbl Oil57.805057.8050 12.00353.359 NGL Rate19.8.bbls/mo Gas57.805057.8050 15.00335.892 NGL Yield67.668.3bbl/MMcf 20.00310.621 Gas Shrinkage38.939.1% Oil Severance4.64.6% Gas Severance7.57.5% NGL Severance7.57.5% Ad Valorem36.3 % 12 Months in first year 7.258 Year Life (04/2025) Total1,146.315 0.0000.0000.000.000448.044448.044366.139 THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.ASN 15DEFAULT1/10/201810:34:19TEXAS REGISTERED ENGINEERING FIRM F-693. OILPDP Table 21Cawley, Gillespie & Associates, Inc.  Table I - PDNPComposite Reserve Estimates and Economic ForecastsLilis Energy, Inc. InterestsDelaware Basin Properties in Texas and New MexicoProved Developed Non-Producing ReservesAs of December 31, 2017(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGLEndProductionProductionProductionProductionSalesProductionPricePricePriceMo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL12-2018360.51,124.076.6226.251475.61647.50547.7462.6118.198 12-2019193.1651.744.0121.630276.01427.24447.7462.6047.797 12-2020127.0455.430.579.949192.51718.83147.7462.6007.485 12-202196.1360.124.060.499152.05714.78447.7462.5977.276 12-202278.2302.520.149.240127.66112.36047.7462.5947.130 12-202366.3262.517.441.763110.71710.68847.7462.5937.028 12-202458.0233.115.436.49898.2759.46847.7462.5926.957 12-202551.4208.813.832.34987.9978.46747.7462.5916.911 12-202646.3189.412.529.18079.8467.67647.7462.5916.885 12-202742.3173.311.526.62273.0257.01847.7462.5916.873 12-202836.9159.710.623.10867.3096.46947.7462.5916.871 12-202933.1146.59.720.69561.7525.93547.7462.5916.871 12-203030.5201.412.919.04184.3837.79047.7462.5715.430 12-203128.0197.412.617.51982.6317.58947.7462.5685.243 12-203225.9182.111.616.16076.2257.00147.7462.5685.243 12-203323.7167.010.714.82669.9316.42347.7462.5685.243 12-203421.8153.79.813.64164.3405.90947.7462.5685.243 12-203520.1141.49.012.55059.1975.43747.7462.5685.243 12-203618.5113.77.311.53847.6744.42847.7462.5745.653 S Tot1,357.65,423.6360.1853.0592,287.167221.02147.7462.5937.064 After6.720.21.44.1518.468.85947.7462.6198.728 Total1,364.35,443.8361.5857.2102,295.636221.88147.7462.5947.071 Cum.0.0.0 Ult1,364.35,443.8361.5 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6Mo-YearM$M$M$M$M$M$M$M$ 12-201810,802.6391,241.603389.4700.0000.00012,433.712612.401310.8434.490 12-20195,807.357718.833212.4150.0000.0006,738.605334.313168.4656.087 12-20203,817.266500.474140.9530.0000.0004,458.692224.498111.4677.557 12-20212,888.620394.822107.5610.0000.0003,391.003171.16584.7758.915 12-20222,351.016331.20288.1220.0000.0002,770.340140.09669.25910.183 12-20231,994.008287.07775.1100.0000.0002,356.196119.31558.90511.404 12-20241,742.625254.71765.8700.0000.0002,063.213104.57951.58012.571 12-20251,544.542228.02058.5160.0000.0001,831.07792.87245.77713.771 12-20261,393.217206.86752.8490.0000.0001,652.93383.86741.32314.931 12-20271,271.098189.18348.2360.0000.0001,508.51776.55137.71316.083 12-20281,103.323174.37444.4490.0000.0001,322.14567.40633.05416.164 12-2029988.131159.97640.7790.0000.0001,188.88560.72829.72216.946 12-2030909.132216.92342.3030.0000.0001,168.35761.48929.20915.843 12-2031836.449212.21539.7870.0000.0001,088.45257.59127.21116.615 12-2032771.599195.76236.7030.0000.0001,004.06353.12625.10217.828 12-2033707.890179.59833.6720.0000.000921.16048.74023.02919.235 12-2034651.296165.24030.9800.0000.000847.51644.84321.18820.716 12-2035599.226152.02928.5030.0000.000779.75941.25819.49422.326 12-2036550.884122.69725.0330.0000.000698.61436.55517.46525.350 S Tot40,730.3175,931.6141,561.3110.0000.00048,223.2412,431.3921,205.58110.307 After198.20422.1787.5000.0000.000227.88211.3835.69733.423 Total40,928.5215,953.7921,568.8100.0000.00048,451.1232,442.7751,211.27810.409 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash FlowEndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. %Mo-YearM$CountM$M$M$M$M$M$M$12-2018485.50654.20.0000.0001,024.7916,266.4093,733.7633,733.7633,395.776 12-2019576.56054.20.0000.000551.696.0005,107.5728,841.3347,845.272 12-2020576.56054.20.0000.000362.581.0003,183.58612,024.92010,362.114 12-2021576.56054.20.0000.000274.358.0002,284.14514,309.06512,002.393 12-2022576.56054.20.0000.000223.290.0001,761.13616,070.20113,151.732 12-2023576.56054.20.0000.000189.379.0001,412.03717,482.23813,989.313 12-2024576.56054.20.0000.000165.502.0001,164.99118,647.22914,617.410 12-2025576.56054.20.0000.000146.688.000969.18119,616.41015,092.322 12-2026576.56054.20.0000.000132.316.000818.86720,435.27615,457.090 12-2027576.56054.20.0000.000120.717.000696.97621,132.25215,739.335 12-2028518.15454.20.0000.000104.678.000598.85321,731.10515,959.797 12-2029496.77543.40.0000.00093.709.000507.95122,239.05716,129.777 12-2030518.49243.40.0000.00086.218.000472.95022,712.00716,273.562 12-2031522.54443.40.0000.00079.325.000401.78123,113.78716,384.709 12-2032522.54443.40.0000.00073.175.000330.11723,443.90416,467.748 12-2033522.54443.40.0000.00067.133.000259.71523,703.61916,527.136 12-2034522.54443.40.0000.00061.766.000197.17523,900.79516,568.139 12-2035522.54443.40.0000.00056.828.000139.63624,040.43016,594.552 12-2036514.63043.40.0000.00052.238.00077.72624,118.15616,608.013 S Tot10,335.317 0.0000.0003,866.3866,266.40924,118.15624,118.15616,608.013 After186.374 0.0000.00018.211.0006.21724,124.37316,609.000 Total10,521.690 0.0000.0003,884.5976,266.40924,124.37324,124.37316,609.000 SEC Pricing YE2017 PercentCum. Disc. WTI CushingHenry Hub 5.00 19,645.597 YearOil $/STBGas $/MMBTU 8.00 17,696.862 201851.342.976 10.00 16,609.000 ThereafterFlatFlat 12.00 15,654.402 Cap51.342.976 15.00 14,423.212 20.00 12.773.115 12 Months in first year 19.929 Year Life (12/2037) THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.1/10/201810:34:19TEXAS REGISTERED ENGINEERING FIRM F-693. SummaryCawley, Gillespie & Associates, Inc.   Table II - PDNPLease Reserve SummaryLilis Energy, Inc. InterestsDelaware Basin Properties in Texas and New MexicoProved Developed Non-Producing ReservesAs of December 31, 2017 OPERATORCurrentInterest WellCntLifeUltimateRecoveryGrossReservesNetReservesOil RevenueGas RevenueProd TaxAdv. TaxExpensesInvestmentsFuture NetCash FlowCash FlowDisc.@ 10.0LEASE NAMEStart % ____________MBBL / MMCF____________M$ / M$M$ / M$M$ / M$M$M$TableClassMajor Well No.DateASN PHANTOM (WOLFCAMP B) -- WINKLER COUNTY, TEXASLILIS ENERGY, INC.GRIZZLY #2H61.0414NI1427.7427.7261.112,466.0715.94,348.77,003.24,906.71 PDNP Oil 02/1842686.6526WI18.81,283.21,283.2532.61,394.9358.31,906.4 CHEYENNE (ATOKA) -- WINKLER COUNTY, TEXASTRATON OPERATING COMPANYHILL, A. G. 1{INCR}58.3125NI11.10.00.00.0119.9170.21,428.0732.02 PDNPGas101/1847877.7500WI18.75,479.61,574.6651.91,649.144.10.0 PHANTOM (WOLFCAMP B) -- WINKLER COUNTY, TEXASLILIS ENERGY, INC.KUDU #2H60.1633NI1433.3433.3260.712,446.8714.84,142.78,897.16,681.33 PDNPOil 02/1832079.2604WI19.81,299.91,299.9531.81,392.7357.8198.2 LION #3H66.2369NI1428.7428.7284.013,558.5778.74,691.35,737.63,429.44 PDNPOil 04/1842792.8237WI18.91,286.21,286.2579.31,517.1389.73,991.4 CRITTENDON (BRUSHY CANYON) -- WINKLER COUNTY, TEXASIMPETRO OPERATING LLCWOLFE UNIT #3H WORKOVER68.9934NI174.674.651.52,457.2113.41,053.41,058.4859.65PDNPOil3H01/1842585.2409WI10.20.00.00.00.061.4170.5 GRAND TOTAL 41,364.31,364.3857.240,928.52,442.814,406.324,124.416,609.0 5,443.85,443.82,295.65,953.81,211.36,266.4 THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.TEXAS REGISTERED ENGINEERING FIRM F-693. Scenario:.5501/10/2018 10:34:19 AM Cawley, Gillespie & Associates, Inc. Page 1  Rate-Time History-Forecast CurvesAndTabular Reserves and EconomicsBy Property Cawley, Gillespie & Associates, Inc.Petroleum Consultants   Table 1Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Developed Non-Producing ReservesLILIS ENERGY, INC. -- GRIZZLY #2HPHANTOM (WOLFCAMP B) FIELD -- WINKLER COUNTY, TEXAS(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGLEndProductionProductionProductionProductionSalesProductionPricePricePriceMo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL12-2018114.4343.323.769.847142.48814.45847.7462.6198.728 12-201959.7179.012.436.42874.3147.54147.7462.6198.728 12-202039.2117.78.123.94348.8434.95647.7462.6198.728 12-202129.789.06.118.11036.9443.74947.7462.6198.728 12-202224.172.45.014.73430.0573.05047.7462.6198.728 12-202320.561.44.212.49325.4862.58647.7462.6198.728 12-202417.953.63.710.91622.2682.26047.7462.6198.728 12-202515.847.53.39.67319.7342.00247.7462.6198.728 12-202614.342.93.08.72417.7981.80647.7462.6198.728 12-202713.039.12.77.95916.2361.64847.7462.6198.728 12-202812.036.02.57.33414.9611.51847.7462.6198.728 12-202911.033.12.36.72813.7261.39347.7462.6198.728 12-203010.130.42.16.19012.6291.28147.7462.6198.728 12-20319.328.01.95.69611.6191.17947.7462.6198.728 12-20328.625.81.85.25410.7181.08847.7462.6198.728 12-20337.923.71.64.8209.833.99847.7462.6198.728 12-20347.321.81.54.4359.047.91847.7462.6198.728 12-20356.720.11.44.0808.324.84547.7462.6198.728 12-20366.118.31.33.7247.598.77147.7462.6198.728 S Tot427.71,283.288.5261.089532.62254.04547.7462.6198.728 After.0.0.0.000.000.000.000.000.000 Total427.71,283.288.5261.089532.62254.04547.7462.6198.728 Cum.0.0.0 Ult427.71,283.288.5 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6Mo-YearM$M$M$M$M$M$M$M$ 12-20183,334.932373.159126.1870.0000.0003,834.278191.52595.8574.518 12-20191,739.321194.62065.8120.0000.0001,999.75399.88949.9946.255 12-20201,143.172127.91443.2550.0000.0001,314.34265.65232.8597.870 12-2021864.66696.75132.7170.0000.000994.13449.65824.8539.388 12-2022703.48478.71626.6180.0000.000808.81840.40120.22010.816 12-2023596.49466.74422.5700.0000.000685.80934.25717.14512.189 12-2024521.18558.31719.7210.0000.000599.22329.93214.98113.494 12-2025461.86651.68017.4760.0000.000531.02226.52513.27614.822 12-2026416.56046.61115.7620.0000.000478.93323.92311.97316.090 12-2027380.01142.52114.3790.0000.000436.91121.82410.92317.334 12-2028350.16839.18213.2500.0000.000402.59920.11010.06518.542 12-2029321.25535.94712.1560.0000.000369.35818.4509.23419.927 12-2030295.57233.07311.1840.0000.000339.82816.9758.49621.384 12-2031271.94230.42910.2900.0000.000312.66015.6187.81622.968 12-2032250.85828.0699.4920.0000.000288.41914.4077.21024.633 12-2033230.14525.7528.7080.0000.000264.60513.2176.61526.566 12-2034211.74623.6938.0120.0000.000243.45112.1616.08628.600 12-2035194.81721.7997.3710.0000.000223.98711.1885.60030.810 12-2036177.82919.8986.7290.0000.000204.45510.2135.11133.126 S Tot12,466.0221,394.874471.6890.0000.00014,332.584715.923358.31511.296 After.000.000.0000.0000.000.000.000.000.000 Total12,466.0221,394.874471.6890.0000.00014,332.584715.923358.31511.296 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash FlowEndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. %Mo-YearM$CountM$M$M$M$M$M$M$12-2018140.13010.90.0000.000325.2221,906.3581,175.1871,175.1871,062.893 12-2019166.37310.90.0000.000169.618.0001,513.8792,689.0662,381.760 12-2020166.37310.90.0000.000111.482.000937.9763,627.0423,123.332 12-2021166.37310.90.0000.00084.322.000668.9284,295.9693,603.720 12-2022166.37310.90.0000.00068.604.000513.2204,809.1903,938.666 12-2023166.37310.90.0000.00058.170.000409.8645,219.0534,181.793 12-2024166.37310.90.0000.00050.826.000337.1125,556.1654,363.548 12-2025166.37310.90.0000.00045.041.000279.8075,835.9734,500.660 12-2026166.37310.90.0000.00040.623.000236.0406,072.0134,605.806 12-2027166.37310.90.0000.00037.059.000200.7326,272.7464,687.094 12-2028166.37310.90.0000.00034.148.000171.9036,444.6484,750.381 12-2029166.37310.90.0000.00031.329.000143.9726,588.6204,798.564 12-2030166.37310.90.0000.00028.824.000119.1616,707.7814,834.823 12-2031166.37310.90.0000.00026.520.00096.3336,804.1144,861.478 12-2032166.37310.90.0000.00024.464.00075.9656,880.0804,880.593 12-2033166.37310.90.0000.00022.444.00055.9566,936.0364,893.393 12-2034166.37310.90.0000.00020.649.00038.1816,974.2174,901.339 12-2035166.37310.90.0000.00018.998.00021.8286,996.0454,905.475 12-2036164.58410.90.0000.00017.342.0007.2057,003.2504,906.728 S Tot3,133.056 0.0000.0001,215.6831,906.3587,003.2507,003.2504,906.728 After.000 0.0000.0000.000.000.0007,003.2504,906.728 Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeinDef InitialFinalUnits Final 5.005,765.007 Oil Rate22,812.492.bbls/mo 96.5%1.200.0% 1,713.15,999.$/w/mo Expense86.652686.6526 8.005,216.055 Gas Rate68,437.1,476.Mcf/mo 0.0%0.000.0% Revenue 10.004,906.728 GOR3,000.3,000.scf/bbl Oil61.041461.0414 12.004,633.554 NGL Rate459.101.bbls/mo Gas61.041461.0414 15.004,278.801 NGL Yield6.768.7bbl/MMcf 20.003,799.071 Gas Shrinkage92.831.5% Oil Severance4.64.6% Gas Severance7.57.5% NGL Severance7.57.5% Ad Valorem41.0 % Start Date: 02/2018 11 Months in year ’18 18.907 Year Life (12/2036) Total3,133.056 0.0000.0001,215.6831,906.3587,003.2507,003.2504,906.728 THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.ASN 426 DEFAULT1/10/201810:34:19TEXAS REGISTERED ENGINEERING FIRM F-693. OILPDNP Table 1Cawley, Gillespie & Associates, Inc.   Table 2Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Developed Non-Producing ReservesTRATON OPERATING COMPANY -- HILL, A. G. 1{INCR} 1CHEYENNE \(ATOKA\) FIELD -- Winkler COUNTY, TEXAS (1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGL EndProductionProductionProductionProductionSalesProductionPricePricePrice Mo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL 12-2018.0107.66.5.00044.5683.766.0002.5302.054 12-2019.0108.66.5.00044.9713.800.0002.5302.054 12-2020.0100.26.0.00041.4853.506.0002.5302.054 12-2021.091.95.5.00038.0593.216.0002.5302.054 12-2022.084.65.1.00035.0172.959.0002.5302.054 12-2023.077.84.7.00032.2172.723.0002.5302.054 12-2024.071.84.3.00029.7192.511.0002.5302.054 12-2025.065.94.0.00027.2662.304.0002.5302.054 12-2026.060.63.6.00025.0862.120.0002.5302.054 12-2027.055.73.3.00023.0801.950.0002.5302.054 12-2028.051.43.1.00021.2911.799.0002.5302.054 12-2029.047.22.8.00019.5331.651.0002.5302.054 12-2030.0110.06.6.00045.5393.848.0002.5302.054 12-2031.0113.36.8.00046.8933.963.0002.5302.054 12-2032.0104.56.3.00043.2583.656.0002.5302.054 12-2033.095.95.8.00039.6863.354.0002.5302.054 12-2034.088.25.3.00036.5133.086.0002.5302.054 12-2035.081.14.9.00033.5942.839.0002.5302.054 10-2036.058.33.5.00024.1372.040.0002.5302.054 S Tot.01,574.694.5.000651.91255.091.0002.5302.054 After.0.0.0.000.000.000.000.000.000 Total.01,574.694.5.000651.91255.091.0002.5302.054 Cum1.13,905.0.0 Ult1.15,479.694.5 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6 Mo-YearM$M$M$M$M$M$M$M$ 12-2018.000112.7387.7340.0000.000120.473.0453.012.000 12-2019.000113.7607.8040.0000.000121.5645.2983.039.000 12-2020.000104.9407.1990.0000.000112.1398.4522.803.000 12-2021.00096.2756.6050.0000.000102.8807.7542.572.000 12-2022.00088.5786.0770.0000.00094.6557.1342.366.000 12-2023.00081.4975.5910.0000.00087.0886.5642.177.000 12-2024.00075.1785.1580.0000.00080.3366.0552.008.000 12-2025.00068.9714.7320.0000.00073.7025.5551.843.000 12-2026.00063.4574.3530.0000.00067.8105.1111.695.000 12-2027.00058.3844.0050.0000.00062.3894.7021.560.000 12-2028.00053.8573.6950.0000.00057.5524.3381.439.000 12-2029.00049.4103.3900.0000.00052.8003.9801.320.000 12-2030.000115.1967.9030.0000.000123.0999.2783.0772.152 12-2031.000118.6218.1380.0000.000126.7599.5543.1692.480 12-2032.000109.4257.5070.0000.000116.9328.8132.9232.688 12-2033.000100.3906.8870.0000.000107.2778.0852.6822.930 12-2034.00092.3646.3370.0000.00098.7007.4392.4683.185 12-2035.00084.9805.8300.0000.00090.8096.8442.2703.462 10-2036.00061.0574.1890.0000.00065.2454.9181.6313.673 S Tot.0001,649.076113.1330.0000.0001,762.209119.91844.0551.178 After.000.000.0000.0000.000.000.000.000.000 Total.0001,649.076113.1330.0000.0001,762.209119.91844.0551.178 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash Flow EndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. % Mo-YearM$CountM$M$M$M$M$M$M$ 12-2018.00010.80.0000.0000.000.000117.416117.416111.592 12-2019.00010.80.0000.0000.000.000113.227230.643209.930 12-2020.00010.80.0000.0000.000.000100.884331.527289.503 12-2021.00010.80.0000.0000.000.00092.554424.081355.865 12-2022.00010.80.0000.0000.000.00085.154509.235411.375 12-2023.00010.80.0000.0000.000.00078.347587.582457.807 12-2024.00010.80.0000.0000.000.00072.272659.854496.743 12-2025.00010.80.0000.0000.000.00066.305726.159529.214 12-2026.00010.80.0000.0000.000.00061.004787.163556.375 12-2027.00010.80.0000.0000.000.00056.127843.290579.095 12-2028.00010.80.0000.0000.000.00051.775895.065598.146 12-2029.00010.80.0000.0000.000.00047.500942.566614.035 12-203021.71710.80.0000.0000.000.00089.0271,031.592641.001 12-203125.76910.80.0000.0000.000.00088.2671,119.859665.407 12-203225.76910.80.0000.0000.000.00079.4261,199.285685.372 12-203325.76910.80.0000.0000.000.00070.7401,270.025701.537 12-203425.76910.80.0000.0000.000.00063.0241,333.049714.629 12-203525.76910.80.0000.0000.000.00055.9251,388.974725.192 10-203619.64410.80.0000.0000.000.00039.0521,428.027731.968 S Tot170.209 0.0000.0000.000.0001,428.0271,428.027731.968 After.000 0.0000.0000.000.000.0001,428.027731.968 Total170.209 0.0000.0000.000.0001,428.0271,428.027731.968 Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinal Units DeinDef InitialFinalUnits Final 5.002,147.204 Gas Rate18,835.6,835.Mcf/mo 8.0%0.000.0% 2,761.2,721.$/w/mo Expense77.750077.7500 8.001,854.416 Oil Rate0.0.bbls/mo 0.0%0.000.0% Revenue 10.001,698.806 NGL Rate1,147.361.bbls/mo Oil58.312558.3125 12.001,567.224 Cond Yield0.00.0bbl/MMcf Gas58.312558.3125 15.001,404.751 NGL Yield60.952.9bbl/MMcf 20.001,200.504 Gas Shrinkage29.236.5% Oil Severance0.00.0% Gas Severance0.07.5% NGL Severance0.07.5% Ad Valorem16.9 % Start Date: 01/201812 Months in year ‘1818.771 Year Life (10/2036) THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.TEXAS REGISTERED ENGINEERING FIRM F-693.ASN 478DEFAULT 1/10/2018 10:34:19 GAS PDNPTable 2 Cawley, Gillespie & Associates, Inc.   Table 3Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Developed Non-Producing ReservesLILIS ENERGY, INC. -- KUDU #2HPHANTOM (WOLFCAMP B) FIELD -- WINKLER COUNTY, TEXAS (1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGL EndProductionProductionProductionProductionSalesProductionPricePricePrice Mo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL 12-2018117.9353.624.470.906144.64814.67847.7462.6198.728 12-201958.3174.812.135.05271.5067.25647.7462.6198.728 12-202038.7116.08.023.26447.4584.81647.7462.6198.728 12-202129.488.16.117.66836.0423.65747.7462.6198.728 12-202223.971.85.014.40729.3902.98247.7462.6198.728 12-202320.361.04.212.23324.9562.53247.7462.6198.728 12-202417.853.43.710.69921.8272.21547.7462.6198.728 12-202515.847.33.39.48919.3571.96447.7462.6198.728 12-202614.242.72.98.56317.4681.77247.7462.6198.728 12-202713.039.02.77.81515.9421.61847.7462.6198.728 12-202812.035.92.57.20214.6921.49147.7462.6198.728 12-202911.032.92.36.60713.4791.36847.7462.6198.728 12-203010.130.32.16.07912.4021.25847.7462.6198.728 12-20319.327.91.95.59311.4101.15847.7462.6198.728 12-20328.625.71.85.16010.5251.06847.7462.6198.728 12-20337.923.61.64.7349.656.98047.7462.6198.728 12-20347.221.71.54.3558.884.90247.7462.6198.728 12-20356.720.01.44.0078.174.82947.7462.6198.728 12-20366.118.41.33.6967.540.76547.7462.6198.728 S Tot428.01,284.188.6257.528525.35753.30847.7462.6198.728 After5.315.81.13.1596.444.65447.7462.6198.728 Total433.31,299.989.7260.686531.80053.96247.7462.6198.728 Cum.0.0.0 Ult433.31,299.989.7 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6 Mo-YearM$M$M$M$M$M$M$M$ 12-20183,385.484378.816128.1000.0000.0003,892.400194.42897.3104.226 12-20191,673.608187.26763.3260.0000.0001,924.20196.11548.1055.875 12-20201,110.761124.28842.0290.0000.0001,277.07763.79131.9277.367 12-2021843.57094.39031.9190.0000.000969.88048.44624.2478.772 12-2022687.86576.96826.0270.0000.000790.86039.50419.77210.094 12-2023584.08765.35622.1010.0000.000671.54333.54416.78911.367 12-2024510.85257.16119.3300.0000.000587.34329.33814.68412.576 12-2025453.04050.69217.1420.0000.000520.87526.01813.02213.807 12-2026408.82945.74615.4690.0000.000470.04423.47911.75114.983 12-2027373.12241.75014.1180.0000.000428.99121.42810.72516.137 12-2028343.87238.47713.0110.0000.000395.36119.7499.88417.260 12-2029315.48035.30011.9370.0000.000362.71718.1189.06818.550 12-2030290.25832.47810.9830.0000.000333.71916.6708.34319.907 12-2031267.05329.88210.1050.0000.000307.03915.3377.67621.382 12-2032246.34827.5659.3210.0000.000283.23414.1487.08122.933 12-2033226.00825.2898.5520.0000.000259.84812.9806.49624.733 12-2034207.93923.2677.8680.0000.000239.07411.9425.97726.628 12-2035191.31521.4077.2390.0000.000219.96110.9875.49928.687 12-2036176.48219.7476.6780.0000.000202.90710.1355.07330.852 S Tot12,295.9711,375.846465.2540.0000.00014,137.072706.157353.42710.501 After150.81816.8765.7070.0000.000173.4008.6614.33533.320 Total12,446.7891,392.722470.9610.0000.00014,310.472714.819357.76210.777 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash Flow EndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. % Mo-YearM$CountM$M$M$M$M$M$M$ 12-2018135.42210.80.0000.000306.394198.1512,960.6942,960.6942,827.567 12-2019152.18010.80.0000.000151.465.0001,476.3354,437.0294,113.523 12-2020152.18010.80.0000.000100.526.000928.6535,365.6824,847.663 12-2021152.18010.80.0000.00076.345.000668.6616,034.3445,327.830 12-2022152.18010.80.0000.00062.253.000517.1516,551.4955,665.323 12-2023152.18010.80.0000.00052.861.000416.1696,967.6645,912.177 12-2024152.18010.80.0000.00046.233.000344.9087,312.5726,098.125 12-2025152.18010.80.0000.00041.001.000288.6547,601.2256,239.564 12-2026152.18010.80.0000.00037.000.000245.6347,846.8596,348.978 12-2027152.18010.80.0000.00033.768.000210.8898,057.7486,434.374 12-2028152.18010.80.0000.00031.121.000182.4278,240.1756,501.532 12-2029152.18010.80.0000.00028.552.000154.8008,394.9756,553.334 12-2030152.18010.80.0000.00026.269.000130.2578,525.2326,592.966 12-2031152.18010.80.0000.00024.169.000107.6778,632.9106,622.755 12-2032152.18010.80.0000.00022.295.00087.5308,720.4406,644.774 12-2033152.18010.80.0000.00020.454.00067.7388,788.1786,660.265 12-2034152.18010.80.0000.00018.819.00050.1568,838.3346,670.697 12-2035152.18010.80.0000.00017.314.00033.9808,872.3146,677.127 12-2036152.18010.80.0000.00015.972.00019.5478,891.8616,680.496 S Tot2,874.662 0.0000.0001,112.814198.1518,891.8618,891.8616,680.496 After141.544 0.0000.00013.649.0005.2108,897.0716,681.321 Total3,016.206 0.0000.0001,126.463198.1518,897.0718,897.0716,681.321 Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinal Units DeinDef InitialFinalUnits Final 5.007,581.893 Oil Rate22,812.453.bbls/mo 96.5%1.200.0% 10,856.15,999.$/w/mo Expense79.260479.2604 8.007,004.908 Gas Rate68,437.1,360.Mcf/mo 0.0%0.000.0% Revenue 10.006,681.321 GOR3,000.3,000.scf/bbl Oil60.163360.1633 12.006,396.397 NGL Rate2,719.92.bbls/mo Gas60.163360.1633 15.006,027.436 NGL Yield39.768.3bbl/MMcf 20.005,529.989 Gas Shrinkage57.431.8% Oil Severance4.64.6% Gas Severance7.57.5% NGL Severance7.57.5% Ad Valorem37.1% Start Date: 02/201811 Months in year ‘1819.846 Year Life (12/2037) THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.TEXAS REGISTERED ENGINEERING FIRM F-693.ASN 320DEFAULT 1/10/2018 10:34:19 OIL PDNPTable 3 Cawley, Gillespie & Associates, Inc.   Table 4Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Developed Non-Producing ReservesLILIS ENERGY, INC. -- LION #3HPHANTOM (WOLFCAMP B) FIELD -- WINKLER COUNTY, TEXAS (1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGL EndProductionProductionProductionProductionSalesProductionPricePricePrice Mo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL 12-2018106.5319.522.070.546143.91314.60347.7462.6198.728 12-201963.1189.213.141.77685.2228.64847.7462.6198.728 12-202040.5121.58.426.82954.7315.55447.7462.6198.728 12-202130.491.16.320.10441.0124.16247.7462.6198.728 12-202224.673.75.116.27333.1983.36947.7462.6198.728 12-202320.862.34.313.75428.0582.84747.7462.6198.728 12-202418.154.33.711.99124.4612.48247.7462.6198.728 12-202516.048.03.310.60921.6422.19647.7462.6198.728 12-202614.443.33.09.55619.4941.97847.7462.6198.728 12-202713.139.42.78.70917.7671.80347.7462.6198.728 12-202812.136.32.58.02216.3651.66147.7462.6198.728 12-202911.133.32.37.36015.0141.52347.7462.6198.728 12-203010.230.72.16.77113.8131.40247.7462.6198.728 12-20319.428.21.96.23012.7091.29047.7462.6198.728 12-20328.726.01.85.74711.7241.19047.7462.6198.728 12-20338.023.91.65.27210.7561.09147.7462.6198.728 12-20347.322.01.54.8519.8961.00447.7462.6198.728 12-20356.720.21.44.4639.105.92447.7462.6198.728 12-20366.218.61.34.1178.399.85247.7462.6198.728 S Tot427.21,281.788.4282.979577.27758.57747.7462.6198.728 After1.54.5.3.9922.025.20547.7462.6198.728 Total428.71,286.288.7283.971579.30158.78247.7462.6198.728 Cum.0.0.0 Ult428.71,286.288.7 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6 Mo-YearM$M$M$M$M$M$M$M$ 12-20183,368.280376.890127.4490.0000.0003,872.620193.44096.8154.397 12-20191,994.627223.18775.4730.0000.0002,293.287114.55157.3326.010 12-20201,280.968143.33348.4690.0000.0001,472.76973.56636.8197.622 12-2021959.888107.40636.3200.0000.0001,103.61455.12627.5909.129 12-2022776.98886.94029.4000.0000.000893.32844.62222.33310.544 12-2023656.69973.48124.8480.0000.000755.02837.71418.87611.905 12-2024572.51164.06121.6630.0000.000658.23432.87916.45613.197 12-2025506.52356.67719.1660.0000.000582.36529.09014.55914.510 12-2026456.26851.05417.2640.0000.000524.58626.20313.11515.765 12-2027415.82646.52815.7340.0000.000478.08823.88111.95216.995 12-2028383.02142.85814.4930.0000.000440.37121.99711.00918.184 12-2029351.39539.31913.2960.0000.000404.01120.18110.10019.540 12-2030323.30236.17612.2330.0000.000371.71118.5679.29320.967 12-2031297.45533.28311.2550.0000.000341.99417.0838.55022.518 12-2032274.39330.70310.3820.0000.000315.47915.7587.88724.149 12-2033251.73728.1689.5250.0000.000289.43014.4577.23626.041 12-2034231.61125.9168.7640.0000.000266.29113.3016.65728.033 12-2035213.09523.8448.0630.0000.000245.00212.2386.12530.198 12-2036196.57321.9957.4380.0000.000226.00711.2895.65032.474 S Tot13,511.1621,511.818511.2350.0000.00015,534.215775.946388.35511.125 After47.3875.3021.7930.0000.00054.4822.7211.36233.750 Total13,558.5481,517.121513.0280.0000.00015,588.697778.667389.71711.204 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash Flow EndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. % Mo-YearM$CountM$M$M$M$M$M$M$ 12-2018133.17110.90.0000.000324.2663,991.419-866.492-866.492-932.695 12-2019178.22110.90.0000.000192.024.0001,751.158884.666593.319 12-2020178.22110.90.0000.000123.320.0001,060.8431,945.5091,432.110 12-2021178.22110.90.0000.00092.409.000750.2672,695.7761,970.936 12-2022178.22110.90.0000.00074.801.000573.3503,269.1262,345.133 12-2023178.22110.90.0000.00063.221.000456.9963,726.1212,616.221 12-2024178.22110.90.0000.00055.116.000375.5624,101.6832,818.708 12-2025178.22110.90.0000.00048.763.000311.7324,413.4152,971.464 12-2026178.22110.90.0000.00043.925.000263.1214,676.5363,088.673 12-2027178.22110.90.0000.00040.032.000224.0024,900.5383,179.384 12-2028178.22110.90.0000.00036.874.000192.2705,092.8083,250.168 12-2029178.22110.90.0000.00033.829.000161.6795,254.4873,304.275 12-2030178.22110.90.0000.00031.125.000134.5055,388.9923,345.203 12-2031178.22110.90.0000.00028.636.000109.5035,498.4953,375.500 12-2032178.22110.90.0000.00026.416.00087.1965,585.6913,397.439 12-2033178.22110.90.0000.00024.235.00065.2815,650.9723,412.371 12-2034178.22110.90.0000.00022.297.00045.8145,696.7853,421.903 12-2035178.22110.90.0000.00020.515.00027.9035,724.6883,427.188 12-2036178.22110.90.0000.00018.924.00011.9225,736.6093,429.251 S Tot3,341.158 0.0000.0001,300.7283,991.4195,736.6095,736.6093,429.251 After44.830 0.0000.0004.562.0001.0075,737.6163,429.414 Total3,385.988 0.0000.0001,305.2903,991.4195,737.6165,737.6163,429.414 Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinal Units DeinDef InitialFinalUnits Final 5.004,368.771 Oil Rate22,812.485.bbls/mo 96.5%1.200.0% 15,465.15,999.$/w/mo Expense92.823792.8237 8.003,766.881 Gas Rate68,437.1,455.Mcf/mo 0.0%0.000.0% Revenue 10.003,429.414 GOR3,000.3,000.scf/bbl Oil66.236966.2369 12.003,132.557 NGL Rate3,996.102.bbls/mo Gas66.236966.2369 15.002,748.922 NGL Yield58.470.6bbl/MMcf 20.002,234.147 Gas Shrinkage41.631.9% Oil Severance4.64.6% Gas Severance7.57.5% NGL Severance7.57.5% Ad Valorem45.1% Start Date: 04/20189 Months in year ‘1819.005 Year Life (04/2037)THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.TEXAS REGISTERED ENGINEERING FIRM F-693.ASN 427DEFAULT 1/10/2018 10:34:19 OIL PDNPTable 4 Cawley, Gillespie & Associates, Inc.   Table 5Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Developed Non-Producing ReservesIMPETRO OPERATING LLC -- WOLFE UNIT #3H WORKOVER 3HCRITTENDON \(BRUSHY CANYON\) FIELD -- Winkler COUNTY, TEXAS (1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGL EndProductionProductionProductionProductionSalesProductionPricePricePrice Mo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL 12-201821.7.0.014.953.000.00047.746.000.000 12-201912.1.0.08.373.000.00047.746.000.000 12-20208.6.0.05.914.000.00047.746.000.000 12-20216.7.0.04.618.000.00047.746.000.000 12-20225.5.0.03.826.000.00047.746.000.000 12-20234.8.0.03.283.000.00047.746.000.000 12-20244.2.0.02.892.000.00047.746.000.000 12-20253.7.0.02.578.000.00047.746.000.000 12-20263.4.0.02.337.000.00047.746.000.000 12-20273.1.0.02.139.000.00047.746.000.000 04-2028.8.0.0.550.000.00047.746.000.000 12-2029 12-2030 12-2031 12-2032 12-2033 12-2034 12-2035 12-2036 S Tot74.6.0.051.463.000.00047.746.000.000 After.0.0.0.000.000.000.000.000.000 Total74.6.0.051.463.000.00047.746.000.000 Cum.0.0.0 Ult74.6.0.0 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6 Mo-YearM$M$M$M$M$M$M$M$ 12-2018713.942.000.0000.0000.000713.94232.96317.8499.743 12-2019399.801.000.0000.0000.000399.80118.4599.99514.137 12-2020282.365.000.0000.0000.000282.36513.0377.05918.100 12-2021220.495.000.0000.0000.000220.49510.1805.51221.885 12-2022182.678.000.0000.0000.000182.6788.4344.56725.462 12-2023156.728.000.0000.0000.000156.7287.2363.91828.914 12-2024138.077.000.0000.0000.000138.0776.3753.45232.198 12-2025123.113.000.0000.0000.000123.1135.6843.07835.551 12-2026111.561.000.0000.0000.000111.5615.1512.78938.755 12-2027102.139.000.0000.0000.000102.1394.7162.55341.905 04-202826.262.000.0000.0000.00026.2621.213.65743.479 12-2029 12-2030 12-2031 12-2032 12-2033 12-2034 12-2035 12-2036 S Tot2,457.161.000.0000.0000.0002,457.161113.44861.42920.469 After.000.000.0000.0000.000.000.000.000.000 Total2,457.161.000.0000.0000.0002,457.161113.44861.42920.469 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash Flow EndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. % Mo-YearM$CountM$M$M$M$M$M$M$ 12-201876.78310.80.0000.00068.909170.482346.958346.958326.419 12-201979.78610.80.0000.00038.588.000252.973599.931546.740 12-202079.78610.80.0000.00027.253.000155.230755.161669.505 12-202179.78610.80.0000.00021.282.000103.735858.896744.042 12-202279.78610.80.0000.00017.632.00072.260931.156791.235 12-202379.78610.80.0000.00015.127.00050.661981.817821.315 12-202479.78610.80.0000.00013.327.00035.1381,016.955840.286 12-202579.78610.80.0000.00011.883.00022.6831,039.638851.420 12-202679.78610.80.0000.00010.768.00013.0681,052.705857.257 12-202779.78610.80.0000.0009.858.0005.2261,057.931859.387 04-202821.38010.80.0000.0002.535.000.4781,058.409859.570 12-2029 12-2030 12-2031 12-2032 12-2033 12-2034 12-2035 12-2036 S Tot816.232 0.0000.000237.162170.4821,058.4091,058.409859.570 After.000 0.0000.0000.000.000.0001,058.409859.570 Total816.232 0.0000.000237.162170.4821,058.4091,058.409859.570 Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinal Units DeinDef InitialFinalUnits Final 5.00947.704 Oil Rate3,041.242.bbls/mo 80.0%1.200.0% 4,277.7,799.$/w/mo Expense85.240985.2409 8.00892.560 Gas Rate0.0.Mcf/mo 0.0%0.000.0% Revenue 10.00859.570 GOR0.0.scf/bbl Oil68.993468.9934 12.00829.190 NGL Rate0.0.bbls/mo Gas68.993468.9934 15.00787.889 NGL Yield0.00.0bbl/MMcf 20.00728.507 Gas Shrinkage0.00.0% Oil Severance4.64.6% Gas Severance0.00.0% NGL Severance0.00.0% Ad Valorem20.4% Start Date: 01/201812 Months in year ‘1810.270 Year Life (04/2028) THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.TEXAS REGISTERED ENGINEERING FIRM F-693.ASN 425DEFAULT 1/10/2018 10:34:19 OIL PDNPTable 5 Cawley, Gillespie & Associates, Inc.  Table I - PUDComposite Reserve Estimates and Economic ForecastsLilis Energy, Inc. InterestsDelaware Basin Properties in Texas and New MexicoProved Undeveloped ReservesAs of December 31, 2017 (1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGL EndProductionProductionProductionProductionSalesProductionPricePricePrice Mo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL 12-2018466.01,397.996.5256.035522.31252.99947.7462.6198.728 12-2019751.72,255.2155.6426.674870.41588.32247.7462.6198.728 12-20201,306.53,919.4270.4704.3691,436.913145.80447.7462.6198.728 12-20211,270.13,810.3262.9620.3831,265.581128.41947.7462.6198.728 12-2022780.62,341.9161.6391.330798.31381.00547.7462.6198.728 12-2023588.61,765.8121.8297.719607.34761.62847.7462.6198.728 12-2024481.01,443.199.6244.521498.82450.61647.7462.6198.728 12-2025408.01,224.184.5208.066424.45543.07047.7462.6198.728 12-2026356.81,070.473.9182.324371.94137.74147.7462.6198.728 12-2027318.0954.165.8162.772332.05433.69447.7462.6198.728 12-2028288.2864.759.7147.710301.32930.57647.7462.6198.728 12-2029262.4787.154.3134.561274.50427.85447.7462.6198.728 12-2030240.9722.749.9123.586252.11525.58247.7462.6198.728 12-2031221.6664.845.9113.693231.93423.53547.7462.6198.728 12-2032204.4613.342.3104.879213.95221.71047.7462.6198.728 12-2033187.5562.638.896.219196.28719.91747.7462.6198.728 12-2034172.6517.735.788.527180.59418.32547.7462.6198.728 12-2035158.8476.332.981.449166.15616.86047.7462.6198.728 12-2036146.4439.330.375.134153.27415.55347.7462.6198.728 S Tot8,610.225,830.61,782.34,459.9529,098.302923.21047.7462.6198.728 After367.41,102.376.1179.990367.17937.25847.7462.6198.728 Total8,977.726,933.01,858.44,639.9429,465.481960.46847.7462.6198.728 Cum.0.0.0 Ult8,977.726,933.01,858.4 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6 Mo-YearM$M$M$M$M$M$M$M$ 12-201812,224.7041,367.871462.5580.0000.00014,055.133804.254467.2073.938 12-201920,372.0642,279.513770.8370.0000.00023,422.4131,343.379782.1174.406 12-202033,630.9593,763.1041,272.5270.0000.00038,666.5892,085.9701,141.8364.767 12-202129,620.9283,314.4051,120.7950.0000.00034,056.1281,797.349960.4655.805 12-202218,684.5212,090.687706.9840.0000.00021,482.1921,145.464619.1317.475 12-202314,214.9651,590.570537.8650.0000.00016,343.400875.165475.2328.892 12-202411,674.9721,306.360441.7570.0000.00013,423.089720.464392.21710.185 12-20259,934.3711,111.597375.8960.0000.00011,421.865613.965334.77811.454 12-20268,705.283974.069329.3900.0000.00010,008.742538.564293.99212.656 12-20277,771.726869.610294.0660.0000.0008,935.402481.177262.88313.825 12-20287,052.606789.145266.8560.0000.0008,108.606436.908238.84714.936 12-20296,424.773718.894243.1000.0000.0007,386.767398.163217.75316.109 12-20305,900.754660.259223.2720.0000.0006,784.285365.734200.04517.280 12-20315,428.423607.408205.4000.0000.0006,241.231336.461184.03518.530 12-20325,007.554560.315189.4760.0000.0005,757.345310.375169.76719.842 12-20334,594.093514.052173.8310.0000.0005,281.975284.748155.75021.365 12-20344,226.806472.954159.9340.0000.0004,859.695261.983143.29822.968 12-20353,888.884435.143147.1470.0000.0004,471.174241.038131.84224.711 12-20363,587.376401.406135.7390.0000.0004,124.521222.351121.62026.542 S Tot212,945.76023,827.3618,057.4320.0000.000244,830.55413,263.5127,292.8169.786 After8,593.824961.598325.1730.0000.0009,880.594522.954280.35130.235 Total221,539.58424,788.9598,382.6040.0000.000254,711.14813,786.4657,573.16610.579 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash Flow EndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. % Mo-YearM$CountM$M$M$M$M$M$M$ 12-2018390.60953.50.0000.0001,096.16826,722.000-15,425.105-15,425.105-15,237.953 12-2019996.819107.40.0000.0001,775.03638,783.407-20,258.345-35,683.450-32,876.622 12-20201,969.4931912.80.0000.0002,981.47741,955.067-11,467.255-47,150.705-41,995.420 12-20212,599.5782013.60.0000.0002,710.771.00025,987.966-21,162.739-23,279.466 12-20222,617.4032013.60.0000.0001,695.738.00015,404.456-5,758.283-13,214.258 12-20232,617.4032013.60.0000.0001,286.185.00011,089.4155,331.132-6,632.271 12-20242,617.4032013.60.0000.0001,054.744.0008,638.26013,969.392-1,973.371 12-20252,617.4032013.60.0000.000896.657.0006,959.06020,928.4521,437.469 12-20262,617.4032013.60.0000.000785.229.0005,773.55426,702.0054,009.715 12-20272,617.4032013.60.0000.000700.704.0004,873.23531,575.2415,983.348 12-20282,617.4032013.60.0000.000635.650.0004,179.79835,755.0387,522.101 12-20292,617.4032013.60.0000.000578.919.0003,574.52839,329.5668,718.200 12-20302,617.4032013.60.0000.000531.644.0003,069.45942,399.0259,651.992 12-20312,617.4032013.60.0000.000489.084.0002,614.24845,013.27310,375.089 12-20322,617.4032013.60.0000.000451.165.0002,208.63547,221.90710,930.532 12-20332,617.4032013.60.0000.000413.913.0001,810.16149,032.06811,344.352 12-20342,617.4032013.60.0000.000380.822.0001,456.18850,488.25611,647.055 12-20352,617.4032013.60.0000.000350.376.0001,130.51551,618.77111,860.758 12-20362,617.4032013.60.0000.000323.211.000839.93652,458.70712,005.186 S Tot45,217.550 0.0000.00019,137.494107,460.47452,458.70752,458.70712,005.186 After7,249.817 0.0000.000774.734.0001,052.73953,511.44612,159.725 Total52,467.366 0.0000.00019,912.229107,460.47453,511.44653,511.44612,159.725 SEC Pricing YE2017 PercentCum. Disc. WTI CushingHenry Hub 5.0027,835.429 YearOil $/STBGas $/MMBTU 8.0017,577.982 201851.342.976 10.0012,159.725 ThereafterFlatFlat 12.007,615.337 Cap51.342.976 15.002,083.374 20.00-4,652.116 12 Months in first year 25.065 Year Life (01/2043) THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.TEXAS REGISTERED ENGINEERING FIRM F-693. 1/10/2018 10:34:19 SummaryCawley, Gillespie & Associates, Inc.   Table II – PUDLease Reserve SummaryLilis Energy, Inc. InterestsDelaware Basin Properties in Texas and New MexicoProved Undeveloped ReservesAs of December 31, 2017 OPERATORCurrentWellCntUltimateGrossNetOil RevenueProd TaxExpensesFuture NetCash FlowLEASE NAME InterestLifeRecoveryReservesReservesGas RevenueAdv. TaxInvestmentsCash FlowDisc.@ 10.0TableClassMajorWell No.Start DateASN% __________________MBBL / MMCF__________________M$ / M$M$ / M$M$ / M$M$M$PHANTOM (WOLFCAMP B) -- WINKLER COUNTY, TEXAS LILIS ENERGY, INC. BISON PUD-239.0000 NI1438.3438.3170.98,161.1468.72,726.51,793.3256.71PUDOil 04/2048652.0000 WI19.81,314.81,314.8348.7913.2234.64,160.0 BISON PUD-34.5000 NI1438.3438.319.7941.754.1314.6207.028.32PUDOil 10/204946.0000 WI19.81,314.81,314.840.2105.427.1480.0 GRIZZLY PUD-161.0414 NI1439.2439.2268.112,801.4735.24,435.22,247.712.43PUDOil 12/2049686.6526 WI19.11,317.71,317.7547.01,432.4368.06,932.2 GRIZZLY PUD-361.0414 NI1439.2439.2268.112,801.4735.24,434.92,248.012.34PUDOil 02/2148886.6526 WI19.11,317.71,317.7547.01,432.4368.06,932.2 HIPPO #2H75.1094 NI1438.4438.4329.315,721.1902.95,246.85,173.62,387.85PUDOil 04/18432100.0000 WI19.81,315.11,315.1671.71,759.1451.96,300.0 HIPPO PUD-168.9935 NI1443.4443.4305.914,606.1838.84,651.24,049.11,059.46PUDOil 12/1949185.4277 WI20.71,330.21,330.2624.11,634.3419.86,834.2 HIPPO PUD-275.1094 NI1438.4438.4329.315,721.1902.95,248.53,471.9517.77PUDOil 01/20492100.0000 WI19.81,315.11,315.1671.71,759.1451.98,000.0 HIPPO PUD-33.7500 NI1438.3438.316.4784.745.1262.1172.523.48PUDOil 11/204935.0000 WI19.81,314.81,314.833.587.822.6400.0 PHANTOM (WOLFCAMP A) -- WINKLER COUNTY, TEXASLILIS ENERGY, INC. KUDU 1 PUD-271.0940 NI1400.3400.3284.613,588.7780.44,463.83,014.0439.49PUDOil 03/2048487.1825 WI19.81,201.01,201.0580.61,520.5390.66,974.6 PHANTOM (WOLFCAMP B) -- WINKLER COUNTY, TEXASLILIS ENERGY, INC. LION 1 PUD-265.9402 NI1434.5434.5286.513,679.9785.64,718.12,433.238.010PUDOil 07/2049092.4753 WI19.11,303.51,303.5584.51,530.7393.27,398.0 LION 3 PUD-165.9402 NI1434.5434.5286.513,679.9785.64,718.22,433.137.311PUDOil 08/2049792.4753 WI19.11,303.51,303.5584.51,530.7393.27,398.0 MEERKAT #1H59.2500 NI1438.3438.3259.712,398.6712.14,141.73,672.91,486.112PUDOil 05/1843579.0000 WI19.71,314.81,314.8529.71,387.3356.45,372.0 MOOSE #1H37.5000 NI1673.6673.6252.612,061.5692.73,448.54,329.61,590.413PUDOil 08/1849850.0000 WI24.42,020.92,020.9515.31,349.6346.75,050.0 PHANTOM (WOLFCAMP B) -- LEA COUNTY, NEW MEXICOLILIS ENERGY, INC. PRIZE HOG 2H50.0000 NI1439.2439.2219.610,484.1868.03,297.62,285.6408.314PUDOil 07/1947962.5000 WI19.91,317.51,317.5447.91,173.1602.75,000.0 PRIZE HOG 3H50.0000 NI1439.2439.2219.610,484.1868.03,297.52,285.7402.815PUDOil 09/1948062.5000 WI19.91,317.51,317.5447.91,173.1602.75,000.0 PHANTOM (WOLFCAMP B) -- WINKLER COUNTY, TEXASLILIS ENERGY, INC. TIGER #2H71.0940 NI1444.0444.0315.715,072.5865.64,770.24,285.71,246.916PUDOil 04/1948587.1825 WI20.91,332.11,332.1644.01,686.5433.26,974.6 TIGER 1 PUD-271.0940 NI1444.0444.0315.715,072.6865.64,770.14,285.81,230.717PUDOil 05/1948987.1825 WI20.91,332.11,332.1644.01,686.5433.26,974.6 TIGER PUD-312.0000 NI1438.3438.352.62,511.1144.2838.9551.878.118PUDOil 06/2049516.0000 WI19.71,314.81,314.8107.3281.072.21,280.0 PHANTOM (WOLFCAMP B) -- LEA COUNTY, NEW MEXICOLILIS ENERGY, INC. WILD HOG 2H50.0000 NI1439.2439.2219.610,484.1868.03,297.72,285.5455.019PUDOil 05/1848162.5000 WI20.01,317.51,317.5447.91,173.1602.75,000.0 THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. TEXAS REGISTERED ENGINEERING FIRM F-693.Scenario: 6.4281/10/2018 10:34:19 AM Cawley, Gillespie & Associates, Inc.Page 1  Table II - PUD (cont.)Lease Reserve SummaryLilis Energy, Inc. InterestsDelaware Basin Properties in Texas and New MexicoProved Undeveloped ReservesAs of December 31, 2017 OPERATORCurrentWellCntUltimateGrossNetOil RevenueProd TaxExpensesFuture NetCash FlowLEASE NAME InterestLifeRecoveryReservesReservesGas RevenueAdv. TaxInvestmentsCash FlowDisc.@ 10.0TableClassMajorWell No.Start DateASN% _________________MBBL / MMCF_________________M$ / M$M$ / M$M$ / M$M$M$PHANTOM (WOLFCAMP B) -- LEA COUNTY, NEW MEXICO LILIS ENERGY, INC. WILD HOG 3H50.0000 NI1439.2439.2219.610,484.1868.03,297.62,285.6448.720PUDOil 07/1848362.5000 WI20.01,317.51,317.5447.91,173.1602.75,000.0 GRAND TOTAL 208,977.78,977.74,639.9221,539.613,786.572,379.653,511.412,159.7 26,933.026,933.09,465.524,789.07,573.2107,460.5 THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. TEXAS REGISTERED ENGINEERING FIRM F-693.Scenario: 6.4281/10/2018 10:34:19 AM Cawley, Gillespie & Associates, Inc.Page 2  Rate-Time History-Forecast CurvesAndTabular Reserves and EconomicsBy Property Cawley, Gillespie & Associates, Inc.Petroleum Consultants   Table 1Reserve Estimates and Economic Forecasts as of December 31, 2017 Lilis Energy, Inc. InterestsProved Undeveloped Reserves LILIS ENERGY, INC. -- BISON PUD-2PHANTOM (WOLFCAMP B) FIELD -- WINKLER COUNTY, TEXAS(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGL EndProductionProductionProductionProductionSalesProductionPricePricePrice Mo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL 12-2018.0.0.0.000.000.000.000.000.000 12-2019.0.0.0.000.000.000.000.000.000 12-2020102.6307.821.240.01181.6228.28247.7462.6198.728 12-202165.8197.513.625.68052.3875.31647.7462.6198.728 12-202241.7125.08.616.24733.1443.36347.7462.6198.728 12-202331.293.56.412.15224.7892.51547.7462.6198.728 12-202425.275.65.29.83320.0602.03547.7462.6198.728 12-202521.263.64.48.27216.8751.71247.7462.6198.728 12-202618.455.33.87.18514.6571.48747.7462.6198.728 12-202716.349.03.46.37012.9941.31947.7462.6198.728 12-202814.744.23.15.74911.7281.19047.7462.6198.728 12-202913.440.22.85.22210.6521.08147.7462.6198.728 12-203012.336.92.54.7969.784.99347.7462.6198.728 12-203111.333.92.34.4139.002.91347.7462.6198.728 12-203210.431.32.24.0718.304.84347.7462.6198.728 12-20339.628.72.03.7347.618.77347.7462.6198.728 12-20348.826.41.83.4367.009.71147.7462.6198.728 12-20358.124.31.73.1616.449.65447.7462.6198.728 12-20367.522.41.52.9165.949.60447.7462.6198.728 S Tot418.61,255.786.6163.247333.02433.79247.7462.6198.728 After19.759.14.17.68015.6661.59047.7462.6198.728 Total438.31,314.890.7170.927348.69135.38247.7462.6198.728 Cum.0.0.0 Ult438.31,314.890.7 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6 Mo-YearM$M$M$M$M$M$M$M$ 12-2018.000.000.0000.0000.000.000.000.000.000 12-2019.000.000.0000.0000.000.000.000.000.000 12-20201,910.360213.75872.2840.0000.0002,196.402109.71254.9104.141 12-20211,226.107137.19446.3930.0000.0001,409.69470.41535.2425.603 12-2022775.74786.80129.3530.0000.000891.90144.55122.2987.133 12-2023580.18964.92021.9530.0000.000667.06233.32016.6778.538 12-2024469.49852.53417.7650.0000.000539.79726.96313.4959.852 12-2025394.96544.19414.9450.0000.000454.10422.68311.35311.151 12-2026343.05738.38612.9810.0000.000394.42319.7029.86112.389 12-2027304.13634.03111.5080.0000.000349.67517.4678.74213.595 12-2028274.49230.71410.3860.0000.000315.59215.7647.89014.743 12-2029249.31927.8979.4340.0000.000286.65014.3187.16615.933 12-2030228.99625.6238.6650.0000.000263.28513.1516.58217.083 12-2031210.68923.5757.9720.0000.000242.23512.1006.05618.310 12-2032194.35421.7477.3540.0000.000223.45511.1625.58619.600 12-2033178.30719.9516.7470.0000.000205.00510.2405.12521.097 12-2034164.05118.3566.2070.0000.000188.6159.4214.71522.672 12-2035150.93616.8895.7110.0000.000173.5368.6684.33824.384 12-2036139.23415.5795.2680.0000.000160.0817.9964.00226.185 S Tot7,794.436872.151294.9260.0000.0008,961.513447.634224.0389.890 After366.67241.02813.8740.0000.000421.57521.05810.53930.537 Total8,161.109913.179308.8000.0000.0009,383.088468.692234.57710.818 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash Flow EndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. % Mo-YearM$CountM$M$M$M$M$M$M$ 12-2018.00000.00.0000.0000.000.000.000.000.000 12-2019.00000.00.0000.0000.000.000.000.000.000 12-202069.33310.50.0000.000174.9804,160.000-2,372.533-2,372.533-1,996.105 12-202199.84010.50.0000.000112.306.0001,091.891-1,280.643-1,209.737 12-202299.84010.50.0000.00071.055.000654.158-626.485-782.272 12-202399.84010.50.0000.00053.143.000464.082-162.403-506.787 12-202499.84010.50.0000.00043.004.000356.495194.093-314.498 12-202599.84010.50.0000.00036.177.000284.051478.144-175.265 12-202699.84010.50.0000.00031.422.000233.599711.743-71.185 12-202799.84010.50.0000.00027.857.000195.769907.5128.105 12-202899.84010.50.0000.00025.142.000166.9561,074.46869.571 12-202999.84010.50.0000.00022.836.000142.4891,216.957117.250 12-203099.84010.50.0000.00020.975.000122.7361,339.693154.588 12-203199.84010.50.0000.00019.298.000104.9421,444.634183.614 12-203299.84010.50.0000.00017.802.00089.0651,533.699206.012 12-203399.84010.50.0000.00016.332.00073.4671,607.167222.807 12-203499.84010.50.0000.00015.026.00059.6121,666.778235.198 12-203599.84010.50.0000.00013.825.00046.8641,713.643244.056 12-203699.84010.50.0000.00012.753.00035.4901,749.133250.157 S Tot1,666.773 0.0000.000713.9354,160.0001,749.1331,749.133250.157 After312.214 0.0000.00033.586.00044.1781,793.311256.716 Total1,978.987 0.0000.000747.5204,160.0001,793.3111,793.311256.716 Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeinDef InitialFinalUnits Final 5.00825.261 Oil Rate22,812.459.bbls/mo 96.3%1.200.0% 5,332.16,000.$/w/mo Expense52.000052.0000 8.00450.311 Gas Rate68,437.1,378.Mcf/mo 0.0%0.000.0% Revenue 10.00256.716 GOR3,000.3,000.scf/bbl Oil39.000039.0000 12.0097.605 NGL Rate1,485.97.bbls/mo Gas39.000039.0000 15.00-90.710 NGL Yield21.770.8bbl/MMcf 20.00-308.244 Gas Shrinkage78.331.7% Oil Severance4.64.6% Gas Severance7.57.5% NGL Severance7.57.5% Ad Valorem25.2% Start Date: 04/20209 Months in year ‘2019.877 Year Life (02/2040)THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.TEXAS REGISTERED ENGINEERING FIRM F-693.ASN 486DEFAULT 1/10/2018 10:34:19 OIL PUDTable 1Cawley, Gillespie & Associates, Inc.   Table 2Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Undeveloped ReservesLILIS ENERGY, INC. -- BISON PUD-3PHANTOM (WOLFCAMP B) FIELD -- WINKLER COUNTY, TEXAS(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGL EndProductionProductionProductionProductionSalesProductionPricePricePrice Mo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL 12-2018.0.0.0.000.000.000.000.000.000 12-2019.0.0.0.000.000.000.000.000.000 12-202048.6145.710.12.1864.459.45247.7462.6198.728 12-202194.3282.819.54.2428.654.87847.7462.6198.728 12-202249.8149.510.32.2424.574.46447.7462.6198.728 12-202335.2105.57.31.5833.228.32847.7462.6198.728 12-202427.682.95.71.2442.537.25747.7462.6198.728 12-202522.868.54.71.0282.096.21347.7462.6198.728 12-202619.658.84.1.8821.799.18347.7462.6198.728 12-202717.251.73.6.7751.581.16047.7462.6198.728 12-202815.446.33.2.6951.418.14447.7462.6198.728 12-202914.041.92.9.6281.281.13047.7462.6198.728 12-203012.838.32.6.5751.173.11947.7462.6198.728 12-203111.835.32.4.5291.079.11047.7462.6198.728 12-203210.832.52.2.488.996.10147.7462.6198.728 12-20339.929.82.1.448.913.09347.7462.6198.728 12-20349.227.51.9.412.840.08547.7462.6198.728 12-20358.425.31.7.379.773.07847.7462.6198.728 12-20367.823.31.6.350.713.07247.7462.6198.728 S Tot415.21,245.786.018.68538.1183.86847.7462.6198.728 After23.069.14.81.0372.116.21547.7462.6198.728 Total438.31,314.890.719.72240.2344.08347.7462.6198.728 Cum.0.0.0 Ult438.31,314.890.7 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6 Mo-YearM$M$M$M$M$M$M$M$ 12-2018.000.000.0000.0000.000.000.000.000.000 12-2019.000.000.0000.0000.000.000.000.000.000 12-2020104.37011.6783.9490.0000.000119.9975.9943.0003.811 12-2021202.55722.6657.6640.0000.000232.88611.6335.8224.807 12-2022107.05511.9794.0510.0000.000123.0846.1483.0776.450 12-202375.5618.4552.8590.0000.00086.8754.3392.1727.903 12-202459.3766.6442.2470.0000.00068.2673.4101.7079.248 12-202549.0675.4901.8570.0000.00056.4142.8181.41010.568 12-202642.1114.7121.5930.0000.00048.4162.4181.21011.824 12-202737.0134.1411.4000.0000.00042.5552.1261.06413.044 12-202833.1883.7141.2560.0000.00038.1571.906.95414.205 12-202929.9913.3561.1350.0000.00034.4821.722.86215.404 12-203027.4613.0731.0390.0000.00031.5731.577.78916.550 12-203125.2612.827.9560.0000.00029.0431.451.72617.733 12-203223.3022.607.8820.0000.00026.7911.338.67018.974 12-203321.3782.392.8090.0000.00024.5791.228.61420.414 12-203419.6692.201.7440.0000.00022.6141.130.56521.931 12-203518.0972.025.6850.0000.00020.8061.039.52023.579 12-203616.6941.868.6320.0000.00019.193.959.48025.311 S Tot892.15099.82633.7570.0000.0001,025.73451.23625.6439.755 After49.5165.5411.8740.0000.00056.9302.8441.42329.953 Total941.666105.36735.6310.0000.0001,082.66454.08027.06710.817 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash Flow EndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. % Mo-YearM$CountM$M$M$M$M$M$M$ 12-2018.00000.00.0000.0000.000.000.000.000.000 12-2019.00000.00.0000.0000.000.000.000.000.000 12-20202.72510.10.0000.0009.560480.000-381.282-381.282-299.629 12-202111.52010.10.0000.00018.553.000185.358-195.924-165.804 12-202211.52010.10.0000.0009.806.00092.533-103.391-105.298 12-202311.52010.10.0000.0006.921.00061.923-41.468-68.529 12-202411.52010.10.0000.0005.439.00046.1924.724-43.609 12-202511.52010.10.0000.0004.494.00036.17240.896-25.877 12-202611.52010.10.0000.0003.857.00029.41070.306-12.772 12-202711.52010.10.0000.0003.390.00024.45594.761-2.867 12-202811.52010.10.0000.0003.040.00020.737115.4984.768 12-202911.52010.10.0000.0002.747.00017.630133.12910.668 12-203011.52010.10.0000.0002.515.00015.171148.30015.283 12-203111.52010.10.0000.0002.314.00013.032161.33218.887 12-203211.52010.10.0000.0002.134.00011.129172.46121.686 12-203311.52010.10.0000.0001.958.0009.259181.72023.802 12-203411.52010.10.0000.0001.802.0007.598189.31725.382 12-203511.52010.10.0000.0001.658.0006.069195.38726.529 12-203611.52010.10.0000.0001.529.0004.706200.09227.337 S Tot187.045 0.0000.00081.717480.000200.092200.09227.337 After41.269 0.0000.0004.535.0006.859206.95128.341 Total228.314 0.0000.00086.252480.000206.951206.95128.341 Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeinDef InitialFinalUnits Final 5.0093.108 Oil Rate22,812.459.bbls/mo 96.3%1.200.0% 13,416.16,000.$/w/mo Expense6.00006.0000 8.0050.145 Gas Rate68,437.1,378.Mcf/mo 0.0%0.000.0% Revenue 10.0028.341 GOR3,000.3,000.scf/bbl Oil4.50004.5000 12.0010.680 NGL Rate3,628.97.bbls/mo Gas4.50004.5000 15.00-9.825 NGL Yield53.070.6bbl/MMcf 20.00-32.715 Gas Shrinkage48.732.3% Oil Severance4.64.6% Gas Severance7.57.5% NGL Severance7.57.5% Ad Valorem2.9 % Start Date: 10/20203 Months in year ‘2019.837 Year Life (08/2040)THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.TEXAS REGISTERED ENGINEERING FIRM F-693.ASN 494DEFAULT 1/10/2018 10:34:19 OIL PUDTable 2Cawley, Gillespie & Associates, Inc.   Table 3Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Undeveloped ReservesLILIS ENERGY, INC. -- GRIZZLY PUD-1PHANTOM (WOLFCAMP B) FIELD -- WINKLER COUNTY, TEXAS(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGL EndProductionProductionProductionProductionSalesProductionPricePricePrice Mo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL 12-2018.0.0.0.000.000.000.000.000.000 12-2019.0.0.0.000.000.000.000.000.000 12-20202.26.7.51.3552.763.28047.7462.6198.728 12-2021126.1378.426.177.002157.08515.93947.7462.6198.728 12-202256.1168.311.634.24069.8497.08847.7462.6198.728 12-202338.1114.37.923.25847.4464.81447.7462.6198.728 12-202429.488.36.117.95736.6313.71747.7462.6198.728 12-202524.172.25.014.68829.9643.04047.7462.6198.728 12-202620.561.54.212.52225.5452.59247.7462.6198.728 12-202717.953.83.710.95422.3462.26747.7462.6198.728 12-202816.048.13.39.78819.9672.02647.7462.6198.728 12-202914.543.43.08.82117.9951.82647.7462.6198.728 12-203013.239.62.78.06016.4431.66947.7462.6198.728 12-203112.136.42.57.41215.1201.53447.7462.6198.728 12-203211.233.62.36.83713.9481.41547.7462.6198.728 12-203310.330.82.16.27312.7961.29847.7462.6198.728 12-20349.528.42.05.77111.7731.19547.7462.6198.728 12-20358.726.11.85.31010.8321.09947.7462.6198.728 12-20368.024.11.74.8989.9921.01447.7462.6198.728 S Tot418.01,254.086.5255.145520.49652.81547.7462.6198.728 After21.263.74.412.96826.4552.68447.7462.6198.728 Total439.21,317.790.9268.113546.95155.49947.7462.6198.728 Cum.0.0.0 Ult439.21,317.790.9 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6 Mo-YearM$M$M$M$M$M$M$M$ 12-2018.000.000.0000.0000.000.000.000.000.000 12-2019.000.000.0000.0000.000.000.000.000.000 12-202064.6757.2372.4470.0000.00074.3593.7141.8593.829 12-20213,676.569411.386139.1140.0000.0004,227.069211.145105.6774.623 12-20221,634.816182.92661.8580.0000.0001,879.60193.88746.9906.453 12-20231,110.485124.25742.0180.0000.0001,276.76063.77531.9198.009 12-2024857.35895.93332.4410.0000.000985.73149.23824.6439.441 12-2025701.29778.47126.5360.0000.000806.30440.27520.15810.839 12-2026597.87066.89822.6220.0000.000687.39034.33617.18512.168 12-2027523.01758.52219.7900.0000.000601.32930.03715.03313.458 12-2028467.32852.29117.6830.0000.000537.30226.83913.43314.685 12-2029421.17047.12615.9360.0000.000484.23224.18812.10615.949 12-2030384.85843.06314.5620.0000.000442.48322.10211.06217.156 12-2031353.88539.59813.3900.0000.000406.87320.32410.17218.381 12-2032326.44836.52812.3520.0000.000375.32818.7489.38319.660 12-2033299.49433.51211.3320.0000.000344.33817.2008.60821.145 12-2034275.55030.83210.4260.0000.000316.80915.8257.92022.708 12-2035253.52128.3679.5930.0000.000291.48114.5607.28724.407 12-2036233.86526.1688.8490.0000.000268.88213.4316.72226.193 S Tot12,182.2061,363.116460.9500.0000.00014,006.271699.624350.15710.237 After619.18669.28323.4290.0000.000711.89835.56017.79730.532 Total12,801.3911,432.399484.3780.0000.00014,718.169735.184367.95411.218 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash Flow EndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. % Mo-YearM$CountM$M$M$M$M$M$M$ 12-2018.00000.00.0000.0000.000.000.000.000.000 12-2019.00000.00.0000.0000.000.000.000.000.000 12-20201.34210.90.0000.0006.3076,932.210-6,871.074-6,871.074-5,248.314 12-2021166.37310.90.0000.000358.538.0003,385.336-3,485.738-2,797.464 12-2022166.37310.90.0000.000159.427.0001,412.923-2,072.815-1,873.130 12-2023166.37310.90.0000.000108.294.000906.399-1,166.416-1,334.803 12-2024166.37310.90.0000.00083.609.000661.868-504.548-977.693 12-2025166.37310.90.0000.00068.390.000511.1086.560-727.112 12-2026166.37310.90.0000.00058.304.000411.193417.752-543.876 12-2027166.37310.90.0000.00051.004.000338.881756.634-406.607 12-2028166.37310.90.0000.00045.574.000285.0841,041.718-301.641 12-2029166.37310.90.0000.00041.072.000240.4931,282.211-221.161 12-2030166.37310.90.0000.00037.531.000205.4141,487.626-158.669 12-2031166.37310.90.0000.00034.511.000175.4941,663.119-110.129 12-2032166.37310.90.0000.00031.835.000148.9891,812.108-72.662 12-2033166.37310.90.0000.00029.207.000122.9501,935.058-44.555 12-2034166.37310.90.0000.00026.872.00099.8192,034.877-23.807 12-2035166.37310.90.0000.00024.723.00078.5382,113.415-8.962 12-2036166.37310.90.0000.00022.806.00059.5502,172.9651.276 S Tot2,663.311 0.0000.0001,188.0056,932.2102,172.9652,172.9651.276 After523.460 0.0000.00060.383.00074.6982,247.66212.360 Total3,186.771 0.0000.0001,248.3886,932.2102,247.6622,247.66212.360 Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeinDef InitialFinalUnits Final 5.00809.355 Oil Rate22,812.492.bbls/mo 96.1%1.200.0% 1,547.15,999.$/w/mo Expense86.652686.6526 8.00277.684 Gas Rate68,437.1,476.Mcf/mo 0.0%0.000.0% Revenue 10.0012.360 GOR3,000.3,000.scf/bbl Oil61.041461.0414 12.00-199.211 NGL Rate459.104.bbls/mo Gas61.041461.0414 15.00-439.270 NGL Yield6.770.9bbl/MMcf 20.00-695.012 Gas Shrinkage93.531.5% Oil Severance4.64.6% Gas Severance7.57.5% NGL Severance7.57.5% Ad Valorem42.4 % Start Date: 12/20201 Months in year ‘2019.229 Year Life (02/2040)THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.TEXAS REGISTERED ENGINEERING FIRM F-693.ASN 496DEFAULT 1/10/2018 10:34:19 OIL PUDTable 3Cawley, Gillespie & Associates, Inc.   Table 4Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Undeveloped ReservesLILIS ENERGY, INC. -- GRIZZLY PUD-3PHANTOM (WOLFCAMP B) FIELD -- WINKLER COUNTY, TEXAS(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGL EndProductionProductionProductionProductionSalesProductionPricePricePrice Mo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL 12-2018.0.0.0.000.000.000.000.000.000 12-2019.0.0.0.000.000.000.000.000.000 12-2020.0.0.0.000.000.000.000.000.000 12-2021119.7359.124.873.061149.04515.12447.7462.6198.728 12-202259.5178.612.336.33374.1207.52147.7462.6198.728 12-202339.5118.58.224.11549.1944.99247.7462.6198.728 12-202430.290.66.318.43237.6023.81547.7462.6198.728 12-202524.673.75.114.99230.5843.10347.7462.6198.728 12-202620.962.64.312.73525.9792.63647.7462.6198.728 12-202718.254.63.811.11222.6692.30047.7462.6198.728 12-202816.248.73.49.91120.2182.05147.7462.6198.728 12-202914.643.83.08.91918.1941.84647.7462.6198.728 12-203013.340.02.88.14116.6071.68547.7462.6198.728 12-203112.336.82.57.48315.2661.54947.7462.6198.728 12-203211.333.92.36.90314.0821.42947.7462.6198.728 12-203310.431.12.16.33312.9191.31147.7462.6198.728 12-20349.528.62.05.82711.8871.20647.7462.6198.728 12-20358.826.31.85.36110.9361.11047.7462.6198.728 12-20368.124.31.74.94510.0881.02447.7462.6198.728 S Tot417.11,251.386.3254.604519.39152.70347.7462.6198.728 After22.166.44.613.51027.5602.79747.7462.6198.728 Total439.21,317.790.9268.113546.95155.49947.7462.6198.728 Cum.0.0.0 Ult439.21,317.790.9 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6 Mo-YearM$M$M$M$M$M$M$M$ 12-2018.000.000.0000.0000.000.000.000.000.000 12-2019.000.000.0000.0000.000.000.000.000.000 12-2020.000.000.0000.0000.000.000.000.000.000 12-20213,488.395390.331131.9940.0000.0004,010.719200.338100.2684.537 12-20221,734.778194.11165.6400.0000.0001,994.53099.62849.8636.263 12-20231,151.397128.83443.5670.0000.0001,323.79866.12533.0957.837 12-2024880.07198.47533.3000.0000.0001,011.84650.54225.2969.279 12-2025715.82280.09627.0850.0000.000823.00341.11020.57510.684 12-2026608.04368.03623.0070.0000.000699.08634.92017.47712.018 12-2027530.57059.36820.0760.0000.000610.01330.47115.25013.311 12-2028473.19152.94717.9050.0000.000544.04327.17513.60114.543 12-2029425.84047.64916.1130.0000.000489.60224.45612.24015.808 12-2030388.69043.49214.7070.0000.000446.89022.32211.17217.018 12-2031357.29439.97913.5190.0000.000410.79320.51910.27018.235 12-2032329.59336.88012.4710.0000.000378.94418.9299.47419.503 12-2033302.37933.83411.4410.0000.000347.65517.3668.69120.974 12-2034278.20531.12910.5270.0000.000319.86115.9777.99722.522 12-2035255.96328.6419.6850.0000.000294.28914.7007.35724.204 12-2036236.11826.4208.9340.0000.000271.47313.5606.78725.973 S Tot12,156.3501,360.223459.9710.0000.00013,976.545698.139349.41410.201 After645.04172.17624.4070.0000.000741.62437.04518.54130.382 Total12,801.3911,432.399484.3780.0000.00014,718.169735.184367.95411.218 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash Flow EndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. % Mo-YearM$CountM$M$M$M$M$M$M$ 12-2018.00000.00.0000.0000.000.000.000.000.000 12-2019.00000.00.0000.0000.000.000.000.000.000 12-2020.00000.00.0000.0000.0006,932.210-6,932.210-6,932.210-5,236.550 12-2021148.54710.90.0000.000340.187.0003,221.378-3,710.832-2,919.833 12-2022166.37310.90.0000.000169.175.0001,509.490-2,201.342-1,932.046 12-2023166.37310.90.0000.000112.284.000945.921-1,255.421-1,370.186 12-2024166.37310.90.0000.00085.824.000683.810-571.610-1,001.215 12-2025166.37310.90.0000.00069.807.000525.139-46.471-743.746 12-2026166.37310.90.0000.00059.296.000421.020374.548-556.127 12-2027166.37310.90.0000.00051.741.000346.178720.727-415.899 12-2028166.37310.90.0000.00046.145.000290.7481,011.474-308.847 12-2029166.37310.90.0000.00041.528.000245.0051,256.479-226.856 12-2030166.37310.90.0000.00037.905.000209.1171,465.596-163.238 12-2031166.37310.90.0000.00034.843.000178.7871,644.383-113.787 12-2032166.37310.90.0000.00032.142.000152.0271,796.410-75.556 12-2033166.37310.90.0000.00029.488.000125.7371,922.148-46.813 12-2034166.37310.90.0000.00027.130.000102.3842,024.531-25.532 12-2035166.37310.90.0000.00024.961.00080.8972,105.429-10.242 12-2036166.37310.90.0000.00023.026.00061.7262,167.155.370 S Tot2,644.143 0.0000.0001,185.4846,932.2102,167.1552,167.155.370 After542.335 0.0000.00062.904.00080.8002,247.95512.314 Total3,186.478 0.0000.0001,248.3886,932.2102,247.9552,247.95512.314 Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeinDef InitialFinalUnits Final 5.00804.964 Oil Rate22,812.492.bbls/mo 96.1%1.200.0% 11,428.15,999.$/w/mo Expense86.652686.6526 8.00275.339 Gas Rate68,437.1,476.Mcf/mo 0.0%0.000.0% Revenue 10.0012.314 GOR3,000.3,000.scf/bbl Oil61.041461.0414 12.00-196.551 NGL Rate2,858.104.bbls/mo Gas61.041461.0414 15.00-432.193 NGL Yield41.870.6bbl/MMcf 20.00-680.523 Gas Shrinkage55.331.8% Oil Severance4.64.6% Gas Severance7.57.5% NGL Severance7.57.5% Ad Valorem42.2 % Start Date: 02/202111 Months in year ‘2119.178 Year Life (04/2040)THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. TEXAS REGISTERED ENGINEERINGFIRM F-693.ASN 488DEFAULT 1/10/2018 10:34:19 OIL PUDTable 4Cawley, Gillespie & Associates, Inc.   Table 5Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Undeveloped ReservesLILIS ENERGY, INC. -- HIPPO #2HPHANTOM (WOLFCAMP B) FIELD -- WINKLER COUNTY, TEXAS(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGL EndProductionProductionProductionProductionSalesProductionPricePricePrice Mo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL 12-2018102.3307.021.276.869156.81315.91247.7462.6198.728 12-201966.0197.913.749.540101.06210.25547.7462.6198.728 12-202041.8125.48.731.39364.0426.49847.7462.6198.728 12-202131.293.56.423.40247.7414.84447.7462.6198.728 12-202225.275.55.218.89038.5363.91047.7462.6198.728 12-202321.263.74.415.93832.5133.29947.7462.6198.728 12-202418.555.43.813.87828.3112.87347.7462.6198.728 12-202516.349.03.412.26825.0262.53947.7462.6198.728 12-202614.744.13.011.04322.5282.28647.7462.6198.728 12-202713.440.22.810.05920.5202.08247.7462.6198.728 12-202812.337.02.69.26318.8971.91747.7462.6198.728 12-202911.333.92.38.49817.3371.75947.7462.6198.728 12-203010.431.22.27.81915.9511.61947.7462.6198.728 12-20319.628.72.07.19414.6751.48947.7462.6198.728 12-20328.826.51.86.63613.5381.37447.7462.6198.728 12-20338.124.31.76.08812.4201.26047.7462.6198.728 12-20347.522.41.55.60111.4271.15947.7462.6198.728 12-20356.920.61.45.15410.5131.06747.7462.6198.728 12-20366.319.01.34.7549.698.98447.7462.6198.728 S Tot431.81,295.389.4324.288661.54767.12847.7462.6198.728 After6.619.91.44.97610.1521.03047.7462.6198.728 Total438.41,315.190.7329.264671.69968.15847.7462.6198.728 Cum.0.0.0 Ult438.41,315.190.7 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6 Mo-YearM$M$M$M$M$M$M$M$ 12-20183,670.208410.674138.8730.0000.0004,219.755210.780105.4944.133 12-20192,365.358264.66989.5000.0000.0002,719.528135.84267.9885.590 12-20201,498.897167.71856.7150.0000.0001,723.33086.08243.0837.109 12-20211,117.376125.02842.2790.0000.0001,284.68264.17132.1178.525 12-2022901.945100.92234.1280.0000.0001,036.99551.79925.9259.854 12-2023760.97685.14928.7940.0000.000874.91843.70321.87311.131 12-2024662.62074.14325.0720.0000.000761.83638.05419.04612.344 12-2025585.73065.54022.1630.0000.000673.43333.63816.83613.576 12-2026527.26358.99819.9510.0000.000606.21230.28115.15514.753 12-2027480.27553.74018.1730.0000.000552.18827.58213.80515.906 12-2028442.28049.48816.7350.0000.000508.50325.40012.71317.018 12-2029405.76145.40215.3530.0000.000466.51723.30311.66318.283 12-2030373.32241.77214.1260.0000.000429.22021.44010.73119.615 12-2031343.47638.43312.9960.0000.000394.90519.7269.87321.062 12-2032316.84635.45311.9890.0000.000364.28818.1969.10722.583 12-2033290.68532.52610.9990.0000.000334.20916.6948.35524.349 12-2034267.44529.92610.1200.0000.000307.49015.3597.68726.207 12-2035246.06427.5339.3110.0000.000282.90714.1317.07328.227 12-2036226.98625.3988.5890.0000.000260.97313.0366.52430.351 S Tot15,483.5121,732.513585.8640.0000.00017,801.889889.218445.04710.467 After237.60626.5878.9910.0000.000273.18313.6466.83032.955 Total15,721.1181,759.099594.8550.0000.00018,075.073902.863451.87710.807 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash Flow EndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. % Mo-YearM$CountM$M$M$M$M$M$M$ 12-2018132.80011.00.0000.000335.6856,300.000-2,865.003-2,865.003-2,872.118 12-2019192.00011.00.0000.000216.340.0002,107.357-757.647-1,035.449 12-2020192.00011.00.0000.000137.092.0001,265.073507.426-35.153 12-2021192.00011.00.0000.000102.197.000894.1971,401.623607.037 12-2022192.00011.00.0000.00082.494.000684.7782,086.4011,053.951 12-2023192.00011.00.0000.00069.600.000547.7422,634.1431,378.862 12-2024192.00011.00.0000.00060.605.000452.1313,086.2741,622.623 12-2025192.00011.00.0000.00053.572.000377.3863,463.6611,807.545 12-2026192.00011.00.0000.00048.225.000320.5513,784.2121,950.332 12-2027192.00011.00.0000.00043.927.000274.8744,059.0862,061.639 12-2028192.00011.00.0000.00040.452.000237.9394,297.0242,149.230 12-2029192.00011.00.0000.00037.112.000202.4394,499.4642,216.973 12-2030192.00011.00.0000.00034.145.000170.9054,670.3682,268.972 12-2031192.00011.00.0000.00031.415.000141.8924,812.2602,308.225 12-2032192.00011.00.0000.00028.979.000116.0054,928.2652,337.406 12-2033192.00011.00.0000.00026.587.00090.5745,018.8392,358.119 12-2034192.00011.00.0000.00024.461.00067.9835,086.8212,372.257 12-2035192.00011.00.0000.00022.505.00047.1985,134.0192,381.186 12-2036192.00011.00.0000.00020.761.00028.6525,162.6712,386.122 S Tot3,588.800 0.0000.0001,416.1536,300.0005,162.6715,162.6712,386.122 After220.090 0.0000.00021.732.00010.8865,173.5572,387.831 Total3,808.890 0.0000.0001,437.8856,300.0005,173.5575,173.5572,387.831 Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeinDef InitialFinalUnits Final 5.003,507.651 Oil Rate22,812.458.bbls/mo 96.3%1.200.0% 4,799.16,000.$/w/mo Expense100.0000100.0000 8.002,787.667 Gas Rate68,437.1,376.Mcf/mo 0.0%0.000.0% Revenue 10.002,387.831 GOR3,000.3,000.scf/bbl Oil75.109475.1094 12.002,038.602 NGL Rate1,342.97.bbls/mo Gas75.109475.1094 15.001,591.031 NGL Yield19.670.9bbl/MMcf 20.00997.882 Gas Shrinkage80.431.5% Oil Severance4.64.6% Gas Severance7.57.5% NGL Severance7.57.5% Ad Valorem48.6% Start Date: 04/20189 Months in year ‘1819.898 Year Life (02/2038)THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. TEXAS REGISTERED ENGINEERINGFIRM F-693.ASN 432DEFAULT 1/10/2018 10:34:19 OIL PUDTable 5Cawley, Gillespie & Associates, Inc.   Table 6Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Undeveloped ReservesLILIS ENERGY, INC. -- HIPPO PUD-1PHANTOM (WOLFCAMP B) FIELD -- WINKLER COUNTY, TEXAS(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGL EndProductionProductionProductionProductionSalesProductionPricePricePrice Mo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL 12-2018.0.0.0.000.000.000.000.000.000 12-201910.531.62.27.27814.8471.50747.7462.6198.728 12-2020119.5358.424.782.415168.12717.06047.7462.6198.728 12-202154.5163.511.337.59776.6987.78347.7462.6198.728 12-202237.2111.77.725.68952.4065.31847.7462.6198.728 12-202328.886.36.019.83740.4674.10647.7462.6198.728 12-202423.771.04.916.33933.3313.38247.7462.6198.728 12-202520.160.44.213.90128.3582.87847.7462.6198.728 12-202617.652.93.712.16924.8242.51947.7462.6198.728 12-202715.747.23.310.85022.1352.24647.7462.6198.728 12-202814.342.83.09.83620.0662.03647.7462.6198.728 12-202913.039.02.78.96518.2881.85647.7462.6198.728 12-203011.935.82.58.24416.8181.70747.7462.6198.728 12-203111.033.02.37.58515.4731.57047.7462.6198.728 12-203210.130.42.16.99714.2741.44847.7462.6198.728 12-20339.327.91.96.41913.0951.32947.7462.6198.728 12-20348.625.71.85.90612.0481.22347.7462.6198.728 12-20357.923.61.65.43411.0851.12547.7462.6198.728 12-20367.321.81.55.01310.2261.03847.7462.6198.728 S Tot421.01,263.087.2290.473592.56660.12847.7462.6198.728 After22.467.14.615.43931.4953.19647.7462.6198.728 Total443.41,330.291.8305.912624.06163.32447.7462.6198.728 Cum.0.0.0 Ult443.41,330.291.8 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6 Mo-YearM$M$M$M$M$M$M$M$ 12-2018.000.000.0000.0000.000.000.000.000.000 12-2019347.50538.88413.1490.0000.000399.53719.9579.9883.371 12-20203,935.005440.304148.8930.0000.0004,524.201225.987113.1054.104 12-20211,795.120200.86367.9240.0000.0002,063.907103.09451.5985.713 12-20221,226.554137.24446.4100.0000.0001,410.20970.44135.2557.084 12-2023947.120105.97735.8370.0000.0001,088.93554.39327.2238.362 12-2024780.11687.29029.5180.0000.000896.92444.80222.4239.562 12-2025663.71974.26625.1140.0000.000763.09838.11719.07710.756 12-2026581.01465.01221.9840.0000.000668.01133.36816.70011.895 12-2027518.06657.96819.6030.0000.000595.63729.75214.89113.006 12-2028469.63652.54917.7700.0000.000539.95626.97113.49914.063 12-2029428.04247.89516.1960.0000.000492.13424.58212.30315.162 12-2030393.62344.04414.8940.0000.000452.56022.60611.31416.247 12-2031362.15340.52313.7030.0000.000416.37920.79810.40917.419 12-2032334.07537.38112.6410.0000.000384.09719.1869.60218.652 12-2033306.49234.29511.5970.0000.000352.38317.6028.81020.083 12-2034281.98831.55310.6700.0000.000324.21116.1958.10521.588 12-2035259.44429.0309.8170.0000.000298.29114.9007.45723.225 12-2036239.32926.7809.0560.0000.000275.16513.7456.87924.946 S Tot13,869.0021,551.859524.7750.0000.00015,945.636796.497398.6419.280 After737.14282.48227.8920.0000.000847.51542.33421.18829.718 Total14,606.1441,634.340552.6670.0000.00016,793.151838.831419.82910.311 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash Flow EndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. % Mo-YearM$CountM$M$M$M$M$M$M$ 12-2018.00000.00.0000.0000.000.000.000.000.000 12-20196.61410.80.0000.00029.5596,834.214-6,500.794-6,500.794-5,484.396 12-2020164.02110.80.0000.000334.712.0003,686.376-2,814.418-2,550.011 12-2021164.02110.80.0000.000152.693.0001,592.501-1,221.917-1,404.239 12-2022164.02110.80.0000.000104.331.0001,036.161-185.756-727.408 12-2023164.02110.80.0000.00080.562.000762.735576.979-274.737 12-2024164.02110.80.0000.00066.357.000599.3211,176.30048.482 12-2025164.02110.80.0000.00056.456.000485.4271,661.727286.397 12-2026164.02110.80.0000.00049.421.000404.5012,066.227466.607 12-2027164.02110.80.0000.00044.067.000342.9052,409.133605.479 12-2028164.02110.80.0000.00039.947.000295.5172,704.650714.266 12-2029164.02110.80.0000.00036.409.000254.8182,959.468799.527 12-2030164.02110.80.0000.00033.482.000221.1383,180.606866.798 12-2031164.02110.80.0000.00030.805.000190.3463,370.951919.444 12-2032164.02110.80.0000.00028.416.000162.8713,533.823960.400 12-2033164.02110.80.0000.00026.070.000135.8813,669.703991.461 12-2034164.02110.80.0000.00023.986.000111.9043,781.6071,014.719 12-2035164.02110.80.0000.00022.068.00089.8453,871.4521,031.699 12-2036164.02110.80.0000.00020.357.00070.1623,941.6141,043.758 S Tot2,794.973 0.0000.0001,179.6976,834.2143,941.6143,941.6141,043.758 After613.844 0.0000.00062.701.000107.4484,049.0621,059.410 Total3,408.817 0.0000.0001,242.3996,834.2144,049.0624,049.0621,059.410 Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeinDef InitialFinalUnits Final 5.002,182.729 Oil Rate22,812.423.bbls/mo 96.3%1.200.0% 7,741.15,768.$/w/mo Expense85.427785.4277 8.001,445.838 Gas Rate68,437.1,271.Mcf/mo 0.0%0.000.0% Revenue 10.001,059.410 GOR3,000.3,000.scf/bbl Oil68.993568.9935 12.00737.240 NGL Rate2,183.86.bbls/mo Gas68.993568.9935 15.00348.155 NGL Yield31.968.2bbl/MMcf 20.00-118.834 Gas Shrinkage69.131.9% Oil Severance4.64.6% Gas Severance7.57.5% NGL Severance7.57.5% Ad Valorem39.7 % Start Date: 12/20191 Months in year ‘1920.832 Year Life (09/2040)THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. TEXAS REGISTERED ENGINEERINGFIRM F-693.ASN 491DEFAULT 1/10/2018 10:34:19 OIL PUDTable 6Cawley, Gillespie & Associates, Inc.   Table 7Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Undeveloped ReservesLILIS ENERGY, INC. -- HIPPO PUD-2PHANTOM (WOLFCAMP B) FIELD -- WINKLER COUNTY, TEXAS(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGL EndProductionProductionProductionProductionSalesProductionPricePricePrice Mo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL 12-2018.0.0.0.000.000.000.000.000.000 12-2019.0.0.0.000.000.000.000.000.000 12-2020121.6364.925.291.351186.35718.91047.7462.6198.728 12-202157.8173.312.043.38188.4968.98047.7462.6198.728 12-202238.6115.88.028.98459.1276.00047.7462.6198.728 12-202329.588.56.122.16245.2114.58847.7462.6198.728 12-202424.272.55.018.15337.0323.75847.7462.6198.728 12-202520.561.54.215.38931.3943.18647.7462.6198.728 12-202617.953.73.713.43827.4132.78247.7462.6198.728 12-202715.947.83.311.96024.3982.47647.7462.6198.728 12-202814.443.23.010.82622.0862.24147.7462.6198.728 12-202913.139.42.79.85720.1072.04047.7462.6198.728 12-203012.136.22.59.06118.4851.87647.7462.6198.728 12-203111.133.32.38.33717.0071.72647.7462.6198.728 12-203210.230.72.17.69115.6891.59247.7462.6198.728 12-20339.428.21.97.05614.3931.46047.7462.6198.728 12-20348.625.91.86.49113.2431.34447.7462.6198.728 12-20358.023.91.65.97212.1841.23647.7462.6198.728 12-20367.322.01.55.50911.2391.14047.7462.6198.728 S Tot420.21,260.687.0315.619643.86365.33347.7462.6198.728 After18.254.53.813.64527.8362.82547.7462.6198.728 Total438.41,315.190.7329.264671.69968.15847.7462.6198.728 Cum.0.0.0 Ult438.41,315.190.7 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6 Mo-YearM$M$M$M$M$M$M$M$ 12-2018.000.000.0000.0000.000.000.000.000.000 12-2019.000.000.0000.0000.000.000.000.000.000 12-20204,361.681488.046165.0370.0000.0005,014.764250.491125.3694.283 12-20212,071.260231.76278.3720.0000.0002,381.394118.95259.5355.963 12-20221,383.874154.84752.3630.0000.0001,591.08579.47639.7777.454 12-20231,058.164118.40240.0390.0000.0001,216.60560.77030.4158.837 12-2024866.74496.98432.7960.0000.000996.52349.77724.91310.134 12-2025734.77982.21727.8030.0000.000844.79942.19821.12011.423 12-2026641.61071.79224.2770.0000.000737.67936.84818.44212.651 12-2027571.03663.89621.6070.0000.000656.53932.79516.41313.849 12-2028516.91657.84019.5590.0000.000594.31529.68614.85814.989 12-2029470.61452.65917.8070.0000.000541.08027.02713.52716.172 12-2030432.64348.41016.3700.0000.000497.42424.84712.43617.331 12-2031398.05544.54015.0620.0000.000457.65622.86011.44118.580 12-2032367.19341.08713.8940.0000.000422.17421.08810.55419.893 12-2033336.87537.69412.7470.0000.000387.31619.3479.68321.416 12-2034309.94334.68111.7280.0000.000356.35117.8008.90923.020 12-2035285.16431.90810.7900.0000.000327.86216.3778.19724.763 12-2036263.05529.4349.9530.0000.000302.44215.1077.56126.595 S Tot15,069.6061,686.199570.2030.0000.00017,326.008865.447433.1509.945 After651.50972.90024.6520.0000.000749.06037.41618.72730.819 Total15,721.1141,759.099594.8550.0000.00018,075.068902.863451.87710.810 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash Flow EndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. % Mo-YearM$CountM$M$M$M$M$M$M$ 12-2018.00000.00.0000.0000.000.000.000.000.000 12-2019.00000.00.0000.0000.0008,000.000-8,000.000-8,000.000-6,669.620 12-2020178.06511.00.0000.000398.928.0004,061.911-3,938.089-3,449.158 12-2021192.00011.00.0000.000189.442.0001,821.465-2,116.624-2,138.252 12-2022192.00011.00.0000.000126.572.0001,153.260-963.364-1,384.827 12-2023192.00011.00.0000.00096.782.000836.637-126.727-888.251 12-2024192.00011.00.0000.00079.274.000650.559523.832-537.374 12-2025192.00011.00.0000.00067.204.000522.2761,046.109-281.383 12-2026192.00011.00.0000.00058.683.000431.7071,477.815-89.043 12-2027192.00011.00.0000.00052.228.000363.1021,840.91858.016 12-2028192.00011.00.0000.00047.278.000310.4932,151.410172.323 12-2029192.00011.00.0000.00043.043.000265.4832,416.893261.157 12-2030192.00011.00.0000.00039.570.000228.5712,645.464330.692 12-2031192.00011.00.0000.00036.407.000194.9482,840.411384.614 12-2032192.00011.00.0000.00033.584.000164.9473,005.359426.095 12-2033192.00011.00.0000.00030.811.000135.4753,140.834457.066 12-2034192.00011.00.0000.00028.348.000109.2943,250.128479.785 12-2035192.00011.00.0000.00026.082.00085.2073,335.334495.891 12-2036192.00011.00.0000.00024.060.00063.7153,399.049506.846 S Tot3,250.065 0.0000.0001,378.2978,000.0003,399.0493,399.049506.846 After560.516 0.0000.00059.588.00072.8133,471.862517.736 Total3,810.581 0.0000.0001,437.8858,000.0003,471.8623,471.862517.736 Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeinDef InitialFinalUnits Final 5.001,621.919 Oil Rate22,812.458.bbls/mo 96.3%1.200.0% 2,064.16,000.$/w/mo Expense100.0000100.0000 8.00895.904 Gas Rate68,437.1,376.Mcf/mo 0.0%0.000.0% Revenue 10.00517.736 GOR3,000.3,000.scf/bbl Oil75.109475.1094 12.00204.618 NGL Rate609.93.bbls/mo Gas75.109475.1094 15.00-169.616 NGL Yield8.968.3bbl/MMcf 20.00-609.471 Gas Shrinkage91.431.8% Oil Severance4.64.6% Gas Severance7.57.5% NGL Severance7.57.5% Ad Valorem46.8 % Start Date: 01/202012 Months in year ‘2019.916 Year Life (11/2039)THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. TEXAS REGISTERED ENGINEERINGFIRM F-693.ASN 492DEFAULT 1/10/2018 10:34:19 OIL PUDTable 7Cawley, Gillespie & Associates, Inc.   Table 8Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Undeveloped ReservesLILIS ENERGY, INC. -- HIPPO PUD-3PHANTOM (WOLFCAMP B) FIELD -- WINKLER COUNTY, TEXAS (1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGL EndProductionProductionProductionProductionSalesProductionPricePricePrice Mo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL 12-2018.0.0.0.000.000.000.000.000.000 12-2019.0.0.0.000.000.000.000.000.000 12-202028.485.25.91.0652.173.22047.7462.6198.728 12-2021107.0321.122.24.0148.188.83147.7462.6198.728 12-202252.5157.410.91.9684.014.40747.7462.6198.728 12-202336.4109.17.51.3632.781.28247.7462.6198.728 12-202428.385.05.91.0622.167.22047.7462.6198.728 12-202523.369.94.8.8731.782.18147.7462.6198.728 12-202619.959.84.1.7471.524.15547.7462.6198.728 12-202717.552.43.6.6551.336.13647.7462.6198.728 12-202815.646.93.2.5861.196.12147.7462.6198.728 12-202914.142.32.9.5291.079.11047.7462.6198.728 12-203012.938.72.7.484.987.10047.7462.6198.728 12-203111.935.62.5.445.908.09247.7462.6198.728 12-203210.932.82.3.411.838.08547.7462.6198.728 12-203310.030.12.1.377.769.07847.7462.6198.728 12-20349.227.71.9.347.707.07247.7462.6198.728 12-20358.525.51.8.319.651.06647.7462.6198.728 12-20367.823.51.6.294.600.06147.7462.6198.728 S Tot414.41,243.185.815.53931.6993.21747.7462.6198.728 After23.971.74.9.8961.829.18647.7462.6198.728 Total438.31,314.890.716.43533.5283.40247.7462.6198.728 Cum.0.0.0 Ult438.31,314.890.7 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6 Mo-YearM$M$M$M$M$M$M$M$ 12-2018.000.000.0000.0000.000.000.000.000.000 12-2019.000.000.0000.0000.000.000.000.000.000 12-202050.8555.6901.9240.0000.00058.4692.9211.4623.713 12-2021191.63521.4437.2510.0000.000220.32911.0065.5084.588 12-202293.95110.5133.5550.0000.000108.0185.3962.7006.275 12-202365.0997.2842.4630.0000.00074.8463.7391.8717.741 12-202450.7135.6751.9190.0000.00058.3072.9121.4589.095 12-202541.6974.6661.5780.0000.00047.9402.3951.19910.421 12-202635.6663.9911.3500.0000.00041.0072.0481.02511.681 12-202731.2753.4991.1830.0000.00035.9571.796.89912.905 12-202827.9943.1321.0590.0000.00032.1851.608.80514.070 12-202925.2632.827.9560.0000.00029.0451.451.72615.271 12-203023.1082.586.8740.0000.00026.5681.327.66416.418 12-203121.2532.378.8040.0000.00024.4361.221.61117.592 12-203219.6062.194.7420.0000.00022.5411.126.56418.821 12-203317.9872.013.6810.0000.00020.6801.033.51720.248 12-203416.5491.852.6260.0000.00019.027.950.47621.750 12-203515.2261.704.5760.0000.00017.506.874.43823.382 12-203614.0451.572.5310.0000.00016.148.807.40425.098 S Tot741.92183.01628.0730.0000.000853.01042.60821.3259.721 After42.8014.7891.6200.0000.00049.2102.4581.23029.808 Total784.72287.80629.6920.0000.000902.22045.06722.55510.816 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash Flow EndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. % Mo-YearM$CountM$M$M$M$M$M$M$ 12-2018.00000.00.0000.0000.000.000.000.000.000 12-2019.00000.00.0000.0000.000.000.000.000.000 12-20201.17310.10.0000.0004.658400.000-351.745-351.745-272.383 12-20219.60010.10.0000.00017.553.000176.662-175.083-144.691 12-20229.60010.10.0000.0008.605.00081.717-93.366-91.246 12-20239.60010.10.0000.0005.963.00053.674-39.692-59.372 12-20249.60010.10.0000.0004.645.00039.692-.001-37.958 12-20259.60010.10.0000.0003.819.00030.92830.927-22.796 12-20269.60010.10.0000.0003.267.00025.06755.994-11.626 12-20279.60010.10.0000.0002.865.00020.79876.791-3.202 12-20289.60010.10.0000.0002.564.00017.60994.4003.281 12-20299.60010.10.0000.0002.314.00014.954109.3558.285 12-20309.60010.10.0000.0002.117.00012.860122.21512.198 12-20319.60010.10.0000.0001.947.00011.058133.27215.256 12-20329.60010.10.0000.0001.796.0009.456142.72817.634 12-20339.60010.10.0000.0001.648.0007.883150.61119.436 12-20349.60010.10.0000.0001.516.0006.485157.09620.783 12-20359.60010.10.0000.0001.395.0005.199162.29521.766 12-20369.60010.10.0000.0001.286.0004.052166.34622.462 S Tot154.773 0.0000.00067.957400.000166.346166.34622.462 After35.481 0.0000.0003.920.0006.121172.46723.355 Total190.254 0.0000.00071.877400.000172.467172.46723.355 Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeinDef InitialFinalUnits Final 5.0077.154 Oil Rate22,812.459.bbls/mo 96.3%1.200.0% 7,460.16,000.$/w/mo Expense5.00005.0000 8.0041.415 Gas Rate68,437.1,378.Mcf/mo 0.0%0.000.0% Revenue 10.0023.355 GOR3,000.3,000.scf/bbl Oil3.75003.7500 12.008.779 NGL Rate2,046.97.bbls/mo Gas3.75003.7500 15.00-8.064 NGL Yield29.970.7bbl/MMcf 20.00-26.704 Gas Shrinkage70.132.3% Oil Severance4.64.6% Gas Severance7.57.5% NGL Severance7.57.5% Ad Valorem2.4% Start Date: 11/20202 Months in year ‘2019.869 Year Life (09/2040)THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. TEXAS REGISTERED ENGINEERINGFIRM F-693.ASN 493DEFAULT 1/10/2018 10:34:19 OIL PUDTable 8Cawley, Gillespie & Associates, Inc.   Table 9Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Undeveloped ReservesLILIS ENERGY, INC. -- KUDU 1 PUD-2PHANTOM (WOLFCAMP A) FIELD -- WINKLER COUNTY, TEXAS(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGL EndProductionProductionProductionProductionSalesProductionPricePricePrice Mo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL 12-2018.0.0.0.000.000.000.000.000.000 12-2019.0.0.0.000.000.000.000.000.000 12-2020102.8308.421.373.073149.06915.12647.7462.6198.728 12-202156.2168.511.639.93381.4638.26647.7462.6198.728 12-202236.6109.87.626.01153.0635.38447.7462.6198.728 12-202327.783.05.719.67940.1464.07447.7462.6198.728 12-202422.567.64.716.02532.6903.31747.7462.6198.728 12-202519.057.13.913.53427.6092.80247.7462.6198.728 12-202616.649.73.411.78724.0462.44047.7462.6198.728 12-202714.744.23.010.47121.3602.16747.7462.6198.728 12-202813.339.92.89.46419.3071.95947.7462.6198.728 12-202912.136.32.58.60717.5571.78247.7462.6198.728 12-203011.133.42.37.90916.1341.63747.7462.6198.728 12-203110.230.72.17.27714.8451.50647.7462.6198.728 12-20329.428.32.06.71313.6941.38947.7462.6198.728 12-20338.726.01.86.15812.5631.27547.7462.6198.728 12-20348.023.91.65.66611.5591.17347.7462.6198.728 12-20357.322.01.55.21310.6351.07947.7462.6198.728 12-20366.820.31.44.8099.810.99547.7462.6198.728 S Tot383.11,149.279.3272.328555.54956.37247.7462.6198.728 After17.351.83.612.27425.0392.54147.7462.6198.728 Total400.31,201.082.9284.602580.58858.91347.7462.6198.728 Cum.0.0.0 Ult400.31,201.082.9 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6 Mo-YearM$M$M$M$M$M$M$M$ 12-2018.000.000.0000.0000.000.000.000.000.000 12-2019.000.000.0000.0000.000.000.000.000.000 12-20203,488.953390.393132.0150.0000.0004,011.360200.370100.2843.985 12-20211,906.651213.34372.1440.0000.0002,192.138109.49954.8035.571 12-20221,241.939138.96646.9920.0000.0001,427.89771.32535.6977.092 12-2023939.612105.13735.5530.0000.0001,080.30253.96227.0088.496 12-2024765.11785.61228.9500.0000.000879.67943.94121.9929.812 12-2025646.19272.30524.4510.0000.000742.94837.11118.57411.116 12-2026562.78862.97321.2950.0000.000647.05632.32116.17612.359 12-2027499.92755.93918.9160.0000.000574.78228.71114.37013.570 12-2028451.88250.56317.0980.0000.000519.54325.95212.98914.722 12-2029410.93045.98115.5490.0000.000472.46023.60011.81115.918 12-2030377.62642.25414.2890.0000.000434.16921.68710.85417.081 12-2031347.43638.87613.1460.0000.000399.45819.9539.98618.328 12-2032320.49935.86212.1270.0000.000368.48818.4069.21219.639 12-2033294.03632.90111.1260.0000.000338.06316.8868.45221.161 12-2034270.52930.27110.2360.0000.000311.03615.5367.77622.763 12-2035248.90127.8509.4180.0000.000286.16914.2947.15424.504 12-2036229.60325.6918.6880.0000.000263.98213.1866.60026.334 S Tot13,002.6211,454.916491.9930.0000.00014,949.529746.740373.7389.735 After586.03765.57422.1740.0000.000673.78633.65616.84530.648 Total13,588.6591,520.490514.1670.0000.00015,623.315780.396390.58310.637 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash Flow EndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. % Mo-YearM$CountM$M$M$M$M$M$M$ 12-2018.00000.00.0000.0000.000.000.000.000.000 12-2019.00000.00.0000.0000.000.000.000.000.000 12-2020135.44210.90.0000.000293.9186,974.597-3,693.251-3,693.251-3,168.503 12-2021167.39010.90.0000.000160.621.0001,699.824-1,993.427-1,944.757 12-2022167.39010.90.0000.000104.624.0001,048.861-944.566-1,259.457 12-2023167.39010.90.0000.00079.155.000752.787-191.780-812.623 12-2024167.39010.90.0000.00064.455.000581.901390.122-498.765 12-2025167.39010.90.0000.00054.437.000465.436855.558-270.628 12-2026167.39010.90.0000.00047.411.000383.7571,239.315-99.647 12-2027167.39010.90.0000.00042.115.000322.1961,561.51130.846 12-2028167.39010.90.0000.00038.068.000275.1451,836.656132.141 12-2029167.39010.90.0000.00034.618.000235.0412,071.697210.789 12-2030167.39010.90.0000.00031.812.000202.4252,274.122272.369 12-2031167.39010.90.0000.00029.269.000172.8592,446.981320.181 12-2032167.39010.90.0000.00027.000.000146.4792,593.461357.018 12-2033167.39010.90.0000.00024.770.000120.5642,714.025384.580 12-2034167.39010.90.0000.00022.790.00097.5432,811.567404.855 12-2035167.39010.90.0000.00020.968.00076.3622,887.929419.289 12-2036167.39010.90.0000.00019.342.00057.4642,945.393429.169 S Tot2,813.687 0.0000.0001,095.3736,974.5972,945.3932,945.393429.169 After505.321 0.0000.00049.369.00068.5953,013.988439.390 Total3,319.008 0.0000.0001,144.7436,974.5973,013.9883,013.988439.390 Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeinDef InitialFinalUnits Final 5.001,396.836 Oil Rate20,835.419.bbls/mo 96.3%1.200.0% 11,354.15,999.$/w/mo Expense87.182587.1825 8.00766.351 Gas Rate62,506.1,258.Mcf/mo 0.0%0.000.0% Revenue 10.00439.390 GOR3,000.3,000.scf/bbl Oil71.094071.0940 12.00169.674 NGL Rate2,846.88.bbls/mo Gas71.094071.0940 15.00-151.106 NGL Yield45.570.6bbl/MMcf 20.00-524.873 Gas Shrinkage55.931.8% Oil Severance4.64.6% Gas Severance7.57.5% NGL Severance7.57.5% Ad Valorem41.9 % Start Date: 03/202010 Months in year ‘2019.851 Year Life (01/2040)THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. TEXAS REGISTERED ENGINEERINGFIRM F-693.ASN 484DEFAULT 1/10/2018 10:34:19 OIL PUDTable 9Cawley, Gillespie & Associates, Inc.   Table 10Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Undeveloped ReservesLILIS ENERGY, INC. -- LION 1 PUD-2PHANTOM (WOLFCAMP B) FIELD -- WINKLER COUNTY, TEXAS(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGLEndProductionProductionProductionProductionSalesProductionPricePricePriceMo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL12-2018.0.0.0.000.000.000.000.000.000 12-2019.0.0.0.000.000.000.000.000.000 12-202079.2237.716.452.252106.59510.81647.7462.6198.728 12-202177.1231.416.050.851103.73610.52647.7462.6198.728 12-202245.3136.09.429.89460.9846.18847.7462.6198.728 12-202333.099.16.821.77944.4294.50847.7462.6198.728 12-202426.479.15.517.38435.4633.59847.7462.6198.728 12-202522.066.04.614.50129.5823.00247.7462.6198.728 12-202619.057.03.912.52325.5472.59247.7462.6198.728 12-202716.850.33.511.05622.5542.28947.7462.6198.728 12-202815.145.33.19.94720.2922.05947.7462.6198.728 12-202913.741.02.89.01218.3851.86647.7462.6198.728 12-203012.537.62.68.26616.8631.71147.7462.6198.728 12-203111.534.62.47.60515.5151.57447.7462.6198.728 12-203210.631.92.27.01614.3121.45247.7462.6198.728 12-20339.829.32.06.43613.1301.33247.7462.6198.728 12-20349.026.91.95.92212.0811.22647.7462.6198.728 12-20358.324.81.75.44811.1151.12847.7462.6198.728 12-20367.622.91.65.02610.2531.04047.7462.6198.728 S Tot416.91,250.886.3274.919560.83556.90847.7462.6198.728 After17.652.73.611.59323.6502.40047.7462.6198.728 Total434.51,303.589.9286.512584.48559.30847.7462.6198.728 Cum.0.0.0 Ult434.51,303.589.9 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6Mo-YearM$M$M$M$M$M$M$M$ 12-2018.000.000.0000.0000.000.000.000.000.000 12-2019.000.000.0000.0000.000.000.000.000.000 12-20202,494.853279.15994.4000.0000.0002,868.412143.27971.7104.191 12-20212,427.939271.67291.8680.0000.0002,791.479139.43669.7875.487 12-20221,427.330159.71054.0070.0000.0001,641.04781.97241.0267.147 12-20231,039.868116.35539.3460.0000.0001,195.56959.72029.8898.648 12-2024830.01192.87331.4060.0000.000954.29047.66723.85710.046 12-2025692.35777.47126.1970.0000.000796.02539.76219.90111.423 12-2026597.91966.90422.6240.0000.000687.44634.33817.18612.735 12-2027527.88059.06719.9740.0000.000606.92130.31615.17314.011 12-2028474.92453.14117.9700.0000.000546.03527.27513.65115.225 12-2029430.30248.14816.2820.0000.000494.73124.71212.36816.480 12-2030394.68944.16314.9340.0000.000453.78722.66711.34517.686 12-2031363.12440.63113.7400.0000.000417.49520.85410.43718.952 12-2032334.97137.48112.6750.0000.000385.12719.2379.62820.283 12-2033307.31334.38711.6280.0000.000353.32817.6498.83321.827 12-2034282.74431.63710.6980.0000.000325.08016.2388.12723.453 12-2035260.13929.1089.8430.0000.000299.09114.9407.47725.220 12-2036239.97126.8519.0800.0000.000275.90213.7826.89827.077 S Tot13,126.3341,468.758496.6740.0000.00015,091.766753.845377.29410.331 After553.53261.93720.9450.0000.000636.41431.78915.91031.007 Total13,679.8661,530.695517.6180.0000.00015,728.179785.634393.20411.168 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash FlowEndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. %Mo-YearM$CountM$M$M$M$M$M$M$12-2018.00000.00.0000.0000.000.000.000.000.000 12-2019.00000.00.0000.0000.000.000.000.000.000 12-202082.57210.90.0000.000240.3567,398.025-5,067.530-5,067.530-4,107.117 12-2021177.55310.90.0000.000233.910.0002,170.793-2,896.737-2,542.175 12-2022177.55310.90.0000.000137.510.0001,202.986-1,693.751-1,755.824 12-2023177.55310.90.0000.000100.182.000828.226-865.524-1,264.098 12-2024177.55310.90.0000.00079.964.000625.249-240.276-926.810 12-2025177.55310.90.0000.00066.702.000492.108251.832-685.574 12-2026177.55310.90.0000.00057.604.000400.765652.597-507.000 12-2027177.55310.90.0000.00050.856.000333.023985.620-372.112 12-2028177.55310.90.0000.00045.755.000281.8021,267.422-268.359 12-2029177.55310.90.0000.00041.456.000238.6431,506.065-188.501 12-2030177.55310.90.0000.00038.025.000204.1981,710.263-126.380 12-2031177.55310.90.0000.00034.984.000173.6671,883.930-78.343 12-2032177.55310.90.0000.00032.271.000146.4372,030.368-41.515 12-2033177.55310.90.0000.00029.607.000119.6862,150.054-14.153 12-2034177.55310.90.0000.00027.240.00095.9232,245.9765.787 12-2035177.55310.90.0000.00025.062.00074.0592,320.03519.787 12-2036177.55310.90.0000.00023.119.00054.5512,374.58729.168 S Tot2,923.413 0.0000.0001,264.6027,398.0252,374.5872,374.58729.168 After476.724 0.0000.00053.328.00058.6622,433.24837.966 Total3,400.137 0.0000.0001,317.9307,398.0252,433.2482,433.24837.966  Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum Disc. InitialFinalUnits DeinDef InitialFinalUnits Final 5.00911.841 Oil Rate22,812.485.bbls/mo 96.3%1.200.0% 9,290.15,999.$/w/mo Expense92.475392.4753 8.00332.782 Gas Rate68,437.1,456.Mcf/mo 0.0%0.000.0% Revenue 10.0037.966 GOR3,000.3,000.scf/bbl Oil65.940265.9402 12.00-201.209 NGL Rate2,589.103.bbls/mo Gas65.940265.9402 15.00-479.037 NGL Yield37.870.7bbl/MMcf 20.00-788.367 Gas Shrinkage63.431.7% Oil Severance4.64.6% Gas Severance7.57.5% NGL Severance7.57.5% Ad Valorem45.0 % Start Date: 07/2020 6 Months in year ‘20 19.192 Year Life (09/2039)THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.ASN 490DEFAULT 1/10/2018 10:34:19 TEXAS REGISTERED ENGINEERING FIRM F-693. OIL PUD Table 10Cawley, Gillespie & Associates, Inc.   Table 11Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Undeveloped ReservesLILIS ENERGY, INC. -- LION 3 PUD-1PHANTOM (WOLFCAMP B) FIELD -- WINKLER COUNTY, TEXAS(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGLEndProductionProductionProductionProductionSalesProductionPricePricePriceMo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL12-2018.0.0.0.000.000.000.000.000.000 12-2019.0.0.0.000.000.000.000.000.000 12-202065.1195.413.542.94687.6118.89047.7462.6198.728 12-202184.7254.017.555.836113.90611.55847.7462.6198.728 12-202247.5142.49.831.29663.8456.47847.7462.6198.728 12-202334.1102.27.122.46045.8184.64947.7462.6198.728 12-202427.080.95.617.79236.2963.68347.7462.6198.728 12-202522.467.24.614.77430.1393.05847.7462.6198.728 12-202619.357.94.012.72025.9492.63347.7462.6198.728 12-202717.051.03.511.20522.8592.32047.7462.6198.728 12-202815.345.83.210.06520.5322.08347.7462.6198.728 12-202913.841.42.99.10718.5791.88547.7462.6198.728 12-203012.738.02.68.34717.0271.72847.7462.6198.728 12-203111.634.92.47.67915.6641.58947.7462.6198.728 12-203210.732.22.27.08314.4501.46647.7462.6198.728 12-20339.929.62.06.49813.2571.34547.7462.6198.728 12-20349.127.21.95.97912.1971.23847.7462.6198.728 12-20358.325.01.75.50111.2221.13947.7462.6198.728 12-20367.723.11.65.07410.3521.05047.7462.6198.728 S Tot416.11,248.286.1274.363559.70156.79347.7462.6198.728 After18.455.33.812.14924.7842.51547.7462.6198.728 Total434.51,303.589.9286.512584.48559.30847.7462.6198.728 Cum.0.0.0 Ult434.51,303.589.9 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6Mo-YearM$M$M$M$M$M$M$M$ 12-2018.000.000.0000.0000.000.000.000.000.000 12-2019.000.000.0000.0000.000.000.000.000.000 12-20202,050.529229.44277.5880.0000.0002,357.559117.76258.9394.107 12-20212,665.972298.306100.8750.0000.0003,065.154153.10776.6295.276 12-20221,494.281167.20156.5410.0000.0001,718.02385.81742.9516.967 12-20231,072.377119.99340.5770.0000.0001,232.94661.58730.8248.481 12-2024849.51795.05632.1440.0000.000976.71748.78824.4189.887 12-2025705.40378.93026.6910.0000.000811.02540.51120.27611.270 12-2026607.32867.95622.9800.0000.000698.26434.87917.45712.586 12-2027535.01259.86520.2440.0000.000615.12130.72615.37813.865 12-2028480.54553.77018.1830.0000.000552.49827.59813.81215.083 12-2029434.83348.65516.4530.0000.000499.94224.97212.49916.341 12-2030398.51444.59115.0790.0000.000458.18522.88711.45517.546 12-2031366.62241.02313.8720.0000.000421.51821.05510.53818.801 12-2032338.19837.84212.7970.0000.000388.83719.4239.72120.119 12-2033310.27434.71811.7400.0000.000356.73217.8198.91821.649 12-2034285.46831.94210.8020.0000.000328.21216.3948.20523.259 12-2035262.64629.3889.9380.0000.000301.97215.0847.54925.009 12-2036242.28327.1109.1670.0000.000278.56013.9146.96426.849 S Tot13,099.8031,465.790495.6700.0000.00015,061.263752.321376.53210.296 After580.06264.90621.9480.0000.000666.91633.31316.67330.860 Total13,679.8661,530.695517.6180.0000.00015,728.179785.634393.20411.168 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash FlowEndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. %Mo-YearM$CountM$M$M$M$M$M$M$12-2018.00000.00.0000.0000.000.000.000.000.000 12-2019.00000.00.0000.0000.000.000.000.000.000 12-202062.52510.90.0000.000197.5507,398.025-5,477.241-5,477.241-4,368.485 12-2021177.55310.90.0000.000256.842.0002,401.023-3,076.218-2,636.423 12-2022177.55310.90.0000.000143.960.0001,267.743-1,808.475-1,807.601 12-2023177.55310.90.0000.000103.314.000859.669-948.806-1,297.166 12-2024177.55310.90.0000.00081.843.000644.115-304.690-949.685 12-2025177.55310.90.0000.00067.959.000504.726200.036-702.256 12-2026177.55310.90.0000.00058.510.000409.865609.901-519.624 12-2027177.55310.90.0000.00051.544.000339.921949.822-381.940 12-2028177.55310.90.0000.00046.296.000287.2391,237.061-276.184 12-2029177.55310.90.0000.00041.892.000243.0261,480.088-194.859 12-2030177.55310.90.0000.00038.393.000207.8981,687.985-131.612 12-2031177.55310.90.0000.00035.321.000177.0511,865.036-82.640 12-2032177.55310.90.0000.00032.582.000149.5592,014.595-45.028 12-2033177.55310.90.0000.00029.892.000122.5502,137.145-17.012 12-2034177.55310.90.0000.00027.502.00098.5572,235.7023.476 12-2035177.55310.90.0000.00025.304.00076.4832,312.18517.934 12-2036177.55310.90.0000.00023.342.00056.7872,368.97227.698 S Tot2,903.367 0.0000.0001,262.0467,398.0252,368.9722,368.97227.698 After496.947 0.0000.00055.884.00064.1002,433.07237.279 Total3,400.314 0.0000.0001,317.9307,398.0252,433.0722,433.07237.279 Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum Disc. InitialFinalUnits DeinDef InitialFinalUnits Final 5.00906.478 Oil Rate22,812.485.bbls/mo 96.3%1.200.0% 3,612.15,769.$/w/mo Expense92.475392.4753 8.00329.577 Gas Rate68,437.1,456.Mcf/mo 0.0%0.000.0% Revenue 10.0037.279 GOR3,000.3,000.scf/bbl Oil65.940265.9402 12.00-198.873 NGL Rate1,053.99.bbls/mo Gas65.940265.9402 15.00-471.660 NGL Yield15.468.6bbl/MMcf 20.00-772.253 Gas Shrinkage85.131.5% Oil Severance4.64.6% Gas Severance7.57.5% NGL Severance7.57.5% Ad Valorem43.7 % Start Date: 08/2020 5 Months in year ‘20 19.224 Year Life (10/2039)THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.ASN 497DEFAULT 1/10/201810:34:19TEXAS REGISTERED ENGINEERING FIRM F-693. OIL PUD Table 11 Cawley, Gillespie & Associates, Inc.   Table 12Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Undeveloped ReservesLILIS ENERGY, INC. -- MEERKAT #1HPHANTOM (WOLFCAMP B) FIELD -- WINKLER COUNTY, TEXAS(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGLEndProductionProductionProductionProductionSalesProductionPricePricePriceMo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL12-201899.8299.520.759.144120.65512.24347.7462.6198.728 12-201967.1201.313.939.75981.1088.23047.7462.6198.728 12-202042.2126.68.725.00451.0085.17647.7462.6198.728 12-202131.494.16.518.58637.9153.84747.7462.6198.728 12-202225.375.85.214.97930.5573.10147.7462.6198.728 12-202321.363.94.412.62625.7572.61447.7462.6198.728 12-202418.555.63.810.98722.4132.27447.7462.6198.728 12-202516.449.13.49.70719.8022.00947.7462.6198.728 12-202614.744.23.18.73517.8191.80847.7462.6198.728 12-202713.440.32.87.95416.2271.64747.7462.6198.728 12-202812.437.12.67.32414.9411.51647.7462.6198.728 12-202911.334.02.36.71913.7071.39147.7462.6198.728 12-203010.431.32.26.18212.6111.28047.7462.6198.728 12-20319.628.82.05.68811.6031.17747.7462.6198.728 12-20328.926.61.85.24710.7031.08647.7462.6198.728 12-20338.124.41.74.8149.820.99647.7462.6198.728 12-20347.522.41.54.4299.035.91747.7462.6198.728 12-20356.920.61.44.0758.312.84347.7462.6198.728 12-20366.319.01.33.7597.668.77847.7462.6198.728 S Tot431.61,294.889.3255.716521.66052.93347.7462.6198.728 After6.720.11.43.9618.081.82047.7462.6198.728 Total438.31,314.890.7259.677529.74253.75347.7462.6198.728 Cum.0.0.0 Ult438.31,314.890.7 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6Mo-YearM$M$M$M$M$M$M$M$ 12-20182,823.922315.980106.8510.0000.0003,246.754162.17881.1694.121 12-20191,898.326212.41171.8290.0000.0002,182.567109.02154.5645.553 12-20201,193.836133.58345.1720.0000.0001,372.59168.56234.3157.080 12-2021887.39299.29433.5770.0000.0001,020.26350.96325.5078.501 12-2022715.19780.02627.0620.0000.000822.28541.07420.5579.833 12-2023602.83467.45422.8100.0000.000693.09834.62117.32711.113 12-2024524.57158.69619.8490.0000.000603.11630.12615.07812.329 12-2025463.47751.86017.5370.0000.000532.87426.61713.32213.563 12-2026417.06046.66715.7810.0000.000479.50823.95211.98814.742 12-2027379.78442.49614.3700.0000.000436.64921.81110.91615.898 12-2028349.68939.12813.2320.0000.000402.04920.08310.05117.011 12-2029320.81635.89712.1390.0000.000368.85318.4249.22118.275 12-2030295.16833.02811.1690.0000.000339.36416.9518.48419.605 12-2031271.57030.38710.2760.0000.000312.23315.5967.80621.051 12-2032250.51528.0319.4790.0000.000288.02514.3877.20122.571 12-2033229.83025.7178.6960.0000.000264.24313.1996.60624.336 12-2034211.45623.6618.0010.0000.000243.11812.1446.07826.193 12-2035194.55121.7697.3610.0000.000223.68111.1735.59228.211 12-2036179.46720.0816.7910.0000.000206.33910.3075.15830.333 S Tot12,209.4621,366.166461.9810.0000.00014,037.609701.189350.94010.474 After189.14521.1647.1570.0000.000217.46610.8635.43732.945 Total12,398.6071,387.330469.1380.0000.00014,255.075712.052356.37710.817 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash FlowEndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. %Mo-YearM$CountM$M$M$M$M$M$M$12-2018100.71210.80.0000.000258.6585,372.000-2,727.964-2,727.964-2,709.079 12-2019151.68010.80.0000.000173.878.0001,693.424-1,034.540-1,233.028 12-2020151.68010.80.0000.000109.350.0001,008.685-25.855-435.433 12-2021151.68010.80.0000.00081.281.000710.832684.97775.077 12-2022151.68010.80.0000.00065.509.000543.4661,228.442429.768 12-2023151.68010.80.0000.00055.217.000434.2531,662.695687.361 12-2024151.68010.80.0000.00048.048.000358.1842,020.879880.473 12-2025151.68010.80.0000.00042.452.000298.8022,319.6811,026.889 12-2026151.68010.80.0000.00038.201.000253.6872,573.3691,139.892 12-2027151.68010.80.0000.00034.786.000217.4562,790.8241,227.949 12-2028151.68010.80.0000.00032.030.000188.2052,979.0301,297.232 12-2029151.68010.80.0000.00029.385.000160.1423,139.1711,350.821 12-2030151.68010.80.0000.00027.036.000135.2123,274.3831,391.960 12-2031151.68010.80.0000.00024.875.000112.2763,386.6591,423.020 12-2032151.68010.80.0000.00022.946.00091.8113,478.4711,446.115 12-2033151.68010.80.0000.00021.051.00071.7073,550.1771,462.513 12-2034151.68010.80.0000.00019.368.00053.8483,604.0251,473.711 12-2035151.68010.80.0000.00017.820.00037.4163,641.4411,480.790 12-2036151.68010.80.0000.00016.438.00022.7553,664.1971,484.710 S Tot2,830.952 0.0000.0001,118.3315,372.0003,664.1973,664.1971,484.710 After175.117 0.0000.00017.325.0008.7253,672.9221,486.079 Total3,006.069 0.0000.0001,135.6565,372.0003,672.9223,672.9221,486.079  Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum Disc. InitialFinalUnits DeinDef InitialFinalUnits Final 5.002,363.518 Oil Rate22,812.459.bbls/mo 96.3%1.200.0% 15,483.16,000.$/w/mo Expense79.000079.0000 8.001,799.026 Gas Rate68,437.1,378.Mcf/mo 0.0%0.000.0% Revenue 10.001,486.079 GOR3,000.3,000.scf/bbl Oil59.250059.2500 12.001,213.137 NGL Rate4,126.97.bbls/mo Gas59.250059.2500 15.00863.994 NGL Yield60.370.9bbl/MMcf 20.00402.767 Gas Shrinkage41.731.5% Oil Severance4.64.6% Gas Severance7.57.5% NGL Severance7.57.5% Ad Valorem38.4 % Start Date: 05/2018 8 Months in year ‘18 19.823 Year Life (02/2038)THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.ASN 435DEFAULT 1/10/201810:34:19TEXAS REGISTERED ENGINEERING FIRM F-693. OIL PUD Table 12 Cawley, Gillespie & Associates, Inc.   Table 13Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Undeveloped ReservesLILIS ENERGY, INC. -- MOOSE #1HPHANTOM (WOLFCAMP B) FIELD -- WINKLER COUNTY, TEXAS(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGLEndProductionProductionProductionProductionSalesProductionPricePricePriceMo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL12-201895.0285.019.735.62272.6697.37447.7462.6198.728 12-2019124.5373.525.846.68395.2349.66347.7462.6198.728 12-202069.8209.514.526.19253.4325.42247.7462.6198.728 12-202150.0149.910.318.73438.2173.87847.7462.6198.728 12-202239.5118.48.214.80430.2003.06447.7462.6198.728 12-202332.998.66.812.32825.1502.55247.7462.6198.728 12-202428.485.15.910.64121.7072.20347.7462.6198.728 12-202524.974.85.29.34619.0661.93547.7462.6198.728 12-202622.367.04.68.37317.0811.73347.7462.6198.728 12-202720.360.84.27.59815.5001.57347.7462.6198.728 12-202818.655.93.96.98214.2431.44547.7462.6198.728 12-202917.151.23.56.40513.0651.32647.7462.6198.728 12-203015.747.13.35.89312.0211.22047.7462.6198.728 12-203114.543.43.05.42111.0601.12247.7462.6198.728 12-203213.340.02.85.00110.2021.03547.7462.6198.728 12-203312.236.72.54.5889.360.95047.7462.6198.728 12-203411.333.82.34.2218.612.87447.7462.6198.728 12-203510.431.12.13.8847.923.80447.7462.6198.728 12-20369.628.72.03.5837.309.74247.7462.6198.728 S Tot630.11,890.4130.4236.299482.05048.91447.7462.6198.728 After43.5130.59.016.31833.2883.37847.7462.6198.728 Total673.62,020.9139.4252.617515.33852.29247.7462.6198.728 Cum.0.0.0 Ult673.62,020.9139.4 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6Mo-YearM$M$M$M$M$M$M$M$ 12-20181,700.808190.31064.3550.0000.0001,955.47397.67748.8873.605 12-20192,228.953249.40784.3390.0000.0002,562.699128.00964.0674.360 12-20201,250.583139.93347.3200.0000.0001,437.83671.82135.9465.452 12-2021894.457100.08433.8440.0000.0001,028.38651.36925.7106.441 12-2022706.82079.08926.7450.0000.000812.65440.59320.3167.364 12-2023588.63465.86522.2730.0000.000676.77133.80516.9198.247 12-2024508.05356.84819.2240.0000.000584.12529.17714.6039.084 12-2025446.24849.93216.8850.0000.000513.06525.62812.8279.932 12-2026399.77744.73315.1270.0000.000459.63622.95911.49110.741 12-2027362.78140.59313.7270.0000.000417.10120.83410.42811.534 12-2028333.34637.29912.6130.0000.000383.25919.1449.58112.291 12-2029305.79634.21711.5710.0000.000351.58317.5628.79013.131 12-2030281.34831.48110.6460.0000.000323.47516.1588.08714.014 12-2031258.85528.9649.7950.0000.000297.61414.8667.44014.975 12-2032238.78626.7199.0350.0000.000274.54013.7136.86315.984 12-2033219.07024.5138.2890.0000.000251.87212.5816.29717.155 12-2034201.55622.5537.6260.0000.000231.73511.5755.79318.388 12-2035185.44220.7507.0170.0000.000213.20810.6505.33019.729 12-2036171.06419.1416.4730.0000.000196.6789.8244.91721.137 S Tot11,282.3761,262.431426.9020.0000.00012,971.709647.947324.2938.021 After779.10987.17829.4800.0000.000895.76744.74422.39427.162 Total12,061.4861,349.608456.3820.0000.00013,867.476692.691346.6879.258 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash FlowEndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. %Mo-YearM$CountM$M$M$M$M$M$M$12-201833.54810.50.0000.000155.7865,050.000-3,430.426-3,430.426-3,321.964 12-201996.00010.50.0000.000204.162.0002,070.461-1,359.965-1,514.742 12-202096.00010.50.0000.000114.548.0001,119.521-240.444-629.246 12-202196.00010.50.0000.00081.928.000773.380532.936-73.775 12-202296.00010.50.0000.00064.741.000591.0031,123.939311.936 12-202396.00010.50.0000.00053.916.000476.1301,600.069594.354 12-202496.00010.50.0000.00046.535.000397.8091,997.878808.808 12-202596.00010.50.0000.00040.874.000337.7372,335.615974.285 12-202696.00010.50.0000.00036.618.000292.5682,628.1831,104.593 12-202796.00010.50.0000.00033.229.000256.6102,884.7931,208.492 12-202896.00010.50.0000.00030.533.000228.0003,112.7931,292.407 12-202996.00010.50.0000.00028.009.000201.2223,314.0151,359.729 12-203096.00010.50.0000.00025.770.000177.4603,491.4751,413.708 12-203196.00010.50.0000.00023.710.000155.5983,647.0731,456.738 12-203296.00010.50.0000.00021.872.000136.0913,783.1641,490.954 12-203396.00010.50.0000.00020.066.000116.9283,900.0911,517.678 12-203496.00010.50.0000.00018.462.00099.9053,999.9961,538.438 12-203596.00010.50.0000.00016.986.00084.2434,084.2391,554.354 12-203696.00010.50.0000.00015.669.00070.2684,154.5071,566.425 S Tot1,761.548 0.0000.0001,033.4145,050.0004,154.5074,154.5071,566.425 After582.194 0.0000.00071.363.000175.0724,329.5791,590.421 Total2,343.742 0.0000.0001,104.7775,050.0004,329.5794,329.5791,590.421  Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum Disc. InitialFinalUnits DeinDef InitialFinalUnits Final 5.002,643.355 Oil Rate33,458.459.bbls/mo 96.3%1.200.0% 3,096.16,000.$/w/mo Expense50.000050.0000 8.001,958.920 Gas Rate100,375.1,378.Mcf/mo 0.0%0.000.0% Revenue 10.001,590.421 GOR3,000.3,000.scf/bbl Oil37.500037.5000 12.001,275.334 NGL Rate1,329.97.bbls/mo Gas37.500037.5000 15.00880.759 NGL Yield13.270.9bbl/MMcf 20.00373.988 Gas Shrinkage87.231.5% Oil Severance4.64.6% Gas Severance7.57.5% NGL Severance7.57.5% Ad Valorem_24.3 % Start Date: 08/2018 5 Months in year ‘18 24.482 Year Life (01/2043)THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.ASN 498DEFAULT 1/10/201810:34:19TEXAS REGISTERED ENGINEERING FIRM F-693. OIL PUD Table 13 Cawley, Gillespie & Associates, Inc.   Table 14Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Undeveloped ReservesLILIS ENERGY, INC. -- PRIZE HOG 2HPHANTOM (WOLFCAMP B) FIELD -- LEA COUNTY, NEW MEXICO(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGLEndProductionProductionProductionProductionSalesProductionPricePricePriceMo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL12-2018.0.0.0.000.000.000.000.000.000 12-201977.3232.016.038.67378.8938.00547.7462.6198.728 12-202078.3234.816.239.12679.8178.09947.7462.6198.728 12-202145.6136.79.422.78946.4894.71747.7462.6198.728 12-202233.199.46.916.57433.8113.43147.7462.6198.728 12-202326.479.15.513.18526.8972.72947.7462.6198.728 12-202422.166.34.611.05222.5472.28847.7462.6198.728 12-202519.057.13.99.51319.4071.96947.7462.6198.728 12-202616.850.43.58.39717.1291.73847.7462.6198.728 12-202715.145.23.17.53315.3681.55947.7462.6198.728 12-202813.741.22.86.86213.9981.42047.7462.6198.728 12-202912.637.72.66.27512.8021.29947.7462.6198.728 12-203011.534.62.45.77311.7781.19547.7462.6198.728 12-203110.631.92.25.31210.8361.10047.7462.6198.728 12-20329.829.42.04.9009.9961.01447.7462.6198.728 12-20339.027.01.94.4959.171.93147.7462.6198.728 12-20348.324.81.74.1368.437.85647.7462.6198.728 12-20357.622.81.63.8057.763.78847.7462.6198.728 12-20367.021.11.53.5107.161.72747.7462.6198.728 S Tot423.81,271.587.7211.911432.29943.86647.7462.6198.728 After15.346.03.27.66815.6431.58747.7462.6198.728 Total439.21,317.590.9219.579447.94245.45347.7462.6198.728 Cum.0.0.0 Ult439.21,317.590.9 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6Mo-YearM$M$M$M$M$M$M$M$ 12-2018.000.000.0000.0000.000.000.000.000.000 12-20191,846.498206.61269.8680.0000.0002,122.978152.869106.1493.725 12-20201,868.114209.03170.6860.0000.0002,147.831154.659107.3924.860 12-20211,088.066121.74841.1700.0000.0001,250.98590.08062.5496.352 12-2022791.34088.54629.9430.0000.000909.82965.51445.4917.691 12-2023629.52370.44023.8200.0000.000723.78352.11736.1898.953 12-2024527.71059.04819.9670.0000.000606.72543.68830.33610.144 12-2025454.21650.82417.1870.0000.000522.22737.60426.11111.335 12-2026400.90744.85915.1700.0000.000460.93633.19123.04712.473 12-2027359.68240.24613.6100.0000.000413.53729.77820.67713.583 12-2028327.62436.65912.3970.0000.000376.67927.12418.83414.641 12-2029299.62233.52611.3370.0000.000344.48424.80517.22415.749 12-2030275.65830.84410.4300.0000.000316.93322.82115.84716.876 12-2031253.62028.3799.5960.0000.000291.59520.99714.58018.101 12-2032233.95626.1788.8520.0000.000268.98719.36913.44919.389 12-2033214.63924.0178.1220.0000.000246.77817.77012.33920.884 12-2034197.47922.0977.4720.0000.000227.04816.34911.35222.457 12-2035181.69120.3306.8750.0000.000208.89615.04210.44524.166 12-2036167.60518.7546.3420.0000.000192.70013.8769.63525.964 S Tot10,117.9501,132.138382.8430.0000.00011,632.931837.652581.6479.481 After366.12540.96713.8530.0000.000420.94630.31121.04729.616 Total10,484.0761,173.106396.6960.0000.00012,053.877867.963602.69410.185 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash FlowEndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. %Mo-YearM$CountM$M$M$M$M$M$M$12-2018.00000.00.0000.0000.000.000.000.000.000 12-201953.87110.60.0000.000158.5605,000.000-3,348.471-3,348.471-2,983.690 12-2020120.00010.60.0000.000160.416.0001,605.364-1,743.107-1,710.459 12-2021120.00010.60.0000.00093.433.000884.923-858.184-1,074.219 12-2022120.00010.60.0000.00067.953.000610.871-247.313-675.306 12-2023120.00010.60.0000.00054.058.000461.418214.105-401.501 12-2024120.00010.60.0000.00045.315.000367.385581.490-203.383 12-2025120.00010.60.0000.00039.004.000299.508880.998-56.596 12-2026120.00010.60.0000.00034.426.000250.2721,131.27054.900 12-2027120.00010.60.0000.00030.886.000212.1971,343.467140.836 12-2028120.00010.60.0000.00028.133.000182.5891,526.056208.052 12-2029120.00010.60.0000.00025.729.000156.7261,682.782260.494 12-2030120.00010.60.0000.00023.671.000134.5941,817.376301.440 12-2031120.00010.60.0000.00021.779.000114.2401,931.615333.039 12-2032120.00010.60.0000.00020.090.00096.0792,027.694357.203 12-2033120.00010.60.0000.00018.431.00078.2382,105.932375.089 12-2034120.00010.60.0000.00016.958.00062.3892,168.321388.059 12-2035120.00010.60.0000.00015.602.00047.8082,216.128397.097 12-2036120.00010.60.0000.00014.392.00034.7972,250.926403.082 S Tot2,093.871 0.0000.000868.8365,000.0002,250.9262,250.926403.082 After303.428 0.0000.00031.439.00034.7212,285.646408.316 Total2,397.299 0.0000.000900.2755,000.0002,285.6462,285.646408.316 Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum Disc. InitialFinalUnits DeinDef InitialFinalUnits Final 5.001,126.125 Oil Rate22,812.453.bbls/mo 96.3%1.200.0% 6,192.15,769.$/w/mo Expense62.500062.5000 8.00657.414 Gas Rate68,437.1,359.Mcf/mo 0.0%0.000.0% Revenue 10.00408.316 GOR3,000.3,000.scf/bbl Oil50.000050.0000 12.00198.529 NGL Rate1,768.93.bbls/mo Gas50.000050.0000 15.00-57.924 NGL Yield25.868.5bbl/MMcf 20.00-371.562 Gas Shrinkage75.031.8% Oil Severance7.17.1% Gas Severance7.97.9% NGL Severance7.97.9% Ad Valorem61.7 % Start Date: 07/2019 6 Months in year ‘19 20.033 Year Life (07/2039)THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.ASN 479DEFAULT 1/10/201810:34:19TEXAS REGISTERED ENGINEERING FIRM F-693. OIL PUD Table 14 Cawley, Gillespie & Associates, Inc.   Table 15Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Undeveloped ReservesLILIS ENERGY, INC. -- PRIZE HOG 3HPHANTOM (WOLFCAMP B) FIELD -- LEA COUNTY, NEW MEXICO(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGLEndProductionProductionProductionProductionSalesProductionPricePricePriceMo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL12-2018.0.0.0.000.000.000.000.000.000 12-201959.9179.812.429.96361.1256.20247.7462.6198.728 12-202087.8263.318.243.88689.5289.08447.7462.6198.728 12-202148.2144.510.024.08349.1294.98547.7462.6198.728 12-202234.4103.27.117.19835.0833.56047.7462.6198.728 12-202327.181.35.613.55727.6562.80647.7462.6198.728 12-202422.667.84.711.30223.0562.34047.7462.6198.728 12-202519.458.24.09.69219.7722.00647.7462.6198.728 12-202617.151.23.58.53217.4061.76647.7462.6198.728 12-202715.345.83.27.64015.5851.58147.7462.6198.728 12-202813.941.72.96.94814.1741.43847.7462.6198.728 12-202912.738.12.66.34812.9501.31447.7462.6198.728 12-203011.735.02.45.84011.9131.20947.7462.6198.728 12-203110.732.22.25.37310.9611.11247.7462.6198.728 12-20329.929.72.14.95610.1111.02647.7462.6198.728 12-20339.127.31.94.5479.276.94147.7462.6198.728 12-20348.425.11.74.1848.534.86647.7462.6198.728 12-20357.723.11.63.8497.852.79747.7462.6198.728 12-20367.121.31.53.5517.243.73547.7462.6198.728 S Tot422.91,268.787.5211.449431.35543.77047.7462.6198.728 After16.348.83.48.13116.5861.68347.7462.6198.728 Total439.21,317.590.9219.579447.94245.45347.7462.6198.728 Cum.0.0.0 Ult439.21,317.590.9 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6Mo-YearM$M$M$M$M$M$M$M$ 12-2018.000.000.0000.0000.000.000.000.000.000 12-20191,430.640160.08054.1320.0000.0001,644.853118.44182.2433.633 12-20202,095.398234.46379.2860.0000.0002,409.146173.475120.4574.635 12-20211,149.875128.66443.5090.0000.0001,322.04995.19766.1026.160 12-2022821.12491.87931.0700.0000.000944.07367.98047.2047.513 12-2023647.28972.42824.4920.0000.000744.20953.58837.2108.783 12-2024539.63060.38120.4190.0000.000620.43044.67531.0229.981 12-2025462.77251.78117.5100.0000.000532.06438.31226.60311.177 12-2026407.38745.58415.4150.0000.000468.38533.72723.41912.318 12-2027364.77240.81613.8020.0000.000419.39030.19920.97013.433 12-2028331.74737.12112.5530.0000.000381.42027.46519.07114.493 12-2029303.08433.91311.4680.0000.000348.46625.09217.42315.601 12-2030278.82231.19910.5500.0000.000320.57123.08316.02916.716 12-2031256.53128.7049.7070.0000.000294.94221.23814.74717.927 12-2032236.64226.4798.9540.0000.000272.07519.59113.60419.200 12-2033217.10324.2938.2150.0000.000249.61017.97412.48120.678 12-2034199.74622.3507.5580.0000.000229.65516.53711.48322.233 12-2035183.77720.5646.9540.0000.000211.29415.21510.56523.924 12-2036169.52918.9696.4150.0000.000194.91314.0359.74625.701 S Tot10,095.8711,129.668382.0070.0000.00011,607.545835.824580.3779.444 After388.20543.43814.6890.0000.000446.33232.13922.31729.436 Total10,484.0751,173.106396.6960.0000.00012,053.877867.963602.69410.184 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash FlowEndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. %Mo-YearM$CountM$M$M$M$M$M$M$12-2018.00000.00.0000.0000.000.000.000.000.000 12-201937.66710.60.0000.000122.8505,000.000-3,716.348-3,716.348-3,247.162 12-2020120.00010.60.0000.000179.933.0001,815.280-1,901.067-1,806.240 12-2021120.00010.60.0000.00098.741.000942.009-959.059-1,128.816 12-2022120.00010.60.0000.00070.511.000638.379-320.680-711.899 12-2023120.00010.60.0000.00055.583.000477.827157.147-428.343 12-2024120.00010.60.0000.00046.338.000378.395535.542-224.280 12-2025120.00010.60.0000.00039.739.000307.410842.952-73.617 12-2026120.00010.60.0000.00034.983.000256.2571,099.20940.547 12-2027120.00010.60.0000.00031.323.000216.8981,316.107128.388 12-2028120.00010.60.0000.00028.487.000186.3971,502.504197.007 12-2029120.00010.60.0000.00026.026.000159.9251,662.429250.519 12-2030120.00010.60.0000.00023.943.000137.5161,799.945292.354 12-2031120.00010.60.0000.00022.029.000116.9291,916.874324.697 12-2032120.00010.60.0000.00020.321.00098.5592,015.433349.484 12-2033120.00010.60.0000.00018.643.00080.5132,095.946367.890 12-2034120.00010.60.0000.00017.152.00064.4832,160.429381.295 12-2035120.00010.60.0000.00015.781.00049.7342,210.163390.697 12-2036120.00010.60.0000.00014.558.00036.5742,246.738396.986 S Tot2,077.667 0.0000.000866.9405,000.0002,246.7382,246.738396.986 After319.569 0.0000.00033.335.00038.9722,285.709402.834 Total2,397.235 0.0000.000900.2755,000.0002,285.7092,285.709402.834 Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeinDef InitialFinalUnits Final 5.001,118.504 Oil Rate22,812.453.bbls/mo 96.3%1.200.0% 12,265.16,000.$/w/mo Expense62.500062.5000 8.00650.354 Gas Rate68,437.1,359.Mcf/mo 0.0%0.000.0% Revenue 10.00402.834 GOR3,000.3,000.scf/bbl Oil50.000050.0000 12.00195.272 NGL Rate3,245.95.bbls/mo Gas50.000050.0000 15.00-57.039 NGL Yield47.470.6bbl/MMcf 20.00-362.622 Gas Shrinkage52.631.9% Oil Severance7.17.1% Gas Severance7.97.9% NGL Severance7.97.9% Ad Valorem63.6 % Start Date: 09/2019 4 Months in year ‘19 20.003 Year Life (09/2039)THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.ASN 480DEFAULT 1/10/201810:34:19TEXAS REGISTERED ENGINEERING FIRM F-693. OIL PUD Table 15 Cawley, Gillespie & Associates, Inc.   Table 16Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Undeveloped ReservesLILIS ENERGY, INC. -- TIGER #2HPHANTOM (WOLFCAMP B) FIELD -- WINKLER COUNTY, TEXAS(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGLEndProductionProductionProductionProductionSalesProductionPricePricePriceMo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL12-2018.0.0.0.000.000.000.000.000.000 12-2019105.0315.121.774.682152.35115.45947.7462.6198.728 12-202064.9194.613.446.12894.1009.54847.7462.6198.728 12-202141.2123.78.529.31059.7926.06747.7462.6198.728 12-202230.992.86.421.98944.8584.55247.7462.6198.728 12-202325.075.05.217.77936.2703.68047.7462.6198.728 12-202421.263.54.415.05530.7113.11647.7462.6198.728 12-202518.455.13.813.04726.6152.70147.7462.6198.728 12-202616.348.83.411.57323.6082.39647.7462.6198.728 12-202714.744.03.010.42221.2602.15747.7462.6198.728 12-202813.440.22.89.52119.4221.97147.7462.6198.728 12-202912.336.82.58.72117.7911.80547.7462.6198.728 12-203011.333.92.38.02416.3691.66147.7462.6198.728 12-203110.431.22.17.38215.0601.52847.7462.6198.728 12-20329.628.72.06.81013.8921.41047.7462.6198.728 12-20338.826.41.86.24812.7451.29347.7462.6198.728 12-20348.124.31.75.74811.7261.19047.7462.6198.728 12-20357.422.31.55.28910.7891.09547.7462.6198.728 12-20366.920.61.44.8799.9521.01047.7462.6198.728 S Tot425.61,276.988.1302.605617.31462.63947.7462.6198.728 After18.455.23.813.07426.6702.70647.7462.6198.728 Total444.01,332.191.9315.679643.98465.34547.7462.6198.728 Cum.0.0.0 Ult444.01,332.191.9 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6Mo-YearM$M$M$M$M$M$M$M$ 12-2018.000.000.0000.0000.000.000.000.000.000 12-20193,565.781398.990134.9220.0000.0004,099.693204.783102.4923.826 12-20202,202.417246.43783.3350.0000.0002,532.189126.48563.3055.189 12-20211,399.431156.58852.9520.0000.0001,608.97180.36940.2246.601 12-20221,049.907117.47839.7260.0000.0001,207.11160.29630.1787.890 12-2023848.90394.98732.1210.0000.000976.01048.75224.4009.113 12-2024718.79780.42927.1980.0000.000826.42441.28120.66110.268 12-2025622.93469.70323.5710.0000.000716.20735.77517.90511.429 12-2026552.55061.82720.9070.0000.000635.28531.73315.88212.537 12-2027497.59455.67818.8280.0000.000572.10028.57714.30313.620 12-2028454.58250.86517.2000.0000.000522.64826.10713.06614.651 12-2029416.39646.59215.7560.0000.000478.74323.91411.96915.745 12-2030383.10642.86714.4960.0000.000440.46922.00211.01216.876 12-2031352.47839.44013.3370.0000.000405.25520.24310.13118.105 12-2032325.15036.38212.3030.0000.000373.83518.6739.34619.397 12-2033298.30333.37811.2870.0000.000342.96817.1328.57420.898 12-2034274.45430.71010.3850.0000.000315.54915.7627.88922.477 12-2035252.51228.2559.5550.0000.000290.32214.5027.25824.193 12-2036232.93526.0648.8140.0000.000267.81313.3776.69525.997 S Tot14,448.2301,616.671546.6910.0000.00016,611.592829.762415.2909.376 After624.22069.84723.6190.0000.000717.68635.84917.94230.423 Total15,072.4511,686.517570.3110.0000.00017,329.279865.611433.23210.248 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash FlowEndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. %Mo-YearM$CountM$M$M$M$M$M$M$12-2018.00000.00.0000.0000.000.000.000.000.000 12-2019120.89310.90.0000.000300.3906,974.597-3,603.463-3,603.463-3,371.682 12-2020167.39010.90.0000.000185.537.0001,989.472-1,613.990-1,795.678 12-2021167.39010.90.0000.000117.892.0001,203.095-410.895-931.007 12-2022167.39010.90.0000.00088.447.000860.800449.905-368.996 12-2023167.39010.90.0000.00071.514.000663.9541,113.85924.941 12-2024167.39010.90.0000.00060.553.000536.5391,650.398314.249 12-2025167.39010.90.0000.00052.478.000442.6592,093.058531.176 12-2026167.39010.90.0000.00046.548.000373.7312,466.789697.661 12-2027167.39010.90.0000.00041.919.000319.9122,786.701827.211 12-2028167.39010.90.0000.00038.295.000277.7893,064.490929.467 12-2029167.39010.90.0000.00035.078.000240.3933,304.8831,009.901 12-2030167.39010.90.0000.00032.274.000207.7913,512.6741,073.114 12-2031167.39010.90.0000.00029.694.000177.7973,690.4711,122.291 12-2032167.39010.90.0000.00027.391.000151.0343,841.5051,160.272 12-2033167.39010.90.0000.00025.130.000124.7433,966.2481,188.788 12-2034167.39010.90.0000.00023.121.000101.3874,067.6351,209.863 12-2035167.39010.90.0000.00021.272.00079.8994,147.5341,224.965 12-2036167.39010.90.0000.00019.623.00060.7274,208.2611,235.405 S Tot2,966.529 0.0000.0001,217.1556,974.5974,208.2614,208.2611,235.405 After533.910 0.0000.00052.586.00077.3994,285.6591,246.873 Total3,500.439 0.0000.0001,269.7416,974.5974,285.6594,285.6591,246.873  Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeinDef InitialFinalUnits Final 5.002,418.995 Oil Rate22,812.419.bbls/mo 96.3%1.200.0% 10,666.15,243.$/w/mo Expense87.182587.1825 8.001,656.162 Gas Rate68,437.1,258.Mcf/mo 0.0%0.000.0% Revenue 10.001,246.873 GOR3,000.3,000.scf/bbl Oil71.094071.0940 12.00899.079 NGL Rate2,855.83.bbls/mo Gas71.094071.0940 15.00468.477 NGL Yield41.766.1bbl/MMcf 20.00-70.836 Gas Shrinkage58.331.8% Oil Severance4.64.6% Gas Severance7.57.5% NGL Severance7.57.5% Ad Valorem39.2 % Start Date: 04/2019 9 Months in year ‘19 20.940 Year Life (03/2040)THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.ASN 485DEFAULT 1/10/201810:34:19TEXAS REGISTERED ENGINEERING FIRM F-693. OIL PUD Table 16 Cawley, Gillespie & Associates, Inc.   Table 17Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Undeveloped ReservesLILIS ENERGY, INC. -- TIGER 1 PUD-2PHANTOM (WOLFCAMP B) FIELD -- WINKLER COUNTY, TEXAS (1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGL EndProductionProductionProductionProductionSalesProductionPricePricePrice Mo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL 12-2018.0.0.0.000.000.000.000.000.000 12-201992.1276.419.165.509133.63813.56047.7462.6198.728 12-202070.8212.514.750.367102.74910.42647.7462.6198.728 12-202143.3129.89.030.77062.7706.36947.7462.6198.728 12-202232.096.06.622.74746.4054.70947.7462.6198.728 12-202325.777.05.318.24937.2283.77847.7462.6198.728 12-202421.664.94.515.37731.3693.18347.7462.6198.728 12-202518.756.03.913.28227.0952.74947.7462.6198.728 12-202616.549.63.411.75323.9752.43347.7462.6198.728 12-202714.944.63.110.56421.5512.18747.7462.6198.728 12-202813.640.72.89.63719.6601.99547.7462.6198.728 12-202912.437.22.68.82117.9951.82647.7462.6198.728 12-203011.434.22.48.11616.5561.68047.7462.6198.728 12-203110.531.52.27.46715.2331.54647.7462.6198.728 12-20329.729.12.06.88814.0521.42647.7462.6198.728 12-20338.926.71.86.31912.8921.30847.7462.6198.728 12-20348.224.51.75.81411.8611.20447.7462.6198.728 12-20357.522.61.65.34910.9131.10747.7462.6198.728 12-20366.920.81.44.93510.0671.02147.7462.6198.728 S Tot424.71,274.287.9301.965616.00862.50747.7462.6198.728 After19.357.94.013.71627.9812.83947.7462.6198.728 Total444.01,332.191.9315.681643.99065.34647.7462.6198.728 Cum.0.0.0 Ult444.01,332.191.9 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6 Mo-YearM$M$M$M$M$M$M$M$ 12-2018.000.000.0000.0000.000.000.000.000.000 12-20193,127.794349.981118.3490.0000.0003,596.125179.62989.9033.743 12-20202,404.836269.08790.9940.0000.0002,764.916138.11069.1234.982 12-20211,469.132164.38755.5890.0000.0001,689.10884.37242.2286.417 12-20221,086.105121.52941.0960.0000.0001,248.73062.37531.2187.718 12-2023871.32897.49632.9690.0000.0001,001.79450.04025.0458.948 12-2024734.19582.15227.7800.0000.000844.12742.16521.10310.110 12-2025634.15970.95923.9950.0000.000729.11336.42018.22811.275 12-2026561.14662.78921.2330.0000.000645.16832.22716.12912.387 12-2027504.40556.44019.0860.0000.000579.93028.96814.49813.473 12-2028460.13651.48617.4110.0000.000529.03326.42613.22614.507 12-2029421.17847.12715.9370.0000.000484.24224.18812.10615.597 12-2030387.50443.35914.6620.0000.000445.52622.25411.13816.715 12-2031356.52439.89313.4900.0000.000409.90720.47510.24817.931 12-2032328.88236.80012.4440.0000.000378.12718.8889.45319.208 12-2033301.72733.76111.4170.0000.000346.90617.3288.67320.691 12-2034277.60531.06210.5040.0000.000319.17115.9437.97922.252 12-2035255.41128.5799.6640.0000.000293.65414.6687.34123.949 12-2036235.60926.3638.9150.0000.000270.88713.5316.77225.733 S Tot14,417.6761,613.252545.5350.0000.00016,576.463828.007414.4129.339 After654.90673.28024.7800.0000.000752.96637.61118.82430.250 Total15,072.5821,686.532570.3160.0000.00017,329.430865.618433.23610.248 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash Flow EndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. % Mo-YearM$CountM$M$M$M$M$M$M$ 12-2018.00000.00.0000.0000.000.000.000.000.000 12-201998.09410.90.0000.000263.4936,974.597-4,009.592-4,009.592-3,661.506 12-2020167.39010.90.0000.000202.589.0002,187.704-1,821.888-1,927.585 12-2021167.39010.90.0000.000123.763.0001,271.355-550.533-1,013.706 12-2022167.39010.90.0000.00091.496.000896.250345.717-428.504 12-2023167.39010.90.0000.00073.403.000685.9151,031.632-21.518 12-2024167.39010.90.0000.00061.850.000551.6191,583.251275.931 12-2025167.39010.90.0000.00053.423.000453.6522,036.903498.250 12-2026167.39010.90.0000.00047.272.000382.1492,419.052668.488 12-2027167.39010.90.0000.00042.492.000326.5822,745.633800.741 12-2028167.39010.90.0000.00038.763.000283.2283,028.862904.999 12-2029167.39010.90.0000.00035.481.000245.0763,273.938987.000 12-2030167.39010.90.0000.00032.644.000212.0983,486.0361,051.523 12-2031167.39010.90.0000.00030.034.000181.7593,667.7951,101.795 12-2032167.39010.90.0000.00027.706.000154.6893,822.4851,140.695 12-2033167.39010.90.0000.00025.418.000128.0963,950.5811,169.978 12-2034167.39010.90.0000.00023.386.000104.4734,055.0541,191.693 12-2035167.39010.90.0000.00021.516.00082.7384,137.7921,207.331 12-2036167.39010.90.0000.00019.848.00063.3454,201.1371,218.220 S Tot2,943.730 0.0000.0001,214.5816,974.5974,201.1374,201.1371,218.220 After556.650 0.0000.00055.171.00084.7104,285.8471,230.720 Total3,500.380 0.0000.0001,269.7526,974.5974,285.8474,285.8471,230.720 Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinal Units DeinDef InitialFinalUnits Final 5.002,402.951 Oil Rate22,812.419.bbls/mo 96.3%1.200.0% 515.15,999.$/w/mo Expense87.182587.1825 8.001,638.830 Gas Rate68,437.1,258.Mcf/mo 0.0%0.000.0% Revenue 10.001,230.720 GOR3,000.3,000.scf/bbl Oil71.094071.0940 12.00885.237 NGL Rate155.89.bbls/mo Gas71.094071.0940 15.00459.586 NGL Yield2.371.0bbl/MMcf 20.00-69.117 Gas Shrinkage97.831.5% Oil Severance4.64.6% Gas Severance7.57.5% NGL Severance7.57.5% Ad Valorem42.1 % Start Date: 05/2019 8 Months in year ‘19 20.994 Year Life (04/2040)THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.TEXAS REGISTERED ENGINEERING FIRM F-693.ASN 489DEFAULT 1/10/2018 10:34:19 OIL PUDTable 17Cawley, Gillespie & Associates, Inc.   Table 18Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Undeveloped ReservesLILIS ENERGY, INC. -- TIGER PUD-3PHANTOM (WOLFCAMP B) FIELD -- WINKLER COUNTY, TEXAS (1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGL EndProductionProductionProductionProductionSalesProductionPricePricePrice Mo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL 12-2018.0.0.0.000.000.000.000.000.000 12-2019.0.0.0.000.000.000.000.000.000 12-202091.6274.819.010.99122.4212.27547.7462.6198.728 12-202171.0212.914.78.51617.3731.76347.7462.6198.728 12-202243.4130.29.05.20910.6271.07847.7462.6198.728 12-202332.196.26.63.8487.849.79647.7462.6198.728 12-202425.877.35.33.0936.309.64047.7462.6198.728 12-202521.664.84.52.5915.286.53647.7462.6198.728 12-202618.756.13.92.2444.578.46547.7462.6198.728 12-202716.549.63.41.9864.051.41147.7462.6198.728 12-202814.944.73.11.7893.650.37047.7462.6198.728 12-202913.540.62.81.6233.311.33647.7462.6198.728 12-203012.437.22.61.4903.040.30847.7462.6198.728 12-203111.434.32.41.3712.796.28447.7462.6198.728 12-203210.531.62.21.2652.580.26247.7462.6198.728 12-20339.729.02.01.1602.367.24047.7462.6198.728 12-20348.926.71.81.0672.177.22147.7462.6198.728 12-20358.224.61.7.9822.003.20347.7462.6198.728 12-20367.522.61.6.9061.848.18847.7462.6198.728 S Tot417.81,253.386.550.131102.26710.37747.7462.6198.728 After20.561.64.22.4625.023.51047.7462.6198.728 Total438.31,314.890.752.593107.28910.88747.7462.6198.728 Cum.0.0.0 Ult438.31,314.890.7 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6 Mo-YearM$M$M$M$M$M$M$M$ 12-2018.000.000.0000.0000.000.000.000.000.000 12-2019.000.000.0000.0000.000.000.000.000.000 12-2020524.75958.71719.8560.0000.000603.33230.13715.0834.066 12-2021406.61145.49715.3850.0000.000467.49323.35211.6875.412 12-2022248.72427.8319.4110.0000.000285.96614.2847.1496.965 12-2023183.70620.5566.9510.0000.000211.21310.5505.2808.381 12-2024147.67316.5245.5880.0000.000169.7858.4814.2459.702 12-2025123.71813.8434.6810.0000.000142.2427.1053.55611.006 12-2026107.15611.9904.0550.0000.000123.2016.1543.08012.249 12-202794.80510.6083.5870.0000.000109.0005.4452.72513.458 12-202885.4319.5593.2330.0000.00098.2234.9062.45614.609 12-202977.5028.6722.9320.0000.00089.1064.4512.22815.801 12-203071.1407.9602.6920.0000.00081.7924.0862.04516.949 12-203165.4527.3242.4770.0000.00075.2523.7591.88118.164 12-203260.3776.7562.2850.0000.00069.4183.4671.73519.441 12-203355.3926.1982.0960.0000.00063.6863.1811.59220.924 12-203450.9645.7031.9280.0000.00058.5952.9271.46522.484 12-203546.8895.2471.7740.0000.00053.9102.6931.34824.180 12-203643.2544.8401.6370.0000.00049.7302.4841.24325.963 S Tot2,393.552267.82490.5670.0000.0002,751.943137.46268.7999.856 After117.55913.1544.4480.0000.000135.1616.7513.37930.387 Total2,511.110280.97895.0150.0000.0002,887.104144.21372.17810.818 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash Flow EndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. % Mo-YearM$CountM$M$M$M$M$M$M$ 12-2018.00000.00.0000.0000.000.000.000.000.000 12-2019.00000.00.0000.0000.000.000.000.000.000 12-202017.83510.20.0000.00048.0661,280.000-787.788-787.788-650.673 12-202130.72010.20.0000.00037.244.000364.491-423.298-388.055 12-202230.72010.20.0000.00022.782.000211.030-212.267-250.137 12-202330.72010.20.0000.00016.827.000147.835-64.432-162.374 12-202430.72010.20.0000.00013.526.000112.81348.381-101.522 12-202530.72010.20.0000.00011.332.00089.529137.910-57.636 12-202630.72010.20.0000.0009.815.00073.432211.342-24.917 12-202730.72010.20.0000.0008.684.00061.427272.769-.038 12-202830.72010.20.0000.0007.825.00052.316325.08519.222 12-202930.72010.20.0000.0007.099.00044.609369.69434.149 12-203030.72010.20.0000.0006.516.00038.425408.11945.839 12-203130.72010.20.0000.0005.995.00032.897441.01654.938 12-203230.72010.20.0000.0005.530.00027.965468.98061.970 12-203330.72010.20.0000.0005.074.00023.119492.09967.255 12-203430.72010.20.0000.0004.668.00018.815510.91471.166 12-203530.72010.20.0000.0004.295.00014.855525.76973.973 12-203630.72010.20.0000.0003.962.00011.321537.09075.920 S Tot509.355 0.0000.000219.2381,280.000537.090537.09075.920 After99.554 0.0000.00010.768.00014.709551.79878.095 Total608.909 0.0000.000230.0061,280.000551.798551.79878.095 Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinal Units DeinDef InitialFinalUnits Final 5.00252.484 Oil Rate22,812.459.bbls/mo 96.3%1.200.0% 15,462.15,243.$/w/mo Expense16.000016.0000 8.00137.306 Gas Rate68,437.1,378.Mcf/mo 0.0%0.000.0% Revenue 10.0078.095 GOR3,000.3,000.scf/bbl Oil12.000012.0000 12.0029.608 NGL Rate4,003.91.bbls/mo Gas12.000012.0000 15.00-27.504 NGL Yield58.566.4bbl/MMcf 20.00-92.916 Gas Shrinkage41.531.7% Oil Severance4.64.6% Gas Severance7.57.5% NGL Severance7.57.5% Ad Valorem7.3 % Start Date: 06/2020 7 Months in year ‘20 19.825 Year Life (03/2040)THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.TEXAS REGISTERED ENGINEERING FIRM F-693.ASN 495DEFAULT 1/10/2018 10:34:19 OIL PUDTable 18Cawley, Gillespie & Associates, Inc.   Table 19Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Undeveloped ReservesLILIS ENERGY, INC. -- WILD HOG 2HPHANTOM (WOLFCAMP B) FIELD -- LEA COUNTY, NEW MEXICO(1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGL EndProductionProductionProductionProductionSalesProductionPricePricePrice Mo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL 12-201892.4277.219.146.20794.2639.56547.7462.6198.728 12-201970.6211.714.635.28571.9827.30447.7462.6198.728 12-202043.4130.19.021.69044.2484.49047.7462.6198.728 12-202132.095.96.615.98732.6143.30947.7462.6198.728 12-202225.777.05.312.82826.1692.65547.7462.6198.728 12-202321.664.74.510.78321.9962.23247.7462.6198.728 12-202418.756.23.99.36519.1051.93947.7462.6198.728 12-202516.549.63.48.26316.8571.71047.7462.6198.728 12-202614.944.63.17.42815.1531.53847.7462.6198.728 12-202713.540.62.86.75813.7871.39947.7462.6198.728 12-202812.437.32.66.22012.6891.28847.7462.6198.728 12-202911.434.22.45.70711.6411.18147.7462.6198.728 12-203010.531.52.25.25010.7111.08747.7462.6198.728 12-20319.729.02.04.8319.8541.00047.7462.6198.728 12-20328.926.71.84.4569.090.92247.7462.6198.728 12-20338.224.51.74.0888.340.84647.7462.6198.728 12-20347.522.61.63.7617.673.77947.7462.6198.728 12-20356.920.81.43.4617.060.71647.7462.6198.728 12-20366.419.21.33.1926.512.66147.7462.6198.728 S Tot431.11,293.489.2215.561439.74444.62147.7462.6198.728 After8.024.11.74.0198.198.83247.7462.6198.728 Total439.21,317.590.9219.579447.94245.45347.7462.6198.728 Cum.0.0.0 Ult439.21,317.590.9 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6 Mo-YearM$M$M$M$M$M$M$M$ 12-20182,206.227246.86483.4790.0000.0002,536.569182.651126.8283.817 12-20191,684.748188.51363.7470.0000.0001,937.009139.47896.8505.087 12-20201,035.613115.87939.1850.0000.0001,190.67785.73759.5346.533 12-2021763.32385.41128.8830.0000.000877.61763.19543.8817.871 12-2022612.47668.53223.1750.0000.000704.18350.70635.2099.125 12-2023514.82757.60619.4800.0000.000591.91442.62229.59610.328 12-2024447.14650.03316.9190.0000.000514.09837.01925.70511.470 12-2025394.52844.14514.9280.0000.000453.60132.66222.68012.629 12-2026354.64839.68313.4190.0000.000407.75029.36120.38813.737 12-2027322.68636.10712.2100.0000.000371.00326.71518.55014.822 12-2028296.99033.23111.2380.0000.000341.45924.58717.07315.864 12-2029272.46730.48710.3100.0000.000313.26422.55715.66317.041 12-2030250.68428.0509.4850.0000.000288.21920.75414.41118.281 12-2031230.64225.8088.7270.0000.000265.17719.09513.25919.627 12-2032212.76123.8078.0500.0000.000244.61817.61412.23121.043 12-2033195.19321.8417.3860.0000.000224.42016.16011.22122.687 12-2034179.58820.0956.7950.0000.000206.47814.86810.32424.417 12-2035165.23118.4886.2520.0000.000189.97113.6799.49926.297 12-2036152.42017.0555.7670.0000.000175.24212.6198.76228.273 S Tot10,292.1991,151.636389.4360.0000.00011,833.270852.078591.6649.798 After191.87721.4707.2600.0000.000220.60715.88511.03030.928 Total10,484.0751,173.106396.6960.0000.00012,053.877867.963602.69410.185 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash Flow EndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. % Mo-YearM$CountM$M$M$M$M$M$M$ 12-201870.64510.60.0000.000189.4505,000.000-3,033.005-3,033.005-3,037.101 12-2019120.00010.60.0000.000144.671.0001,436.010-1,596.995-1,785.057 12-2020120.00010.60.0000.00088.929.000836.478-760.518-1,123.573 12-2021120.00010.60.0000.00065.547.000584.995-175.523-703.421 12-2022120.00010.60.0000.00052.594.000445.674270.151-412.547 12-2023120.00010.60.0000.00044.209.000355.487625.638-201.674 12-2024120.00010.60.0000.00038.397.000292.978918.616-43.717 12-2025120.00010.60.0000.00033.878.000244.3801,162.99676.032 12-2026120.00010.60.0000.00030.454.000207.5481,370.544168.482 12-2027120.00010.60.0000.00027.709.000178.0281,548.573240.573 12-2028120.00010.60.0000.00025.503.000154.2961,702.869297.373 12-2029120.00010.60.0000.00023.397.000131.6471,834.515341.425 12-2030120.00010.60.0000.00021.526.000111.5281,946.044375.358 12-2031120.00010.60.0000.00019.805.00093.0182,039.062401.090 12-2032120.00010.60.0000.00018.270.00076.5032,115.564420.333 12-2033120.00010.60.0000.00016.761.00060.2782,175.842434.117 12-2034120.00010.60.0000.00015.421.00045.8652,221.707443.654 12-2035120.00010.60.0000.00014.188.00032.6052,254.312449.821 12-2036120.00010.60.0000.00013.088.00020.7732,275.085453.399 S Tot2,230.645 0.0000.000883.7985,000.0002,275.0852,275.085453.399 After166.797 0.0000.00016.477.00010.4172,285.502455.020 Total2,397.443 0.0000.000900.2755,000.0002,285.5022,285.502455.020 Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeinDef InitialFinalUnits Final 5.001,190.352 Oil Rate22,812.453.bbls/mo 96.3%1.200.0% 1,032.15,769.$/w/mo Expense62.500062.5000 8.00717.524 Gas Rate68,437.1,359.Mcf/mo 0.0%0.000.0% Revenue 10.00455.020 GOR3,000.3,000.scf/bbl Oil50.000050.0000 12.00225.767 NGL Rate307.93.bbls/mo Gas50.000050.0000 15.00-68.034 NGL Yield4.568.6bbl/MMcf 20.00-457.430 Gas Shrinkage95.731.6% Oil Severance7.17.1% Gas Severance7.97.9% NGL Severance7.97.9% Ad Valorem61.9 % Start Date: 05/2018 8 Months in year ‘18 20.061 Year Life (05/2038)THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.TEXAS REGISTERED ENGINEERING FIRM F-693.ASN 481DEFAULT 1/10/2018 10:34:19 OIL PUDTable 19Cawley, Gillespie & Associates, Inc.   Table 20Reserve Estimates and Economic Forecasts as of December 31, 2017Lilis Energy, Inc. InterestsProved Undeveloped ReservesLILIS ENERGY, INC. -- WILD HOG 3HPHANTOM (WOLFCAMP B) FIELD -- LEA COUNTY, NEW MEXICO (1)(2)(3)(4)(5)(6)(7)(8)(9)(10) Gross OilGross GasGross NGLNet OilNet GasNet NGLAvg OilAvg GasAvg NGL EndProductionProductionProductionProductionSalesProductionPricePricePrice Mo-YearMBBLSMMCFMBBLSMBBLSMMCFMBBLS$/BBL$/MCF$/BBL 12-201876.4229.215.838.19277.9127.90647.7462.6198.728 12-201978.6235.816.339.30180.1738.13547.7462.6198.728 12-202045.9137.69.522.93846.7954.74847.7462.6198.728 12-202133.299.76.916.61033.8843.43847.7462.6198.728 12-202226.479.25.513.20626.9412.73447.7462.6198.728 12-202322.166.24.611.03922.5202.28547.7462.6198.728 12-202419.157.34.09.55219.4851.97747.7462.6198.728 12-202516.850.43.58.40517.1451.74047.7462.6198.728 12-202615.145.23.17.54015.3811.56147.7462.6198.728 12-202713.741.12.86.84913.9721.41847.7462.6198.728 12-202812.637.82.66.29812.8471.30447.7462.6198.728 12-202911.634.72.45.77711.7861.19647.7462.6198.728 12-203010.631.92.25.31510.8441.10047.7462.6198.728 12-20319.829.32.04.8919.9771.01247.7462.6198.728 12-20329.027.11.94.5119.203.93447.7462.6198.728 12-20338.324.81.74.1398.443.85747.7462.6198.728 12-20347.622.81.63.8087.768.78847.7462.6198.728 12-20357.021.01.53.5047.147.72547.7462.6198.728 12-20366.519.41.33.2326.593.66947.7462.6198.728 S Tot430.21,290.689.1215.106438.81744.52747.7462.6198.728 After8.926.81.94.4739.125.92647.7462.6198.728 Total439.21,317.590.9219.579447.94245.45347.7462.6198.728 Cum.0.0.0 Ult439.21,317.590.9 (11)(12)(13)(14)(15)(16)(17)(18)(19)(20) OilGasNGLHedgeOtherTotalProductionAd Valorem EndRevenueRevenueRevenueRevenueRevenueRevenueTaxesTaxes$/BOE6 Mo-YearM$M$M$M$M$M$M$M$ 12-20181,823.540204.04368.9990.0000.0002,096.582150.969104.8293.720 12-20191,876.460209.96571.0010.0000.0002,157.426155.350107.8714.851 12-20201,095.226122.54941.4410.0000.0001,259.21690.67262.9616.328 12-2021793.06088.73930.0080.0000.000911.80665.65645.5907.680 12-2022630.55870.55623.8590.0000.000724.97352.20336.2498.943 12-2023527.07458.97619.9430.0000.000605.99443.63630.30010.153 12-2024456.05451.03017.2560.0000.000524.34037.75626.21711.301 12-2025401.29044.90215.1840.0000.000461.37633.22223.06912.463 12-2026359.98340.28013.6210.0000.000413.88429.80320.69413.574 12-2027327.01136.59112.3730.0000.000375.97527.07318.79914.663 12-2028300.68433.64511.3770.0000.000345.70624.89317.28515.703 12-2029275.84730.86610.4370.0000.000317.15022.83715.85716.867 12-2030253.79328.3989.6030.0000.000291.79421.01114.59018.091 12-2031233.50326.1288.8350.0000.000268.46619.33113.42319.421 12-2032215.40024.1028.1500.0000.000247.65217.83312.38320.820 12-2033197.61522.1127.4770.0000.000227.20416.36011.36022.443 12-2034181.81620.3446.8800.0000.000209.03915.05210.45224.152 12-2035167.28018.7186.3300.0000.000192.32713.8499.61626.009 12-2036154.31117.2665.8390.0000.000177.41612.7758.87127.961 S Tot10,270.5041,149.208388.6150.0000.00011,808.327850.282590.4169.757 After213.57223.8978.0810.0000.000245.55017.68112.27830.737 Total10,484.0761,173.106396.6960.0000.00012,053.877867.963602.69410.185 (21)(22)(23)(24)(25)(26)(27)(28)(29)(30)(31) OperatingWellsWorkover3rd PartyOther Future NetCumulativeCum.Cash Flow EndExpenseGrossNetExpenseCOPASDeductionsInvestmentCash FlowCash FlowDisc.@ 10. % Mo-YearM$CountM$M$M$M$M$M$M$ 12-201852.90310.60.0000.000156.5895,000.000-3,368.708-3,368.708-3,297.690 12-2019120.00010.60.0000.000161.133.0001,613.072-1,755.636-1,890.289 12-2020120.00010.60.0000.00094.048.000891.535-864.100-1,185.126 12-2021120.00010.60.0000.00068.101.000612.459-251.642-745.207 12-2022120.00010.60.0000.00054.146.000462.375210.733-443.416 12-2023120.00010.60.0000.00045.260.000366.798577.532-225.826 12-2024120.00010.60.0000.00039.162.000301.205878.737-63.429 12-2025120.00010.60.0000.00034.459.000250.6261,129.36259.382 12-2026120.00010.60.0000.00030.912.000212.4751,341.837154.029 12-2027120.00010.60.0000.00028.081.000182.0231,523.860227.738 12-2028120.00010.60.0000.00025.820.000157.7081,681.568285.793 12-2029120.00010.60.0000.00023.687.000134.7681,816.336330.890 12-2030120.00010.60.0000.00021.793.000114.4001,930.736365.696 12-2031120.00010.60.0000.00020.051.00095.6602,026.396392.158 12-2032120.00010.60.0000.00018.497.00078.9402,105.336412.014 12-2033120.00010.60.0000.00016.969.00062.5142,167.850426.309 12-2034120.00010.60.0000.00015.613.00047.9232,215.773436.274 12-2035120.00010.60.0000.00014.364.00034.4982,250.271442.798 12-2036120.00010.60.0000.00013.251.00022.5192,272.790446.675 S Tot2,212.903 0.0000.000881.9355,000.0002,272.7902,272.790446.675 After184.396 0.0000.00018.340.00012.8562,285.646448.668 Total2,397.299 0.0000.000900.2755,000.0002,285.6462,285.646448.668 Evaluation Parameters (Gross) Expenses (Gross) Percent Interests PercentCum. Disc. InitialFinalUnits DeinDef InitialFinalUnits Final 5.001,181.848 Oil Rate22,812.453.bbls/mo 96.3%1.200.0% 4,644.15,769.$/w/mo Expense62.500062.5000 8.00709.432 Gas Rate68,437.1,359.Mcf/mo 0.0%0.000.0% Revenue 10.00448.668 GOR3,000.3,000.scf/bbl Oil50.000050.0000 12.00222.022 NGL Rate1,342.93.bbls/mo Gas50.000050.0000 15.00-66.645 NGL Yield19.668.5bbl/MMcf 20.00-445.275 Gas Shrinkage81.031.6% Oil Severance7.17.1% Gas Severance7.97.9% NGL Severance7.97.9% Ad Valorem61.8 % Start Date: 07/20186 Months in year ‘1820.042 Year Life (07/2038) THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.TEXAS REGISTERED ENGINEERING FIRM F-693.ASN 483DEFAULT 1/10/2018 10:34:19 OIL PUDTable 20Cawley, Gillespie & Associates, Inc.  APPENDIXExplanatory Comments for Summary Tables HEADINGS Table IDescription of Table InformationIdentity of Interest EvaluatedProperty Description – LocationReserve Classification and Development StatusEffective Date of Evaluation FORECAST (Columns) (1) (11) (21)Calendar or Fiscal years/months commencing on effective date.(2) (3) (4)Gross Production (8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of cubic feet(MMcf) of gas at standard conditions. Total future production, cumulative production to effective date and ultimate recovery at the effective date are shownfollowing the annual/monthly forecasts.(5) (6) (7)Net Production accruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take intoaccount changes in interest and gas shrinkage.(8)Average (volume weighted) gross liquid price per barrel before deducting production-severance taxes.(9)Average (volume weighted) gross gas price per Mcf before deducting production-severance taxes.(10)Average (volume weighted) gross NGL price per barrel before deducting production-severance taxes.(12)Revenue derived from oil sales -- column (5) times column (8).(13)Revenue derived from gas sales -- column (6) times column (9).(14)Revenue derived from NGL sales -- column (7) times column (10).(15)Revenue derived from hedge positions.(16)Revenue derived from other sources not included in column (12) through column (15); may include revenue from electrical sales, pipeline gas transportation,3rd party saltwater disposal, etc.(17)Total Revenue – sum of column (12) through column (16).(18)Production-Severance taxes deducted from gross oil, gas and NGL revenue.(19)Ad Valorem taxes.(20)$/BOE6 – is the total of column (22), column (25), column (26), and column (27) divided by Barrels of Oil Equivalent (“BOE”). BOE is net oil productioncolumn (5) plus net gas production column (6) converted to oil at six Mcf gas per one bbl oil plus net NGL production column (7) converted to oil at one bblNGL per 0.65 bbls of oil.(22)Operating Expenses are direct operating expenses to the evaluated working interest and may include combined fixed rate administrative overhead charges foroperated oil and gas producers known as COPAS.(23)Average gross wells.(24)Average net wells are gross wells times working interest.(25)Workover Expenses are non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump repair.(26)3rd Party COPAS are combined fixed rate administrative overhead charges for non-operated oil and gas producers.(27)Other Deductions may include compression-gathering expenses, transportation costs and water disposal costs.(28)Investments, if any, include re-completions, future drilling costs, pumping units, etc. and may include either tangible or intangible or both, and the costs forplugging and the salvage value of equipment at abandonment may be shown as negative investments at end of life.(29) (30)Future Net Cash Flow is column (17) less the total of column (18), column (19), column (22), column (25), column (26), column (27) and column (28). Thedata in column (29) are accumulated in column (30). Federal income taxes have not been considered.(31)Cumulative Discounted Cash Flow is calculated by discounting monthly cash flows at the specified annual rates. MISCELLANEOUSDCF Profile•The cumulative cash flow discounted at six different interest rates are shown at the bottom of columns (30-31). Interest has been compounded monthly.The DCF’s for the “Without Hedge” case may be shown to the left of the main DCF profile.Life•The economic life of the appraised property is noted in the lower right-hand corner of the table.Footnotes•Comments regarding the evaluation may be shown in the lower left-hand footnotes.Price Deck•A table of oil and gas prices, price caps and escalation rates may be shown in the lower middle footnotes.Differentials•Total annual price adjustments may be shown in gray font to the left of column (8), column (9) and column (10). Appendix Cawley, Gillespie & Associates, Inc.Page 1  APPENDIXMethods Employed in the Estimation of Reserves The four methods customarily employed in the estimation of reserves are (1) production performance, (2) material balance, (3) volumetric and (4) analogy. Mostestimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data available and the characteristics of the reservoirs. Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the quality, quantity and types of informationavailable on individual properties. Operators are generally required by regulatory authorities to file monthly production reports and may be required to measure and reportperiodically such data as well pressures, gas-oil ratios, well tests, etc. As a general rule, an operator has complete discretion in obtaining and/or making available geological andengineering data. The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in significant differences in theaccuracy and reliability of estimates. A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows: Production performance. This method employs graphical analyses of production data on the premise that all factors which have controlled the performance to date willcontinue to control and that historical trends can be extrapolated to predict future performance. The only information required is production history. Capacity production can usuallybe analyzed from graphs of rates versus time or cumulative production. This procedure is referred to as "decline curve" analysis. Both capacity and restricted production can, insome cases, be analyzed from graphs of producing rate relationships of the various production components. Reserve estimates obtained by this method are generally considered tohave a relatively high degree of accuracy with the degree of accuracy increasing as production history accumulates. Material balance. This method employs the analysis of the relationship of production and pressure performance on the premise that the reservoir volume and its initialhydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzing changes in pressure with respect to productionrelationships. This method requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir. The material balance methodis applicable to all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids. Reserves for depletion type reservoirs can beestimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available. Estimates for other reservoir typesrequire extensive data and involve complex calculations most suited to computer models which makes this method generally applicable only to reservoirs where there is economicjustification for its use. Reserve estimates obtained by this method are generally considered to have a degree of accuracy that is directly related to the complexity of the reservoir andthe quality and quantity of data available. Volumetric. This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of hydrocarbons in-place. The data required arewell information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric method is most applicable to reservoirswhich are not susceptible to analysis by production performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs.The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and a knowledge of thenature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of accuracy can be relatively high whererock quality and subsurface control is good and the nature of the reservoir is uncomplicated. Analogy. This method which employs experience and judgment to estimate reserves, is based on observations of similar situations and includes consideration oftheoretical performance. The analogy method is a common approach used for “resource plays,” where an abundance of wells with similar production profiles facilitates the reliableestimation of future reserves with a relatively high degree of accuracy. The analogy method may also be applicable where the data are insufficient or so inconclusive that reliablereserve estimates cannot be made by other methods. Reserve estimates obtained in this manner are generally considered to have a relatively low degree of accuracy. Much of the information used in the estimation of reserves is itself arrived at by the use of estimates. These estimates are subject to continuing change as additionalinformation becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtainedabout well and reservoir performance. Appendix Cawley, Gillespie & Associates, Inc.Page 2  APPENDIXReserve Definitions and Classifications The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adherenceto the following definitions of oil and gas reserves: "(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can beestimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and 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 ofwhether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certainthat it will commence the project within a reasonable time. "(i) The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilledportions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscienceand engineering data. "(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetrationunless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. "(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oilreserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contactwith reasonable certainty. "(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included inthe proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operationof an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis onwhich the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities. "(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average priceduring the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for eachmonth within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. "(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category 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 ofa 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. "(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells onundrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. “(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled,unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. “(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilledwithin five years, unless the specific circumstances, justify a longer time. “(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improvedrecovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty. Appendix Cawley, Gillespie & Associates, Inc.Page 3  "(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with provedreserves, are as likely as not to be recovered. “(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probablereserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reservesestimates. “(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, evenif the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurallyhigher than the proved area if these areas are in communication with the proved reservoir. “(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumedfor proved reserves. “(iv) See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below). "(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. “(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable pluspossible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plusprobable plus possible reserves estimates. “(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressivelyless certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from thereservoir by a defined project. “(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantitiesassumed for probable reserves. “(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercialinterpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects. “(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation thatmay be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore,and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurallyhigher or lower than the proved area if these areas are in communication with the proved reservoir. “(vi) Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potential exists for anassociated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established withreasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gasbased on reservoir fluid properties and pressure gradient interpretations.” Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that "a registrant engaged in oil and gasproducing activities shall provide the information required by Subpart 1200 of Regulation S–K." This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant ispermitted, but not required, to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.” "(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, byapplication 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 ora 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. “Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated andevaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence ofreservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscoveredaccumulations).” Appendix Cawley, Gillespie & Associates, Inc.Page 4  CAWLEY, GILLESPIE & ASSOCIATES, INC. PETROLEUM CONSULTANTS 13640 BRIARWICK DRIVE, SUITE 100AUSTIN, TEXAS 78729-1107306 WEST SEVENTH STREET, SUITE 302FORT WORTH, TEXAS 76102-49871000 LOUISIANA STREET, SUITE 1900HOUSTON, TEXAS 77002-5008512-249-7000817- 336-2461713-651-9944 www.cgaus.com Professional Qualifications of Primary Technical Person The evaluation summarized by this report was conducted by a proficient team of geologists and reservoir engineers who integrategeological, geophysical, engineering and economic data to produce high quality reserve estimates and economic forecasts. This reportwas supervised by Todd Brooker, President of Cawley, Gillespie & Associates (CG&A). Prior to joining CG&A, Mr. Brooker worked in Gulf of Mexico drilling and production engineering at Chevron. Mr. Brooker has beenan employee of CG&A since 1992. His responsibilities include reserve and economic evaluations, fair market valuations, field studies,pipeline resource studies and acquisition/divestiture analysis. His reserve reports are routinely used for public company SECdisclosures. His experience includes significant projects in both conventional and unconventional resources in every major U.S.producing basin and abroad, including oil and gas shale plays, coalbed methane fields, waterfloods and complex, faulted structures. Mr. Brooker graduated with honors from the University of Texas at Austin in 1989 with a Bachelor of Science degree in PetroleumEngineering, and is a registered Professional Engineer in the State of Texas. He is also a member of the Society of PetroleumEngineers. Based on his educational background, professional training and more than 20 years of experience, Mr. Brooker and CG&A continueto deliver professional, ethical and reliable engineering and geological services to the petroleum industry. CAWLEY, GILLESPIE & ASSOCIATES, INC. TEXAS REGISTERED ENGINEERING FIRM F-693 

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