Lilis Energy
Annual Report 2016

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, 2016 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: None Common Stock, $0.0001 par value 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 filer¨Non-accelerated filer ¨Smaller reporting companyx 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, 2016, 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 $8,249,960. This figure is based on the closing sales price of $2.00 per share of theregistrant’s common stock on June 30, 2016 on the OTCQB. As of March 1, 2017, 24,387,793 shares of the registrant’s Common Stock were issued and outstanding.  FORM 10-K ANNUAL REPORTYEAR ENDED DECEMBER 31, 2016LILIS ENERGY, INC. PagePART I Items 1 and 2.Business and Properties6Item 1A.Risk Factors20Item 1B.Unresolved Staff Comments40Item 3.Legal Proceedings40Item 4.Mine Safety Disclosures40 PART II Item 5.Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities41Item 6.Selected Financial Data41Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations42Item 7A.Quantitative and Qualitative Disclosures About Market Risk52Item 8.Financial Statements and Supplementary Data53Item 9.Changes in and disagreements with Accountants on Accounting and Financial Disclosure53Item 9A.Controls and Procedures53Item 9B.Other Information53 PART III Item 10.Directors, Executive Officers and Corporate Governance54Item 11.Executive Compensation60Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters70Item 13.Certain Relationships and Related Transactions, and Director Independence75Item 14.Principal Accounting Fees and Services78 PART IV Item 15.Exhibits, Financial Statement Schedules80  FORWARD-LOOKING STATEMENTS This Annual Report on Form 10-K contains “forward-looking statements”. All statements other than statements of historical fact are “forward-lookingstatements” for purposes of federal and state securities laws, including, but not limited to, any projections of earnings, revenue or other financial items; anystatements of the plans, strategies and objectives of management for future operations; any statements concerning future production, reserves or otherresource development opportunities; any projected well performance or economics, or potential joint ventures or strategic partnerships; any statementsregarding future economic conditions or performance; any statements regarding future capital-raising activities; any statements of belief; and any statementsof assumptions underlying any of the foregoing. Forward-looking statements may include the words “may,” “should,” “could,” “estimate,” “intend,” “plan,” “project,” “continue,” “believe,” “expect” or“anticipate” or other similar words. These forward-looking statements present our estimates and assumptions only as of the date of this presentation. Exceptas required by law, we do not intend, and undertake no obligation, to update any forward-looking statement. Although we believe that the expectations reflected in any of our forward-looking statements are reasonable, actual results could differ materially from thoseprojected or assumed in any of our forward-looking statements. Our future financial condition and results of operations, as well as any forward-lookingstatements, are subject inherent risks and uncertainties. The factors impacting these risks and uncertainties include, but are not limited to, the Risk Factors setforth in this Annual Report on Form 10-K in Part I, “Item 1A. Risk Factors” and the following factors: ·our estimates regarding operating results, future revenues and capital requirements;·our ability to successfully integrate our acquisition of Brushy Resources, Inc. and realize anticipated benefits from such acquisition;·availability of capital on an economic basis, or at all, to fund our capital or operating needs;·our level of debt, which could adversely affect our ability to raise additional capital, limit our ability to react to economic changes and makeit more difficult to meet our obligations under our debt;·restrictions imposed on us under our credit agreement or other debt instruments that limit our discretion in operating our business;·potential default under our material debt agreements;·failure to meet requirements or covenants under our debt instruments, which could lead to foreclosure of significant core assets;·failure to fund our authorization for expenditures from other operators for key projects which will reduce or eliminate our interest in thewells/asset;·the inability of management to effectively implement our strategies and business plans;·estimated quantities and quality of oil and natural gas reserves;·exploration, exploitation and development results;·fluctuations in the price of oil and natural gas, including further reductions in prices that would adversely affect our revenue, cash flow,liquidity and access to capital;·availability of, or delays related to, drilling, completion and production, personnel, supplies (including water) and equipment;·the timing and amount of future production of oil and natural gas;·the timing and success of our drilling and completion activity;·lower oil and natural gas prices negatively affecting our ability to borrow or raise capital, or enter into joint venture arrangements;·declines in the values of our natural gas and oil properties resulting in further write-down or impairments;·inability to hire or retain sufficient qualified operating field personnel;·our ability to successfully identify and consummate acquisition transactions;·our ability to successfully integrate acquired assets or dispose of non-core assets;·the occurrence of natural disasters, unforeseen weather conditions, or other events or circumstances that could impact our operations or couldimpact the operations of companies or contractors we depend upon in our operations;·inability to successfully develop our large inventory of undeveloped acreage we currently hold on a timely basis;·constraints, interruptions or other issues affecting the Delaware Basin, including with respect to transportation, marketing, processing,curtailment of production, natural disasters, and adverse weather conditions;·deterioration in general or regional economic conditions;·inability to acquire or maintain mineral leases at a favorable economic value that will allow us to expand our development efforts;·technical risks inherent in drilling in existing or emerging unconventional shale plays using horizontal drilling and complex completiontechniques;·delays, denials or other problems relating to our receipt of operational consents, approvals and permits from governmental entities and otherparties; 1  ·unanticipated recovery or production problems, including cratering, explosions, blow-outs, fires and uncontrollable flows of oil, natural gasor well fluids;·loss of senior management or technical personnel;·litigation and the outcome of other contingencies, including legal proceedings;·adverse state or federal legislation or regulation that increases the costs of compliance, or adverse findings by a regulator with respect toexisting operations, including those related to climate change and hydraulic fracturing;·anticipated trends in our business;·effectiveness of our disclosure controls and procedures and internal controls over financial reporting; and·changes in generally accepted accounting principles in the United States or in the legal, regulatory and legislative environments in themarkets in which we operate. Many of these factors are beyond our ability to control or predict. These factors are not intended to represent a complete list of the general or specificfactors that may affect us. 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 theSEC’s website (www.sec.gov). 2  GLOSSARY In this Annual Report on Form 10-K, 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. 3  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 gas reserves. Proved developed oil and gas reserves are proved reserves that can be expected to be recovered (i) through existingwells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well;and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving awell. 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 gas reserves are proved reserves that are expected to be recovered from new wells on undrilledacreage, 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 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. PV-10 (Present value of future net cash flow). The present value of estimated future revenues to be generated from the production of estimated provedreserves, net of capital expenditures and operating expenses, using the simple 12 month arithmetic average of first of the month prices and current costs(unless such prices or costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as generaland administrative expenses, debt service, future income tax expenses, depreciation, depletion and amortization or impairment, discounted using an annualdiscount rate of 10%. While this non-GAAP measure does not include the effect of income taxes as would the use of the standardized measure calculation, webelieve it provides an indicative representation of the relative value of our company on a comparative basis to other companies and from period to period. 4  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 gas liquids anticipated to be economically producible, as of a given date, by application ofdevelopment projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right toproduce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financingrequired 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. 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. 5  PART I Items 1 and 2. Business and Properties Lilis Energy, Inc. and its consolidated subsidiaries (collectively, “we,” “us,” “our,” “Lilis Energy,” “Lilis,” or the “Company”) is an upstreamindependent oil and gas company engaged in the acquisition, drilling and production of oil and natural gas properties and prospects. We were incorporatedin August 2007 in the State of Nevada as Universal Holdings, Inc. In October 2009, we changed our name to Recovery Energy, Inc. and in December 2013,we changed our name to Lilis Energy, Inc. On June 23, 2016, we completed the merger transaction contemplated by the Agreement and Plan of Merger dated as of December 29, 2015, asamended to date (the “Merger Agreement”) by and among us, Brushy Resources, Inc., a Delaware corporation (“Brushy”) and Lilis Merger Sub, Inc., aDelaware corporation, a wholly-owned subsidiary of ours (“Merger Sub”). Pursuant to the terms of the Merger Agreement, at the effective time (the “EffectiveTime”), Merger Sub merged with and into Brushy (the “Merger”), with Brushy continuing as the surviving corporation and becoming a wholly-ownedsubsidiary of ours. The Merger resulted in the acquisition of our properties in the Delaware Basin as well as the majority of our current operating activity. Additionally, in connection with the Merger on June 23, 2016, we effected a 1-for-10 reverse stock split (the “Reverse Split”). As a result of theReverse Split, every ten shares of issued and outstanding common stock were automatically converted into one newly issued and outstanding share ofcommon stock, without any change in the par value per share. However, the number of authorized shares of common stock remained unchanged. Shortly after the Merger, we began to develop a drilling program on our properties using hydraulic fracture stimulation techniques. Our primary focusis drilling horizontal wells in the Delaware Basin of West Texas, which we believe will provide attractive returns on a majority of our acreage positions. Ourgoal is to earn economic returns to our shareholders through cash flow from new production of oil, natural gas and NGLs, as well as through derisking thedevelopment profile of our portfolio of properties in order to add overall value. 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 drilled our first horizontal well in late2016 and completed it in February 2017. Overview of Our Business and Strategy We are an oil and natural gas company, engaged in the acquisition, development and production of conventional and unconventional oil and naturalgas properties. We have accumulated approximately 6,924 net acres in the Delaware Basin in Winkler and Loving Counties, Texas and Lea County, NewMexico. Our leasehold position is largely contiguous, allowing us to maximize development efficiency, manage full-cycle finding costs and potentiallyenabling us to generate higher returns for our shareholders. In addition, 66% of our acreage positions is held by production, and we are the named operator on100% of our acreage. These characteristics give us control over the pace of development and the ability to design a more efficient and profitable drillingprogram that maximizes recovery of hydrocarbons. We expect that substantially all of our estimated 2017 capital expenditure budget will be focused on thedevelopment and expansion of our Delaware Basin acreage and operations. We also plan to continue to selectively and opportunistically pursue strategicbolt-on acreage acquisitions. As of March 1, 2017, our net production was 618 Boe/d (44% oil and liquids) of which 522 Boe/d was from our Delaware Basin area and 96 Boe/dfrom our Denver-Julesburg Basin area. As of December 31, 2016, on consolidated basis, we had proved reserves of 1,195 MBoe (46% oil and liquids). Our Delaware Basin Properties We have approximately 6,924 net acres in the Delaware Basin, comprised of 6,424 acres in Winkler and Loving Counties, Texas and 500 acres in LeaCounty, New Mexico. The aerial extent of the Delaware Basin stretches across Ward, Reeves, Loving, Winkler, Pecos, and Culberson Counties in Texas andalso runs north into Lea and Eddy Counties in New Mexico. The Delaware Basin is comprised of multiple stacked petroleum systems. Drilling andcompletion technology has evolved with more modern vintage wells utilizing longer laterals, more numerous fracture stimulation stages, and higher volumesof proppant. Our 2017 drilling program will primarily target the Wolfcamp formation in up to 10 wells. We are targeting horizontal lateral lengths of 5,000 to7,500 feet, holding hydraulic fracture stimulation stages per wellbore at each 200 foot increment, and an average of 2,200 pounds of proppant per lateral foot.Considering offset operator activity and our internal estimates, we believe our net average well cost will be between approximately $6.0 million and $8.0million per well based on the lateral length range of 5,000 to 7,500 feet, with average estimated ultimate recoveries, or EURs, ranging from approximately738 to 915 MBoe per well, and initial 30-day average production ranging between approximately 1,200 to over 1,750 Boe/d per well. 6  Our Denver-Julesburg Basin Properties In addition to our core Delaware Basin focus area, we have approximately 14,254 net acres in the Denver-Julesburg Basin (“DJ Basin”) comprised of280 net acres in the core of the Wattenberg field in Weld County, Colorado and 13,974 net acres in Laramie County, Wyoming, Nebraska and other parts ofColorado. Our acreage position has multi-zone potential with producing wells in the Niobrara, Codell, and J Sand. Our 2017 capital expenditure budget doesnot contemplate committing significant capital to our DJ Basin project area, and we are currently reviewing strategic alternatives with respect to theseproperties. Business Strengths and Strategies Our primary business objective is to increase our Delaware Basin leasehold position, reserves, production and cash flows at attractive rates of return oninvested capital in order to enhance shareholder value. To achieve this objective, key elements of our strategy include: ·Geographic focus in one of North America’s leading unconventional oil plays. We have accumulated a leasehold position of approximately 6,924 netacres in the Delaware Basin as of March 1, 2017. We believe the Delaware Basin has one of the highest rates of return among such formations in NorthAmerica based on results of offset operators. In addition to leveraging our technical expertise in this core area, our geographically-concentrated acreageposition allows us to capitalize on economies of scale with respect to drilling and production costs. Based on our drilling and production results to dateand well-established offset operator activity in and around our project areas, we believe there are relatively low geologic risks and ample repeatabledrilling opportunities across our core Delaware Basin operating area. We plan on allocating all of our 2017 capital budget to our Delaware Basinactivities. ·Develop our Delaware Basin leasehold position. We intend to focus on developing our acreage position in the Delaware Basin in order to maximizethe value of our resource potential through utilizing the best-in-class drilling and completion techniques at the lowest possible costs. Through thedevelopment of our properties, we will seek to derisk our acreage position and drilling program and substantially increase our production and cashflow, thereby increasing the value of our properties. Our current leasehold position in the Delaware Basin has significant stacked-pay potential. Wecurrently estimate our properties include at least seven productive zones and hold approximately 500 future drilling locations across all of theproductive zones within this position. Initially, we intend to focus our horizontal development on the Wolfcamp formation, followed by the BoneSpring and Avalon formations through a combination of re-entering existing vertical wellbores and new drilling locations. ·Pursue strategic acquisitions, organic leasing, and other creative structures to continue to develop and grow our production and leasehold position.We continue to identify and seek to acquire additional acreage and producing assets in the Delaware Basin. We believe that we can continue oursuccessful track record of growing our acreage position in and around our core area at attractive costs. Since entering the Delaware Basin in June 2016,we have grown our acreage position 98% from 3,500 net acres to 6,924. We have accomplished this through buying smaller packages that arecomplementary to our core position and also by acquiring smaller, fragmented working interest positions on existing leaseholds. ·Leverage our extensive operational expertise to reduce costs and enhance returns. We are focused on continuously improving our operating costs andmetrics. We evaluate our operating metrics against those of other operators in our area in order to measure our performance and optimize our drillingand completion techniques. We utilize this process to make informed decisions about our capital expenditure program and drilling and completionactivity. We intend to leverage our contiguous acreage position and our knowledge of the Delaware Basin to capture operational and economicefficiencies. ·Employ leading drilling and completion techniques. We intend to employ industry best practices well design drilling and completion techniques byreplicating leading Delaware Basin operators. Our contiguous acreage position is offset by RSP Permian, Matador, Devon, Shell, Anadarko, and XTO,among other operators, and we will continue to observe and monitor their drilling activity and well results in the area as we execute on ourdevelopment plan. ·Maintain financial liquidity and flexibility. We intend to utilize cash flow from operations, available working capital, borrowings under our multiple-draw term loan and access the capital markets in order to fund and execute our capital expenditure and development program. We believe thisfinancial liquidity and flexibility will result in steady growth in leasehold, production, cash flow and proved reserves. ·Hedging. We intend to opportunistically use commodity price hedging instruments to reduce our exposure to oil and natural gas price fluctuationsand to help ensure that we have adequate cash flow to fund our debt service costs and capital programs. We intend to use hedging primarily to manageprice risks and returns on certain acquisitions and drilling programs. Our policy is to consider hedging an appropriate portion of our production atcommodity prices we deem attractive. 7  Principal Oil and Gas Interests All references to production, sales volumes and reserve quantities are net to our interest unless otherwise indicated. As of December 31, 2016, we owned interests in approximately 19,968 net acres, of which 14,994 net acres are classified as undeveloped acreageand all of which are located in west Texas and New Mexico within the Delaware Basin and Colorado, Wyoming and Nebraska within the DJ Basin. Ourprimary targets within the Delaware Basin are the Wolfcamp formation as well as the Bone Springs and Avalon Formations. As of December 31, 2016 and March 1, 2017, we had 2 gross (1.2 net) and 1 gross (0.6 net) wells in the process of being drilled, respectively, all inthe Delaware Basin. Reserves The table below presents summary information with respect to the estimates of our proved oil and gas reserves for the years ended December 31,2016 and 2015. We engaged Cawley, Gillespie & Associates, Inc. (“CG&A”) and Forrest A. Garb & Associates to audit internally prepared engineeringestimates for all of our proved reserves at year-end 2016 and 2015, respectively. Of these reserves, approximately 50% were classified as Proved DevelopedProducing (“PDP”). Proved Undeveloped (“PUD”) and Proved Non-Producing (“PNP”) included in this estimate are from 0 vertical well locations and 2horizontal well locations. As of December 31, 2016, total proved reserves were approximately 46% oil and NGLs and 54% natural gas. As of December 31,2015, total proved reserves were approximately 59% oil and NGLs and 41% natural gas. The following table provides summary information regarding our proved reserves as of December 31, 2016 and 2015, and production for the yearsended December 31, 2016 and 2015. Estimated Total Proved Reserves December 31, 2016 2015 Delaware Basin DJBasin Total Delaware Basin DJBasin Total Oil (MMBBL) 0.455 0.096 0.551 - 0.033 0.033 Natural Gas (BCF) 3.507 0.365 3.872 - 0.141 0.141 Total (MMBOE) 1.04 0.156 1.196 - 0.057 0.057 % Oil 44% 61% - 59% % Developed 100% 100% - 100% Avg. Net Production (BOE/D) 317 87 404 - 215 215 During the years ended December 31, 2016 and 2015, we recognized an impairment expense of approximately $4.7 million and $24.5 million,respectively. The $4.7 million impairment charge during the year ended December 31, 2016 was primarily due to the lower commodity prices sustained forthe majority of 2016 in the DJ Basin and the $24.5 million impairment charge for the year ended December 31, 2015 was attributable to the lack of capital todevelop our undeveloped oil and gas properties and lower commodity prices. 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 Securities Exchange Commission (the “SEC”). Responsibility for compliance in reservebookings is delegated to our Chief Financial Officer with assistance from our senior geologist consultant and a senior reserve engineering consultant. In2016, we established a Reserves Committee to provide additional oversight of our reserves estimation and certification process. The members of the ReservesCommittee consist of Brennan Short, our Chief Operating Officer, Ron Ormand, our Executive Chairman and Glenn Dawson, a member of our Board ofDirectors. 8  Technical reviews are performed throughout the year by our senior reserve engineering consultant and our geologist and other consultants whoevaluate all available geological and engineering data, under the guidance of the Chief Financial Officer. This data, in conjunction with economic data andownership information, is used in making a determination of estimated proved reserve quantities. The 2016 reserve process was overseen by Chris Cantrell,our senior reserve engineering consultant. Mr. Cantrell holds a Bachelor of Science degree in Petroleum Engineering conferred by Texas A&M University in1995. He is a registered professional engineer licensed in the State of Texas, license number 90521. He has been continuously involved in evaluating oil andgas properties since 1997, and is a member of the Society of Petroleum Engineers and the American Petroleum Institute. Third-party Reserves Study An independent third-party reserve study as of December 31, 2016, was performed by CG&A using its own engineering assumptions and othereconomic data provided by us. All of our total calculated proved reserve PV-10 value was audited by CG&A. CG&A is an independent petroleumengineering consulting firm that has been providing petroleum engineering consulting services for over 20 years. The individual at CG&A primarilyresponsible for overseeing our reserve audit is Todd Brooker, Senior Vice 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 States of Texas. He is also a member of the Society of PetroleumEngineers. The CG&A report dated January 12, 2017, is filed as Exhibit 99.1 to this Annual Report on Form 10-K. Oil and gas reserves and the estimates of the present value of future net cash flows therefrom were determined based on prices and costs as prescribedby the SEC and Financial Accounting Standards Board (“FASB”) guidelines. Reserve calculations involve the estimate of future net recoverable reserves ofoil and gas and the timing and amount of future net cash flows to be received therefrom. Such estimates are not precise and are based on assumptionsregarding a variety of factors, many of which are variable and uncertain. Proved reserves were estimated in accordance with guidelines established by the SECand the FASB, which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and costescalations except by contractual arrangements. For the years ended December 31, 2016 and 2015, commodity prices over the prior 12-month period and yearend costs were used in estimating net cash flows in accordance with SEC guidelines. In addition to a third-party reserve study, our reserves and the corresponding report are reviewed by our Chief Financial Officer, geologist and theAudit Committee of our Board of Directors. Our Chief Financial Officer is responsible for reviewing and verifying that the estimate of proved reserves isreasonable, complete, and accurate. The Audit Committee of our Board of Directors reviews the final reserves estimate in conjunction with CG&A’s auditletter. Production The following table summarizes the average volumes and realized prices of oil and gas produced from properties in which we held an interest duringthe periods indicated, and production cost per BOE: For the Year Ended December 31, 2016 2015 Product Oil (Bbl.) 61,088 7,067 Oil (Bbls)-average price $39.59 $41.36 Natural Gas (MCFE)-volume 400,775 32,291 Natural Gas (MCFE)-average price $2.54 $2.39 Barrels of oil equivalent (BOE) 127,863 12,449 Average daily net production (BOE) 350 34 Average Price per BOE $26.87 $29.67 (1)Includes proceeds from the sale of natural gas liquids (“NGL’s”) 9  For the Year Ended December 31, 2016 2015 Production costs per BOE $9.75 $15.70 Production taxes per BOE (1.30) 2.24 Depreciation, depletion, and amortization per BOE 12.25 46.93 Total operating costs per BOE $20.70 $64.87 Gross margin per BOE $6.17 $(35.20)Gross margin percentage 23% (119)% Oil and gas production costs, production taxes, depreciation, depletion, and amortization Drilling Activity As of December 31, 2016, we have drilled 1.2 net productive wells. As of December 31, 2016 and 2015, we had working interests in 35 gross (21 net) wells and 6 gross (1.27 net) wells, respectively. Productive wellsare either wells producing in commercial quantities or wells capable of commercial production, but are currently shut-in. Multiple completions in the samewellbore are counted as one well. A well is categorized under state reporting regulations as an oil well or a gas well based on the ratio of gas to oil producedwhen it first commenced production, and such designation may not be indicative of current production. Acreage As of December 31, 2016, we owned 36 producing wells within the Delaware Basin in Texas and New Mexico and in the DJ Basin in Colorado, aswell as approximately 34,858 gross (19,968 net) acres, of which 25,752 gross (14,994 net) acres were classified as undeveloped acreage. Our primary assetsincluded acreage located in Winkler and Loving Counties in Texas, Lea County in New Mexico; Laramie and Goshen Counties in Wyoming; Banner,Kimball, and Scotts Bluff Counties in Nebraska; and Weld, Arapahoe and Elbert Counties in Colorado. As of December 31, 2015, we owned 8 producing wells in Wyoming, Nebraska and Colorado within the DJ Basin, as well as approximately 18,000gross (16,000 net) acres, of which 10,000 gross (8,000 net) acres were classified as undeveloped acreage. Our primary assets included acreage located inLaramie and Goshen Counties in Wyoming; Banner, Kimball, and Scotts Bluff Counties in Nebraska; and Weld, Arapahoe and Elbert Counties in Colorado.The following table sets forth our gross and net developed and undeveloped acreage as of December 31, 2016 and 2015: Undeveloped Developed Gross Net Gross Net DJ Basin 16,678 13,576 1,923 678 Delaware Basin 9,074 1,418 7,183 4,295 Total acreage as of December 31, 2016 25,752 14,994 9,106 4,973 DJ Basin 10,000 8,000 8,000 8,000 Total acreage as of December 31, 2015 10,000 8,000 8,000 8,000 As of March 1, 2017, our inventory of developed and undeveloped acreage includes approximately 40,618 gross (21,178 net) acres, of which 9,106gross (5,248 net) acres that are held by production. We will continue to pursue additional properties, acquire other properties primarily targeted in theDelaware Basin, but potentially throughout North America, or drill wells on our core properties to hold the property by production if financing is available tous and the properties are economic. 10  Title to Properties Approximately 66% of our leasehold interests are held by production, with the majority of our Delaware Basin leasehold position subject tomortgages securing indebtedness under our credit and guarantee agreement. The credit agreement was entered into on September 29, 2016 (the “CreditAgreement”) by and among our wholly-owned subsidiaries, Brushy, ImPetro Operating, LLC, a Delaware limited liability company (“Operating”) andImPetro Resources, LLC, a Delaware limited liability company (“Resources”, and together with Brushy and Operating, the “Borrowers”), and the lendersparty thereto (each a “Lender” and together, the “Lenders”) and T.R. Winston & Company, LLC acting as collateral agent. We believe the security interestsgranted in our properties do not materially interfere with the use of, or affect the value of, such properties. Marketing and Pricing We derive revenue and cash flow principally from the sale of oil and natural gas. As a result, our revenues are determined, to a large degree, byprevailing prices for crude oil and natural gas. We sell our oil and natural gas on the open market at prevailing market prices or through forward deliverycontracts. The market price for oil and natural gas is dictated by supply and demand, and we cannot accurately predict or control the price we may receive forour oil and natural gas. Our revenues, cash flows, profitability and future rate of growth will depend substantially upon prevailing prices for oil and natural gas. Prices mayalso affect the amount of cash flow available for capital expenditures and other cash requirements and our ability to borrow money or raise additional capital.Lower prices may also adversely affect the value of our reserves and make it uneconomical for us to commence or continue production levels of natural gasand crude oil. Historically, the prices received for oil and natural gas have fluctuated widely. Among the factors that can cause these fluctuations are: ·changes in global supply and demand for oil and natural gas;·the actions of the Organization of Petroleum Exporting Countries;·the price and quantity of imports of foreign oil and natural gas;·acts of war or terrorism;·political conditions and events, including embargoes, affecting oil-producing activity;·the level of global oil and natural gas exploration and production activity;·the level of global oil and natural gas inventories;·weather conditions;·technological advances affecting energy consumption;·transportation options from trucking, rail, and pipeline; and·the price and availability of alternative fuels. 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, 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. In addition, hedging arrangements may limit the benefit we would receive from increases in the prices for oil and natural gas. As of December 31,2016, we had no hedging agreements in place. 11  Major Customers Our major customers for the year ended December 31, 2016 include Noble Energy, Inc., Texican Natural Gas Company, and Energy TransferPartners, L.P., who accounted for approximately 41%, 38%, and 16% of our revenue for the year ended December 31, 2016, respectively. Our major customersfor the year ended December 31, 2015 include, Shell Trading (US) Company, PDC Energy, Inc., and Noble Energy, Inc., who accounted for approximately43%, 26%, and 21% of our revenue for the year ended December 31, 2015, respectively. We do not believe that the loss of any single customer wouldmaterially affect our business because there are numerous other potential purchasers of our production. Seasonality Generally, but not always, the demand and price levels for natural gas increase during colder winter months and decrease during warmer summermonths. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies, and industrial users utilize natural gas storage facilitiesand forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity has placedincreased demand on storage volumes. Demand for crude oil and heating oil is also generally higher in the winter and the summer driving season, althoughoil prices are much more driven by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. The impact ofseasonality on crude oil has been somewhat magnified by overall supply and demand economics attributable to the narrow margin of production capacity inexcess of existing worldwide demand for crude oil. Competition 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 dependson 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 than we do. 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. 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. 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, the FERC and the courts. We cannot predict when or whether any suchproposals may become effective. We do not believe that we would be affected by any such action materially differently than similarly situated competitors. 12  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 gas and may prevent or delay the commencement or continuation of certainprojects. In addition, these laws and regulations may impose substantial clean-up, remediation, and other obligations in the event of any discharges oremissions in violation of these laws and regulations. Further, legislative and regulatory initiatives related to global warming or climate change could have anadverse 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, 2016 and 2015, we incurred $182,000 and $130,000, respectively, related to compliance withenvironmental laws for our DJ Basin. 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. 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.  13  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. 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 May 12,2016, the EPA issued regulations (effective August 2, 2016) that build on the NSPS OOOO standards by directly regulating methane and volatile organiccompound (“VOC”) emissions from various types of new and modified oil and gas sources. Some of those sources are already regulated under NSPS OOOO,while others, like hydraulically fractured oil wells, pneumatic pumps, and certain equipment and components at compressor stations, are covered for the firsttime. On March 10, 2016, moreover, the EPA announced that it is moving towards issuing performance standards for methane emissions from existing oil andgas sources. The agency said that it will “begin with a formal process (i.e., an Information Collection Request) to require companies operating existing oiland gas sources to provide information to assist in the development of comprehensive regulations to reduce methane emissions.” On November 10, 2016, theEPA issued the Information Collection Request (“ICR”) and explained that “[r]ecipients of the operator survey (also referred to as Part 1) will have 60 daysafter 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 180days after receiving the ICR to complete that survey and submit it to the agency.” 14  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. Along these lines, on October 20, 2016, the EPA finalized Control Techniques Guidelines to reduce emissions from a number of existing oil and gassources that are located in certain ozone nonattainment areas and states in the Ozone Transport Region (which is comprised of Connecticut, Delaware, Maine,Maryland, Massachusetts, New Hampshire, New Jersey, New York, Pennsylvania, Rhode Island, Vermont, the District of Columbia, and Northern Virginia).These guidelines will lead to direct regulation of VOC emissions and have the incidental effect of reducing methane emissions. The regulations will take theform of reasonably available control technology requirements. 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 gas production sources in the United States on an annual basis, which include certain of our operations. In October2015, the EPA finalized rules (effective January 1, 2016) that added new sources to the scope of the greenhouse gases monitoring and reporting rule. Thesenew sources include gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells. The revisions also includethe addition of well identification reporting requirements for certain facilities. In addition, as noted above, the EPA has finalized new source performancestandards related to methane emissions from the oil and natural gas industry. 15  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, gas or other pollutants into the air, soil or water may give rise to liabilities to the government and third parties and may requireus to incur costs to remedy discharges. Natural gas, oil or other pollutants, including salt water brine, may be discharged in many ways, including from a wellor drilling equipment at a drill site, leakage from pipelines or other gathering and transportation facilities, leakage from storage tanks and sudden dischargesfrom damage or explosion at natural gas facilities of oil and gas wells. Discharged hydrocarbons may migrate through soil to fresh water aquifers or adjoiningproperty, giving rise to additional liabilities. 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. 16  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 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. 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. As a result of a pair of 2011 settlementagreements, the FWS is required to make determinations on whether more than 250 species should be listed as endangered or threatened under the FSA. Itmust make the determinations by no later than completion of the agency’s 2017 fiscal year. Similar protections are offered to migratory birds under theMigratory Bird Treaty Act. The federal government has issued indictments under the Migratory Bird Treaty Act to several oil and gas companies after deadmigratory birds were found near reserve pits associated with drilling activities. The identification or designation of previously unprotected species asthreatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protectionmeasures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and producereserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases. 17  NEPAAdditionally, 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. 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 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.  18  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 gas leases, such operations must comply with numerous regulatory restrictions, includingvarious non-discrimination statutes, and certain of such operations must be conducted pursuant to certain on-site security regulations and other permitsissued 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. 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. In May 2010, the BLM adopted changes to its oil and gas leasing program that require, among other things, a more detailed environmental reviewprior to leasing oil and natural gas resources, increased public engagement in the development of master leasing and development plans prior to leasing areaswhere intensive new oil and gas development is anticipated, and a comprehensive parcel review process. These changes have increased the amount of timeand regulatory costs necessary to obtain oil and gas leases administered by the BLM. In addition, the BLM, on March 20, 2015, issued its final regulationsfor hydraulic fracturing on federal and tribal lands. The new regulations require, among other things, disclosure of chemicals, annulus pressure monitoring,flow back and produced water management and storage, and more stringent well integrity measures associated with hydraulic fracturing operations on publicland. The new regulations become effective on June 24, 2015. BLM has also announced its intention to conduct a separate rulemaking to address ventingand flaring of natural gas from oil and gas operations on public land. These hydraulic fracturing-related rulemakings may adversely affect our operationsconducted on federal lands. 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. Employees As of December 31, 2016, we had nineteen full-time employees and two part-time employees, and intend to continue to add additional personnel asour operational requirements grow. We plan to continue to leverage the use of independent consultants and contractors to provide various professionalservices, including additional land, legal, engineering, geology, environmental and tax services. 19  Available Information We have closed our offices in Denver, Colorado on February 28, 2017 and moved our corporate headquarter to 300 E. Sonterra Blvd., Suite No.1220, San Antonio, Texas 78258, and our telephone number is (210) 999-5400. Our web site is www.lilisenergy.com. Additional information that may beobtained through our web site does not constitute part of this Annual Report on Form 10-K. Our Annual Reports on Form 10-K, Quarterly Reports on Form10-Q, Current Reports on Form 8-K and amendments to those reports are accessible free of charge at our website. The SEC also maintains an internet site thatcontains reports, proxy and information statements and other information regarding our filings at www.sec.gov. 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 could materiallyaffect our business, financial condition and results of operations and cause a decline in the market price of our shares. You should carefully consider all ofthe risks described in this Annual Report on Form 10-K, in addition to the other information contained in this Annual Report on Form 10-K, before youmake an investment in our common stock. Additional risks not presently known to us or that we currently deem immaterial may also adversely affect ourbusiness. In addition to other matters identified or described by us from time to time in filings with the SEC, there are several important factors that couldcause our future results to differ materially from historical results or trends, results anticipated or planned by us, or results that are reflected from time totime in any forward-looking statement. Some of these important factors, but not necessarily all important factors, include the following: Risks Relating to Our Business If we are not able to access additional capital in significant amounts, we may not be able to develop our current prospects and properties, or wemay forfeit our interest in certain prospects and we may not be able to continue to operate our business. We need significant additional capital to continue to operate our properties and continue operations. Currently, a significant portion of our revenueafter field level operating expenses is required to be paid to our lenders as debt service. In the near term, we intend to finance our capital expenditures with cash flow from operations, sales of non-core property assets, future issuance ofdebt and/or equity securities and entry into a new credit facility. Our cash flow from operations and access to capital is subject to a number of variables,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 2017 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, sales of non-core property assets, offerings of debt or equity securities or other means. Wemay not be able to obtain debt or equity financing on terms favorable, or at all. If we are unable to fund our capital requirements, we may be required to curtail our operations relating to the exploration and development of ourprospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves, or may be otherwise unable to implementtheir development plan, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which couldhave a material adverse effect on our production, revenues and results of operations. In addition, a delay in or the failure to complete proposed or futureinfrastructure projects could delay or eliminate potential efficiencies and related cost savings. The occurrence of such events may prevent us from continuingto operate our business and our common stock and preferred stock may not have any value. 20  We have substantial liquidity needs and may be required to seek additional financing to fund our 2017 capital budget. If we are unable to obtainfinancing on satisfactory terms or maintain adequate liquidity, our ability to fund our capital budget, replace our proved reserves or to maintainproduction levels and generate revenue will be limited. 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 and Series B preferred notes. Our capital program will require additional financing abovethe level of cash generated by our operations to fund growth. If our expected cash flow from operations decreases as a result of lower commodity prices orotherwise, our ability to expend the capital necessary to replace our proved reserves, maintain our leasehold acreage or maintain production may be limited,resulting in decreased production and proved reserves over time. We face uncertainty regarding the adequacy of our liquidity and capital resources to fund our 2017 capital budget. Our liquidity, including ourability to meet our ongoing operational obligations, is dependent upon, among other things: (i) our ability to maintain adequate cash on hand, including ourability to access additional financing, and (ii) our ability to generate cash flow from operations. Our ability to maintain adequate liquidity depends in partupon industry conditions and general economic, financial, competitive, regulatory and other factors beyond our control. We can provide no assurance thatadditional financing will be available or, if available, offered to us on acceptable terms. Given our existing debt and the estimated value of our provedreserves on December 31, 2016, we do not expect to have access to reserve-based revolving debt capacity during 2017. As a result, our access to additionalfinancing is, and for the foreseeable future will likely continue to be, dependent up our access to new equity and equity-linked capital. As a result, theadequacy of our capital resources is difficult to predict at this time Oil, NGL and natural gas prices are volatile and have declined significantly from levels experienced in recent years. If commodity prices experience afurther, substantial decline, our operations, financial condition, and level of expenditures for the development of our oil, NGL, and natural gas reservesmay be materially and adversely affected. The prices we receive for our oil, NGLs, and natural gas production heavily influence our revenue, operating results, profitability, access to capital,future rate of growth and carrying value of our properties. Oil, NGLs, and natural gas 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 willlikely continue to be volatile in the future. If the prices of oil, NGLs, and natural gas experience a further, substantial decline, our operations, financialcondition and level of expenditures for the development of our oil, NGLs, and natural gas reserves may be materially and adversely affected. The prices wereceive for our production, and the levels of our production, depend on numerous factors beyond our control and include the following: ·the level of global exploration and production; ·the level of global inventories; ·the ability and willingness of members of the Organization of the Petroleum Exporting Countries to agree to and maintain oil price andproduction controls; ·worldwide and regional economic conditions affecting the global supply and demand for oil, NGLs and natural gas; ·the price and quantity of imports of foreign oil, NGLs and natural gas; ·political and economic conditions in or affecting other producing countries, including conflicts in the Middle East, Africa, South America andRussia; ·prevailing prices on local price indexes in the areas in which we operate and expectations about future commodity prices; ·the proximity, capacity, cost and availability of gathering and transportation facilities, and other factors that result in differentials to benchmarkprices; ·localized and global supply and demand fundamentals and transportation availability; the cost of exploring for, developing, producing andtransporting reserves;weather conditions and other natural disasters;technological advances affecting energy consumption; 21  ·the price and availability of alternative fuels;expectations about future commodity prices; anddomestic, local and foreign governmentalregulation and taxes. Lower commodity prices may reduce our cash flows and borrowing ability. We may be unable to obtain needed capital or financing on satisfactoryterms, which could lead to a decline in our reserves as existing reserves are depleted. Lower commodity prices may also reduce the amount of oil, NGLs, andnatural gas that we can produce economically, and a significant portion of our exploitation, development and exploration projects could becomeuneconomic. This may result in our having to make significant downward adjustments to our estimated proved reserves. As a result, if commodity pricesremain depressed for a lengthy period of time or experience a further substantial or extended decline, our future business, financial condition, results ofoperations, liquidity, or ability to finance planned capital expenditures may be materially and adversely affected. 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. On September 29, 2016, we entered into the Credit Agreement that provides for a three-year senior secured term loan with an aggregate principalamount of $31.0 million outstanding as of December 31, 2016, and $38.1 million outstanding as of March 1, 2017. We may borrow up to an aggregateprincipal amount of $50 million under the Credit Agreement. Our degree of leverage could have important consequences, including the following: ·it may limit our ability to obtain additional debt or equity financing for working capital, capital expenditures, further exploration, debtservice requirements, 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 andwill not be available 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 capitalspending and 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 ourlenders, 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. Ourability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, natural gasand oil prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. Factorsthat will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value ofour assets, the number of shares of capital stock we have authorized, unissued and unreserved and our performance at the time we need capital. The Credit Agreement, guaranteed and further secured by substantially all our assets, contains restrictive covenants that may limit our ability to respondto changes in market conditions or pursue business opportunities. The Credit Agreement contains restrictive covenants that limit our ability to, among other things: ·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. 22  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. Our disclosure controls and procedures and internal controls over financial reporting may not detect errors or potential acts of fraud. Our management does not expect that our disclosure controls and procedures and internal controls will prevent all possible errors and all fraud. Acontrol system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system arebeing met. In addition, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls are evaluatedrelative to their costs. Because of the inherent limitations in all control systems, no evaluation of our controls can provide absolute assurance that all controlissues and instances of fraud, if any, have been detected. The design of any system of controls is based in part upon the likelihood of future events, and anydesign may not succeed in achieving its intended goals under all potential future conditions. Over time, a control may become inadequate because ofchanges in conditions, or the degree of compliance with our policies or procedures may deteriorate. Because of inherent limitations in a cost-effective controlsystem, misstatements due to error or fraud may occur without detection. 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. Through September 30, 2016, management had concluded that its internal control over financial reporting was not effective. During the fourthquarter of 2016, we completed our remediation efforts, but we may discover additional areas of our internal control over financial reporting in the futurewhich may require improvement. If we are unable to assert that our internal control over financial reporting is effective in any future period, or if our auditorsare unable to express an opinion on the effectiveness of our internal controls, we could lose investor confidence in the accuracy and completeness of ourfinancial reports, which could have an adverse effect on our stock price. If oil or natural gas prices decrease or exploration and development efforts are unsuccessful, wells in progress are deemed unsuccessful, or major tracts ofundeveloped acreage expire, or other similar adverse events occur, we may be required to write-down the carrying value of our developed properties. 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 wells, completing productive wells, or plugging and abandoning non-productive wells, costs related toexpired leases, or leases underlying producing and non-producing wells, and overhead charges directly related to acquisition and exploration activities.Under the full cost method of accounting, capitalized oil and natural gas property that comprise the full cost pool, less accumulated depletion and net ofdeferred income taxes, may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and naturalgas reserves. This ceiling test is performed at least quarterly. Should the capitalized costs of the full cost pool exceed this ceiling, we would recognize animpairment expense. We recognized an impairment expense of approximately $4.7 million and $24.5 million for the years ended December 31, 2016 and2015, respectively. At December 31, 2016, the Company’s estimates of undiscounted future cash flows indicated that the carrying amounts were not expectedto be recovered due to a decrease in proved reserves. During 2016, commodity prices continued to trade in a low range. With low commodity prices sustainedfor the majority of 2016 in the DJ Basin, some of our properties became uneconomic triggering impairment charge of $4.7 million at December 31, 2016. Theimpairment charge of $24.5 million in 2015 was due to the lower commodity prices and lack of capital to develop our undeveloped oil and gas properties.Future write-downs could occur for numerous reasons, including, but not limited to continued reductions in oil and gas prices that lower the estimate offuture net revenues from proved oil and natural gas reserves, revisions to reserve estimates, or from the addition of non-productive capitalized costs to the fullcost pool that do not result in corresponding increase in oil and gas reserves. Impairments of plugging and abandonment of wells in progress are other areaswhere costs may be capitalized into the full cost pool, without any corresponding increase in reserve values; as such, these situations could result in futureadditional impairment expenses. 23  If commodity prices stay at current levels or decline further, we could incur full cost ceiling impairments in future quarters. Because the ceilingcalculation uses rolling 12-month average commodity prices, the effect of lower quarter-over-quarter prices in 2016 compared to 2015 is a lower ceilingvalue each quarter. This may result in ongoing impairments each quarter until prices stabilize or improve. Impairment charges would not affect cash flow fromoperating activities, but would adversely affect our net income and stockholders’ equity. 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. No one can measure underground accumulations of oil and natural gas in an exact way. Oil and natural gas reserve engineering requires subjectiveestimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, and operatingand development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of developmentexpenditures may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantitiesand present value of our reserves which could adversely affect business, results of operations, financial condition and our ability to make cash distributions toshareholders. 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 average oil and gasindex prices, calculated as the un-weighted arithmetic average for the first-day-of-the-month price for each month and costs in effect on the date of theestimate, 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 net present value estimate, and future net present value estimates usingthen current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we used when calculating discountedfuture net cash flows for reporting requirements in compliance with the FASB in Accounting Standards Codification, which is referred to as ASC 932 may notbe the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry ingeneral. Oil and natural gas prices are highly volatile, and our revenue, profitability, cash flow, future growth and ability to borrow funds or obtain additionalcapital, as well as the carrying value of our properties, are substantially dependent on prevailing prices of oil and natural gas. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices wereceive for our production and the levels of our production depend on numerous factors beyond our control. These factors include the following: ·changes in global supply and demand for oil and natural gas;·the actions of the Organization of Petroleum Exporting Countries;·the price and quantity of imports of foreign oil and natural gas;·acts of war or terrorism;·political conditions and events, including embargoes, affecting oil-producing activity;·the level of global oil and natural gas exploration and production activity;·the level of global oil and natural gas inventories;·weather conditions;·technological advances affecting energy consumption;·the price and availability of alternative fuels; and·market concerns about global warming or changes in governmental policies and regulations due to climate change initiatives. 24  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. 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, 2016, we had no hedgingagreements in place. Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrenceor timing of our drilling. Our management has specifically identified and scheduled drilling locations as an estimation of future multi-year drilling activities on 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 oil and natural gas is a speculative activity and involves numerous risks and substantial and uncertain costs that could adversely affect us. Our success will depend on the success of our drilling program. There is no way to predict in advance of drilling and testing whether any 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. Analogies drawn from available data from other wells, more fullyexplored prospects or producing fields may not be applicable to current drilling prospects. The budgeted costs of planning, drilling, completing and operating wells are often exceeded and such costs can increase significantly due to variouscomplications that may arise during the drilling and operating processes. Before a well is spud, we may incur significant geological and geophysical(seismic) costs, which are incurred whether a well eventually produces commercial quantities of hydrocarbons, or is drilled at all. Exploration wells endure amuch greater risk of loss than development wells. If actual drilling and development costs are significantly more than the current estimated costs, we may notbe able to continue operations as proposed and could be forced to modify drilling plans accordingly. Drilling for oil and natural gas involves numerous risks,including the risk that no commercially productive natural gas or oil reservoirs will be discovered. The cost of drilling, completing, and operating wells issubstantial and uncertain, and drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors beyond our control, including: 25  ·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. If we decide to drill a certain location, there is a risk that (i) no commercially productive oil or natural gas reservoirs will be found or produced, or (ii)we may 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 aprofit after drilling, operating and other costs. A productive well may become uneconomical if water or other deleterious substances are encountered whichimpair or prevent the production of oil and/or natural gas from the well. Our overall drilling success rate or drilling success rate for activity within a particularproject area may decline. Unsuccessful drilling activities could result in a significant decline in production and revenues and materially harm operations andfinancial condition by reducing available cash and resources. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productivehydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production andreserves from the well or abandonment of the well. 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 exploration and development activities. We derive essentially all of our revenues from the sale of our oil and natural gas 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. Liquidity and cash flow problems encountered by our working interest co-owners or the third-party operators of our non-operated properties mayprevent or delay the drilling of a well or the development of a project. Our working interest co-owners may be unwilling or unable to pay their share of thecosts of projects as they become due. In the case of a working interest owner, we could be required to pay the working interest owner’s share of the projectcosts. Prospects in which we decide to participate may not yield oil or natural gas in commercially viable quantities or quantities sufficient to meet our targetedrate of return. A prospect is a property in which we own an interest and contains what we believe, based on available reservoir, seismic and/or geologicalinformation, to be indications of commercial oil or natural gas. Our prospects are in various stages of evaluation, ranging from a prospect that is ready to bedrilled to a prospect that will require substantial additional technical assessment, data acquisition and/or seismic data processing and interpretation. There isno definitive method to predict in advance of drilling and testing and wider-scale development whether any particular prospect will yield oil or natural gas insufficient quantities to be economically viable. The use of reservoir, geologic and seismic data and other technologies and the study of producing fields inthe same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas willbe present in commercial quantities. The analysis we perform using data from other wells, more fully explored prospects or producing fields may not be usefulin predicting the characteristics and potential reserves associated with our drilling prospects. Our industry is highly competitive, which may adversely affect our performance, including our ability to participate in ready to drill prospects in our coreareas. We operate in a highly competitive environment. In addition to capital, the principle resources necessary for the exploration and production of oiland natural gas are: ·leasehold prospects under which oil and natural gas reserves may be discovered;·drilling rigs and related equipment to explore for such reserves; and·knowledge personnel to conduct all phases of oil and natural gas operations. We must compete for such resources with both major oil and natural gas companies and independent operators. Virtually all of these competitorshave financial and other resources substantially greater than ours. Such capital, materials and resources may not be available when needed. If we are unable toaccess capital, material and resources when needed, we risk suffering numerous consequences, including: 26  ·the breach of our obligations under the oil and gas leases by which we hold our prospects and the potential loss of those leasehold interests;·loss of reputation in the oil and gas community;·inability to retain staff or attract capital;·a general slowdown in our operations and decline in revenue; and·decline in market price of our common stock. Seismic studies do not guarantee that hydrocarbons are present or, if present, will produce in economic quantities. We may use seismic studies to assist with assessing prospective drilling opportunities on current properties, as well as on properties that we mayacquire. Such seismic studies are merely an interpretive tool and do not necessarily guarantee that hydrocarbons are present or if present will produce ineconomic quantities. 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, 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. 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 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 and operations are located in a limited number of geographic areas, which exposes us to various risks, including the risk ofdamage or business interruptions from natural disasters or weather events. All of our estimated proved reserves at December 31, 2016, all of our 2016 and 2015 sales were generated in the Delaware Basin in Winkler andLoving Counties, West Texas and Lea County, New Mexico and the DJ Basin in southeastern Wyoming, northeastern Colorado and southwestern Nebraska. Although these areas are well-established oilfield infrastructures, we may be disproportionately exposed to the impact of delays or interruptions ofproduction from these wells caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel orservices, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption oftransportation of oil or natural gas produced from the wells in this area. 27  In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and gas producing areas,which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Due to the concentrated nature of our portfolio ofproperties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results ofoperations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a materialadverse effect on our financial condition and results of operations. Our operational risk is concentrated due to our reliance on a small number of wells, operators and oil and gas purchasers. We have concentrated operational risks both in terms of producing oil and gas properties, the operators we use and in the purchasers of our oil andgas production. An operational failure by an operator, the decline of production from a property and the termination of a contractual agreement with anoperator or purchaser could have a material negative impact on our company. Our properties are located in areas where we have multiple markets for our oiland gas. As such, the loss of any single purchaser will not have a material impact with our ability to sell our oil and gas. We will 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 our Delaware assets, but do not control all our DJ Basin development. As we carry out our exploration anddevelopment programs, we may enter into arrangements with respect to existing or future drilling locations that result in a greater proportion of locationsbeing operated by others. As a result, we may have limited ability to exercise influence over the operations of the drilling locations operated by our partners.Dependence on the operator could prevent us from realizing target returns for those locations. The success and timing of exploration and developmentactivities operated by our partners will depend on a number of factors that will 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. This limited ability to exercise control over the operations of some of drilling locations may cause a material adverse effect on results of operationsand financial condition. The marketability of our production is dependent upon transportation and processing facilities over which we may have no control. The marketability of our production depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems, railservice, and processing facilities in addition to competing oil and gas production available to third-party purchasers. We deliver crude oil and natural gasproduced from these areas through trucking, gathering systems and pipelines, some of which we do not own. The lack of availability of capacity on third-party systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance ofdevelopment plans for properties. Although we have some contractual control over the transportation of our production through firm transportationarrangements, third-party systems and facilities may be temporarily unavailable due to market conditions or mechanical reliability or other reasons, includingadverse weather conditions or work-loads. Activist or other efforts may delay or halt the construction of additional pipelines or facilities. Third-party systemsand facilities may not be available to us in the future at a price that is acceptable to us. Any significant change in market factors or other conditions affectingthese infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities, could delay production, therebyharming our business and, in turn, our results of operations, cash flows, and financial condition. Our success is influenced by oil, natural gas, and NGL prices in the specific areas where we operate, and these prices may be lower than prices at majormarkets. Regional natural gas, condensate, oil and NGLs prices may move independently of broad industry price trends. Because some of our operations arelocated outside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTI or other major market pricing. 28  Unless we find new oil and gas reserves to replace actual production, our reserves and production will decline, which would materially and adverselyaffect our business, financial condition and results of operations. Producing oil and 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 gas reserves and production and, therefore, our cash flow andrevenue are highly dependent on our success in efficiently obtaining additional reserves. We may not be able to develop, find or acquire reserves to replaceour current and future production at costs or other terms acceptable to us, or at all, in which case our business, financial condition and results of operationswould be materially and adversely affected. Part of our strategy involves drilling in existing or emerging unconventional shale plays using available horizontal drilling and completion techniques.The results of our planned exploratory and development drilling in these plays are subject to drilling and completion execution risks and drilling resultsmay not meet our economic expectations for reserves or production. As a result, we may incur material write-downs and the value of our undevelopedacreage could decline if drilling results are unsuccessful. 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 over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because ofcapital constraints, lease expirations, access to gathering systems and limited takeaway capacity or otherwise, and/or natural gas and oil prices decline, thereturn on our investment in these areas may not be as attractive as we anticipate and we could incur material write-downs of undeveloped properties and thevalue of our undeveloped acreage could decline in the future. The unavailability or high cost of drilling rigs, equipment supplies or personnel could adversely affect our ability to execute our exploration 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 gas during the last several years have increased activity which has resulted in shortages of drilling rigs, equipment and personnel, which have resulted inincreased costs and delays in the areas where we operate. If drilling rigs, equipment, supplies or qualified personnel are unavailable to us due to excessivecosts or demand or otherwise, our ability to execute our exploration and development plans could be materially and adversely affected and, as a result, ourfinancial 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. 29  We are exposed to operating hazards and uninsured risks. Our operations are subject to the risks inherent in the oil and natural gas industry, including the risks of: ·fire, explosions and blowouts;·negligence of personnel;·inclement weather;·pipe or equipment failure;·abnormally pressured formations; and·environmental accidents such as oil spills, natural gas environment (including groundwater contamination). 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. We maintain insurance against some, but not all, of these risks. Our insurance may not be adequate to cover these losses or liabilities. We do notcarry business interruption insurance. Losses and liabilities arising from uninsured or underinsured events may have a material adverse effect on our financialcondition and operations. 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. We may not have enough insurance to cover all of the risks faced and operators of prospects in which we participate may not maintain or may fail toobtain adequate insurance. In accordance with customary industry practices, we maintain insurance coverage against some, but not all, potential losses in order to protectagainst the risks faced. We do not carry business interruption insurance. We may elect not to carry insurance if management believes that the cost of availableinsurance is excessive relative to the risks presented. In addition, we cannot insure fully against pollution and environmental risks. The occurrence of anevent not fully covered by insurance could have a material adverse effect on our financial condition and results of operations. The impact of natural disastersor weather events in the areas where we operate has resulted in escalating insurance costs and less favorable coverage terms. 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. We do not operate all of the properties in which we hold an interest. In the projects in which we own a non-operating interest directly, the operatorfor the prospect maintains insurance of various types to cover operations with policy limits and retention liability customary in the industry. We believe thecoverage and types of insurance are adequate. The occurrence of a significant adverse event that is not fully covered by insurance could result in the loss ofour total investment in a particular prospect which could have a material adverse effect on financial condition and results of operations. Failure to adequately protect critical data and technology systems could materially affect our operations. Information technology solution failures, network disruptions and breaches of data security could disrupt our operations by causing delays orcancellation of customer orders, impeding processing of transactions and reporting financial results, resulting in the unintentional disclosure of customer,employee or our information, or damage to our reputation. A system failure or data security breach could have a material adverse effect on our financialcondition, results of operations or cash flows. 30  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 will be dependent upon partnering arrangements. As of December 31, 2016, we had nineteen full-time employees and two part-time employees. We leverage the services of independent consultantsand contractors to perform various professional services, including engineering, oil and gas well planning and supervision, and land, legal, environmentaland tax services. We also pursue alliances with partners in the areas of geological and geophysical services and prospect generation, evaluation and prospectleasing. Our dependence on third-party consultants and service providers creates a number of risks, including but not limited to: ·the possibility that such third parties may not be available to us as and when needed; and·the risk that we may not be able to properly control the timing and quality of work conducted with respect to our projects. If we experience significant delays in obtaining the services of such third parties or poor performance by such parties, our results of operations andstock 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 Abraham Mirman, our Chief Executive Officer andother executive officers and key employees. These individuals have extensive experience and expertise in evaluating and analyzing producing oil andnatural gas properties and drilling prospects, maximizing production from oil and natural gas properties, marketing oil and natural gas production anddeveloping and executing financing and hedging strategies. The loss of any of these individuals could have a material adverse effect on operations. We donot maintain key-man life insurance with respect to any of our employees. Our success will be dependent on our ability to continue to employ and retainskilled 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, properties, prospects and leaseholds. The successful acquisition ofproducing properties requires an assessment of several factors, including: ·recoverable reserves;·future oil and natural gas prices and their appropriate differentials;·well and facility integrity;·development and operating cost;·regulatory constraints and plans; and·potential environmental and other liabilities. 31  The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties. Ourreview will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess theirdeficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarilyobservable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractualprotection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties onan “as is” basis. Significant acquisitions 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. 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 would place a strain on our financial, technical, operational and managementresources. The failure to continue to upgrade our technical, administrative, operating and financial staff and control systems or the occurrences ofunexpected expansion difficulties, including the failure to recruit and retain experienced managers, geologists, engineers and other professionals in the oiland gas industry could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute ourbusiness plan. We may face difficulties in securing and operating under authorizations and permits to drill, complete or operate our wells. The recent growth in oil and gas exploration in the United States has drawn intense scrutiny from environmental and community interest groups,regulatory agencies and other governmental entities. As a result, we may face significant opposition to, or increased regulation of, our operations, that maymake it difficult or impossible to obtain permits and other needed authorizations to drill, complete or operate, result in operational delays, or otherwise makeoil and gas exploration more costly or difficult than in other countries. Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with operating in one majorgeographic area. Most of our producing properties are geographically concentrated in the Permian Basin of West Texas. As a result of this concentration, we may bedisproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused bygovernmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations orinterruption of the processing or transportation of oil, natural gas or natural gas liquids. In addition, the effect of fluctuations on supply and demand maybecome more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions tooccur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of ourproperties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they mighthave on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on ourfinancial condition and results of operations. 32  We operate in areas of high industry activity, which may affect our ability to hire, train or retain qualified personnel needed to manage and operate ourassets. Our operations and drilling activity are concentrated in the Permian Basin in West Texas, an area in which industry activity has remained relativelysteady despite the recent downturn in commodity prices. As a result, demand for qualified personnel in this area, and the cost to attract and retain suchpersonnel, has continued to be competitive, and would be expected to increase substantially in the future if commodity prices rebound. Moreover, ourcompetitors may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development activities could resultin oil and gas production volumes being below our forecasted volumes. In addition, any such negative effect on production volumes, or significant increasesin costs, could have a material adverse effect on our results of operations, liquidity and financial condition. 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 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 gas sources. Some of those sources are alreadyregulated under NSPS OOOO, while others, like hydraulically fractured oil wells, pneumatic pumps, and certain equipment and components at compressorstations, are covered for the first time. On March 10, 2016, moreover, the EPA announced that it is moving towards issuing performance standards for methaneemissions from existing oil and gas sources. The agency said that it will “begin with a formal process (i.e., an Information Collection Request) to requirecompanies operating existing oil and gas sources to provide information to assist in the development of comprehensive regulations to reduce methaneemissions.” On November 10, 2016, the EPA issued the Information Collection Request (“ICR”) and explained that “[r]ecipients of the operator survey (alsoreferred 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 to the agency.” 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. 33  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 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, NGLs, and natural gas 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 gas contained in the rocks. We routinely use hydraulic fracturing techniques inmany of our drilling and completion programs. The process is typically regulated by state oil and natural gas commissions, but the EPA, under the federalSafe Drinking Water Act, has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel. The Bureau of Land Management (“BLM”), on March 20, 2015, issued its final regulations for hydraulic fracturing on federal and tribal lands. Thenew regulations require, among other things, disclosure of chemicals, annulus pressure monitoring, flow back and produced water management and storage,and more stringent well integrity measures associated with hydraulic fracturing operations on public land. On June 21, 2016, however, the U.S. District Courtfor the District of Wyoming enjoined BLM from enforcing the regulations, concluding that the agency lacked the authority to issue them. BLM appealed thatdecision to the U.S. Court of Appeals for the Tenth Circuit. The appeal is pending. 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 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. 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. 34  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 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 gas facilities. The EPA granted the petition in part, by agreeingto 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, in light of thatdecision, the environmental advocacy groups that had commenced the lawsuit opted to voluntarily dismiss it. On January 6, 2017, EPA issued a proposedrulemaking 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 gas and oil. Future legislation may result in the elimination of certain U.S. federal income tax deductions currently available with respect to oil and natural gasexploration and production. Additionally, future federal or state legislation may impose new or increased taxes or fees on oil and natural gas extraction. Potential legislation, if enacted into law, could make significant changes to U.S. federal and state income tax laws, including the elimination ofcertain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. These changes include, but are notlimited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties; (ii) the elimination of current deductions for intangibledrilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization periodfor certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any suchchanges could become effective. The passage of this legislation or any other similar changes in U.S. federal and state income tax laws could eliminate orpostpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change couldnegatively affect our financial condition and results of operations. Additionally, legislation could be enacted that increases the taxes states impose on oil andnatural gas extraction. 35  Moreover, as part of the Budget of the United States Government for Fiscal Year 2017, there was a proposal to impose an “oil fee” of $10.25 on a perbarrel equivalent of crude oil. This fee would be collected on domestically produced and imported petroleum products. The fee would be phased in evenlyover five years, beginning October 1, 2016. The adoption of this, or similar proposals, could result in increased operating costs and/or reduced consumerdemand for petroleum products, which in turn could affect the prices we receive for our oil. Any of these tax changes could have a material impact on ourfinancial performance. 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;·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 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 andproduction and processing activities, including environmental regulations governing the withdrawal, storage and use of surface water orgroundwater necessary for 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. 36  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 the NGA to impose penalties for currentviolations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our operations have not beenregulated 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 the CFTC prohibits market manipulation in the markets regulated by the CFTC, including similar anti-manipulation authority with respect to crude oil swaps and futures contracts as that granted to the CFTC with respect to crude oil purchases and sales. TheCFTC rules subject violators to a civil penalty of up to the greater of $1 million or triple the monetary gain to the person for each violation. Failure to complywith those regulations in the future could subject us to civil penalty liability, as described in “Business-Regulation of the Oil and Natural Gas Industry.” Risks Relating to Our Securities Our common stock may be subject to penny stock rules which limit the market for our common stock. Our shares of common stock likely qualify as “penny stock” under the SEC rules. Sales and purchases of “penny stock” generally require moredisclosures by broker-dealers and satisfaction of other administrative requirements. As a result, broker-dealers may be less willing to execute transactions insecurities subject to the “penny stock” rules. This may make it more difficult for investors to dispose of our common stock and cause a decline in the marketvalue of our stock. There is a limited public market for our common stock and an active trading market or a specific share price may not be established or maintained. On May 26, 2016, our common stock was suspended from trading on the Nasdaq and immediately began trading on the OTCQB VentureMarketplace, or the OTCQB. On July 29, 2016, the Nasdaq announced that it will delist our common stock and file a Form 25 with the Securities andExchange Commission. The Form 25 was subsequently filed on August 1, 2016, and the delisting became effective on August 11, 2016. We have applied forrelisting on the Nasdaq and are working to show full compliance with all applicable Nasdaq initial listing criteria. While our common stock trades on the OTCQB, trading activity in our common stock generally occurs in small volumes each day. The value of ourcommon stock could be affected by: ·actual or anticipated variations in our operating results;·the market price for crude oil;·changes in the market valuations of other oil and gas companies;·announcements by us or our competitors of significant acquisitions, strategic partnerships, joint ventures or capital commitments;·adoption of new accounting standards affecting our industry;·additions or departures of key personnel;·sales of our common stock or other securities in the open market;·actions taken by our lenders or the holders of our convertible debentures;·changes in financial estimates by securities analysts;·conditions or trends in the market in which we operate;·changes in earnings estimates and recommendations by financial analysts;·our failure to meet financial analysts’ performance expectations; and·other events or factors, many of which are beyond our control. 37  In a volatile market, you may experience wide fluctuations in the market price of our common stock. These fluctuations may have an extremelynegative effect on the market price of our common stock and may prevent you from obtaining a market price equal to your purchase price when you attemptto sell our common stock in the open market. In these situations, you may be required either to sell at a market price which is lower than your purchase price,or to hold our common stock for a longer period of time than you planned. An inactive market may also impair our ability to raise capital by selling shares ofcapital stock and may impair our ability to acquire other companies or oil and gas properties by using our common stock as consideration. If an orderly and active trading market for our securities does not develop or is not sustained, the value and liquidity of your investment in our securitiescould be adversely affected. An active or liquid market in our common stock or securities exercisable or convertible for our common stock does not currently exist and might notdevelop or, if it does develop, it might not be sustainable. The last reported sale price of our common stock on the OTCQB on March 1, 2017 was $4.00 pershare. The historic bid and ask quotations for our common stock, however, should not be viewed as an indicator of the current or historical market price forour common stock nor as an indicator of the market price for our common stock if our common stock were to be listed on a national securities exchange. Theoffering price for our securities as issued by us from time to time is determined through discussions between us and the prospective investor(s), with referenceto the most recent closing price of our common stock on the OTCQB, and may vary from the market price of our securities following any offering. Further, ourtrading volume on the OTCQB has been generally very limited. If an active public market for our common stock develops, we expect the market price may be volatile, which may depress the market price of our securitiesand result in substantial losses to investors if they are unable to sell their securities at or above their purchase price. If an active public market for our common stock develops, we expect the market price of our securities to fluctuate substantially for the foreseeablefuture, 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. Further, our common stock is currently quoted on the OTCQB, which is often characterized by low trading volume and by wide fluctuations intrading prices due to many factors that may have little to do with our operations or business prospects. The availability of buyers and sellers represented bythis volatility could lead to a market price for our common stock that is unrelated to operating performance. Moreover, the OTCQB is not a stock exchange,and trading of securities quoted on the OTCQB is often more sporadic than the trading of securities listed on a national securities exchange like TheNASDAQ Stock Market or the New York Stock Exchange. While we are currently seeking to list our securities on a national securities exchange, there is noassurance we will be able to do so, and if we do so, many of these same forces and limitations may still impact our trading volumes and market price in thenear term. Additionally, the sale or attempted sale of a large amount of common stock into the market may also have a significant impact on the trading priceof 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. 38  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 shareholders. 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 two series of preferred stock issued and outstanding, both of which provide its holders with aliquidation preference and prohibit the payment of dividends on junior securities, including our Common Stock, 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. Forexample, the conversion of the remaining Series B preferred stock in full could result in the issuance of 15,454,545 shares of common stock, and the exerciseof outstanding warrants could result in the issuance of 15,915,511 shares of common stock. To the extent outstanding restricted stock units, warrants oroptions to purchase our common stock under our employee and director stock option plans are exercised, the price vesting triggers under the performanceshares granted to our executive officers are satisfied, or additional shares of restricted stock are issued to our employees, holders of our Common Stock willexperience dilution. Furthermore, if we sell additional equity or convertible debt securities, such sales could result in further dilution to our existingstockholders and cause the price of our outstanding securities to decline. We do not expect to pay dividends on our common stock. We have never paid dividends with respect to our common stock, and we do not expect to pay any dividends, in cash or otherwise, in the foreseeablefuture. We intend to retain any earnings for use in our business. In addition, our Credit Agreement prohibits us from paying any dividends and the indenturegoverning our senior notes restricts our ability to pay dividends. In the future, we may agree to further restrictions. Any return to shareholders will thereforebe limited to the appreciation of their stock. Securities analysts may not initiate coverage of our shares or may issue negative reports, which may adversely affect the trading price of the shares. Securities analysts may not provide research reports on our company. If securities analysts do not cover our company, this 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. Our Series B preferred stock accrues a dividend, and we may be required to issue additional shares of Series B preferred stock upon the occurrence ofcertain events. The Series B preferred stock accrues a dividend, payable quarterly in arrears (based on calendar quarters), in the amount of 6% per annum of theoriginal issuance price of the Series B preferred stock. The dividend is payable by an increase to the stated value of the Series B preferred stock or in-kind inSeries B preferred stock or in cash, at our election. We may not have sufficient available cash to pay the dividends as it accrues. The payment of the dividends, or our failure to timely pay thedividends when due, could reduce our available cash on hand, have a material adverse effect on our results of operations and cause the value of our stock todecline in value. Additionally, any increase in stated value, which would result in the issuance of additional shares of Series B preferred stock in lieu of cashdividends (and the subsequent conversion of such Series B preferred stock into common stock pursuant to the terms of such Series B preferred stock) couldcause substantial dilution to the then holders of our common stock. The issuance and sale of common stock upon conversion of the Series B Preferred Stock and the exercise of warrants received in those transactions, maydepress the market price of our common stock. If conversions of the Series B preferred stock and exercises of warrants received in those transactions, sales of such converted securities take place,the price of our common stock may decline. In addition, the common stock issuable upon conversion of such securities may represent overhang that may alsoadversely affect the market price of our common stock. Overhang occurs when there is a greater supply of a company’s stock in the market than there isdemand for that stock. When this happens the price of our company’s stock will decrease, and any additional shares which shareholders attempt to sell in themarket will only further decrease the share price. If the share volume of our common stock cannot absorb converted shares sold by the Series B preferred stockholders, then the value of our common stock will likely decrease. 39  Anti-takeover effects of certain provisions of Nevada state law hinder a potential takeover of our company. Though not now, in the future we may become subject to Nevada’s control share law. A corporation is subject to Nevada’s control share law if it hasmore than 200 stockholders, at least 100 of whom are stockholders of record and residents of Nevada, and it does business in Nevada or through an affiliatedcorporation. The law focuses on the acquisition of a “controlling interest” which means the ownership of outstanding voting shares sufficient, but for thecontrol share law, to enable the acquiring person to exercise the following proportions of the voting power of the corporation in the election of directors: (i)one-fifth or more but less than one-third, (ii) one-third or more but less than a majority, or (iii) a majority or more. The ability to exercise such voting powermay be direct or indirect, as well as individual or in association with others. The effect of the control share law is that the acquiring person, and those acting in association with it, obtains only such voting rights in the controlshares as are conferred by a resolution of the stockholders of the corporation, approved at a special or annual meeting of stockholders. The control share lawcontemplates that voting rights will be considered only once by the other stockholders. Thus, there is no authority to strip voting rights from the controlshares of an acquiring person once those rights have been approved. If the stockholders do not grant voting rights to the control shares acquired by anacquiring person, those shares do not become permanent non-voting shares. The acquiring person is free to sell its shares to others. If the buyers of thoseshares themselves do not acquire a controlling interest, their shares do not become governed by the control share law. If control shares are accorded fullvoting rights and the acquiring person has acquired control shares with a majority or more of the voting power, any stockholder of record, other than anacquiring person, who has not voted in favor of approval of voting rights is entitled to demand fair value for such stockholder’s shares. Nevada’s controlshare law may have the effect of discouraging takeovers of the corporation. In addition to the control share law, Nevada has a business combination law which prohibits certain business combinations between Nevadacorporations and “interested stockholders” for three years after the “interested stockholder” first becomes an “interested stockholder,” unless thecorporation’s board of directors approves the combination in advance. For purposes of Nevada law, an “interested stockholder” is any person who is (i) thebeneficial owner, directly or indirectly, of ten percent or more of the voting power of the outstanding voting shares of the corporation, or (ii) an affiliate orassociate of the corporation and at any time within the three previous years was the beneficial owner, directly or indirectly, of ten percent or more of thevoting power of the then outstanding shares of the corporation. The definition of the term “business combination” is sufficiently broad to cover virtually anykind of transaction that would allow a potential acquirer to use the corporation’s assets to finance the acquisition or otherwise to benefit its own interestsrather than the interests of the corporation and its other stockholders. The effect of Nevada’s business combination law is to potentially discourage partiesinterested in taking control of our company from doing so if it cannot obtain the approval of our Board of Directors. 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 any currentlypending 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. 40  PART II Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Recent Market Prices We began trading on the OTCQB Venture Marketplace under the symbol “LLEX” on May 27, 2016. From February 11, 2016 to May 26, 2016, ourcommon stock traded on The Nasdaq Capital Market (“Nasdaq”) under the symbol “LLEX.” Prior February 11, 2016, our common stock traded on the NasdaqGlobal Market under the symbol “LLEX.” We have applied for relisting on the Nasdaq and are working to show full compliance with all applicable Nasdaqinitial listing criteria. 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 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 2015 Fourth Quarter $7.00 $0.70 Third Quarter $31.50 $4.80 Second Quarter $19.00 $7.40 First Quarter $12.60 $6.00 As of March 1, 2017, there were 135 owners of record of our common stock. We estimate that there are approximately 1,833 beneficial holders of ourcommon stock Dividend Policy We have never paid any cash dividends on our common stock and do not anticipate paying any dividends in the foreseeable future. Our currentbusiness plan is to retain any future earnings to finance the expansion and development of our business. Any future determination to pay cash dividends willbe at the discretion of our Board of Directors, and will be dependent upon our financial condition, results of operations, capital requirements and other factorsas our board may deem relevant at that time. In addition, we are currently restricted from declaring any dividends pursuant to the terms of our CreditAgreement and outstanding preferred stock. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—“Liquidity and Capital Resources.” 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, 2016. Equity Compensation Plans Information regarding equity compensation plans is set forth in Item 12 of this Annual Report on Form 10-K and is incorporated herein by reference. Item 6. Selected Financial Data Not applicable. 41  Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidatedfinancial statements and related notes in “Part II, Item 8. Financial Statements and Supplementary Data.” The following discussion and analysis containsforward-looking statements, including, without limitation, statements relating to our plans, strategies, objectives, expectations, intentions and resources.Please see “Cautionary Statement Concerning Forward-Looking Statements” and “Part I, Item 1A. Risk Factors” in this Annual Report on Form 10-K. General We are an independent oil and gas company engaged in the acquisition, drilling and production of oil and natural gas properties and prospects. Wewere incorporated in August of 2007 in the State of Nevada as Universal Holdings, Inc. In October 2009, we changed our name to Recovery Energy, Inc. andin December 2013, we changed our name to Lilis Energy, Inc. On June 23, 2016, we completed a merger (the “Merger”) with Brushy Resources, Inc. (“Brushy”), which resulted in the acquisition of our propertiesin the Delaware Basin as well as the majority of our current operating activity. Additionally, in connection with the Merger on June 23, 2016, we effected a 1-for-10 reverse stock split. As a result of the reverse split, every tenshares of issued and outstanding common stock were automatically converted into one newly issued and outstanding share of common stock, without anychange in the par value per share. However, the number of authorized shares of common stock remained unchanged. Shortly after the Merger, we began to develop a drilling program on our properties using hydraulic fracture stimulation techniques across multipleproductive horizons. Our primary focus is drilling horizontal wells in the Delaware Basin of West Texas, which we believe will provide attractive returns on amajority of our acreage position. Our goal is to earn economic returns to our shareholders through cash flow from new production of oil, natural gas andNGLs, as well as through derisking the development profile of our portfolio of properties in order to add overall value. Our drilling program utilizes thedevelopment of new horizontal wells across several potentially productive formations in the Delaware Basin, with an initial focus on targeting the Wolfcampformation. We drilled our first horizontal well in late 2016 and completed it in 2017. Overview of Our Business and Strategy We are an oil and natural gas company, engaged in the acquisition, development and production of unconventional oil and natural gas properties.We have accumulated approximately 6,924 net acres in what we believe to be the core of the Delaware Basin in Winkler and Loving Counties, Texas and LeaCounty, New Mexico. Our leasehold position is largely contiguous, allowing us to maximize development efficiency, manage full cycle finding costs andpotentially enabling us to generate higher returns for our shareholders. In addition, 68% of our acreage position is held by production, and we are the namedoperator on 100% of our acreage. These two characteristics give us control over the pace of development and the ability to design a more efficient andprofitable drilling program that maximizes recovery of hydrocarbons. We expect that substantially all of our estimated 2017 capital expenditure budget willbe focused on the development and expansion of our Delaware Basin acreage and operations. We also plan to continue to selectively and opportunisticallypursue strategic bolt-on acreage acquisitions in the Delaware Basin. We generate the vast majority of our revenues from the sale of oil for our producing wells. The prices of oil and natural gas are critical factors to oursuccess. Volatility in the prices of oil and natural gas could be detrimental to our results of operations. Our business requires substantial capital to acquireproducing properties and develop our non-producing properties. As the price of oil declines and causes our revenues to decrease, we generate less cash toacquire new properties or develop our existing properties and the price decline may also make it more difficult for us to obtain any debt or equity financingto supplement our cash on hand. Our Board has approved a drilling program of up to 10 gross Delaware Basin wells (6 net) that is contingent upon our access to sufficient capital tofully execute. In the first quarter of 2017, we completed two wells, and we have begun drilling a third well. We expect our 2017 horizontal drilling programwill be focused almost exclusively on the Wolfcamp zone of the Delaware Basin, with lateral lengths ranging from approximately 5,000’ laterals to 7,000’laterals. 42  Based upon current commodity price expectations for 2017, we believe that our cash flow from operations, combined with the proceeds of ourrecently completed equity offering, proceeds from the conversion of in-the-money warrants to equity, and availability under our Credit Facility, will besufficient to fund our operations for 2017, including working capital requirements. However, future cash flows are subject to a number of variables, includinguncertainty in forecasted production volumes and commodity prices. We are the operator for 100% of our 2017 operational capital program and, as a result,the amount and timing of a substantial portion of our capital expenditures is discretionary. Accordingly, we may determine it prudent to curtail drilling andcompletion operations due to capital constraints or reduced returns on investment as a result of commodity price weakness. The results of operations of Brushy are included with those of ours from June 23, 2016 through December 31, 2016. As a result, results of operationsfor the year ended December 31, 2016 are not necessarily comparable to the results of operations for prior periods. Additionally, all discussion related tohistorical representations of common stock, unless otherwise noted, give retroactive effect to the reverse split for all periods presented. Results of Operations Results of operations for the year ended December 31, 2016 compared to the year ended December 31, 2015 The following table compares operating data for the years ended December 31, 2016 and 2015 (in thousands): Years Ended December 31, 2016 2015 Variance % (In Thousands) Revenue: Oil $2,418 $292 $2,126 728%Gas 1,012 77 935 1214%Other 5 27 (22) -81% $3,435 $396 $3,039 767% Total Revenue Total revenue was approximately $3.4 million ($1.8 million from Brushy) for the year ended December 31, 2016 as compared to $0.4 million for theyear ended December 31, 2015, representing an increase of approximately $3.0 million or 767%. The increase in revenue was primarily attributable toapproximately $1.8 million in revenues from Brushy’s operations during the second half of 2016 and increase of approximately $1.2 million in revenuesfrom the DJ Basin due to increase in production volumes. The following table compares production volumes and average prices for the years ended December 31, 2016 and 2015: For the Year Ended December 31, 2016 2015 Product Oil (Bbl.) 61,088 7,067 Oil (Bbls)-average price $39.59 $41.36 Natural Gas (MCFE)-volume 400,775 32,291 Natural Gas (MCFE)-average price $2.54 $2.39 Barrels of oil equivalent (BOE) 127,863 12,449 Average daily net production (BOE) 350 34 Average Price per BOE $26.87 $29.67 43  Oil and Gas Production Costs, Production Taxes, Depreciation, Depletion, and Amortization The following tables compares oil and gas production costs, production taxes, depreciation, depletion, and amortization for the years ended December 31,2016 and 2015: For the Year Ended December 31, 2016 2015 Production costs per BOE $9.75 $15.70 Production taxes per BOE (1.30) 2.24 Depreciation, depletion, and amortization per BOE 12.25 46.93 Total operating costs per BOE $20.70 $64.87 Gross margin per BOE $6.17 $(35.20)Gross margin percentage 23% (119)% Years Ended December 31, 2016 2015 Variance % (In Thousands) Costs and expenses: Production costs $1,247 $195 $1,052 539%Production taxes (167) 28 (195) -696%General and administrative 14,570 7,930 6,640 84%Depreciation, depletion and amortization 1,566 574 992 173%Accretion of asset retirement obligations 132 10 122 1220%Impairment of evaluated oil and gas properties 4,718 24,478 (19,760) -81%Total operating expenses 22,066 33,215 (11,149) -34% Loss from operations $(18,631) $(32,819) $14,188 -43% Production Costs Production costs were $1.2 million for the year ended December 31, 2016, compared to $0.2 million for the year ended December 31, 2015, anincrease of $1 million or 539%. The increase is primarily attributable to Brushy’s operations. Production costs per BOE decreased to $9.75 for the year endedDecember 31, 2016 from $15.70 in 2015, a decrease of $5.95 per BOE, or 38%, primarily due to Brushy’s lower production costs. The Company anticipatesthat its production costs in the near term would be closer to the level of Brushy’s historical production costs. Production Taxes Production taxes were $(0.2) million for the year ended December 31, 2016, compared to $0.03 million for the year ended December 31, 2015, adecrease of $(0.2) million or -696%. Currently, ad valorem, severance and conservation taxes range from 1% to 13% based on the state and county fromwhich production is derived. Production taxes per BOE decreased to $(1.30) during the year ended December 31, 2016 from $2.24 in 2015, a decrease of$(3.54) or -158%. Subsequent to the issuance of our consolidated financial statements for the year ended December 31, 2016, we determined that certain advalorem and severance tax estimates were higher than the actual amount billed, resulting in a tax benefit to us. General and Administrative Expenses General and administrative expenses were $14.5 million during the year ended December 31, 2016, compared to $7.9 million during the year endedDecember 31, 2015, an increase of $6.6 million, or 84%. The increase of $6.6 million in general and administrative expenses was attributable to an increaseof $3.9 million to $7.1 million in non-cash stock-based compensation expense, a $0.6 million increase in legal fees associated with the Merger, an increase of$1.5 million in payroll primarily due to the addition of 18 former Brushy employees, bonuses paid to officers at the completion of the Merger and an increaseof $0.6 million in other administrative office expenses. 44  Depreciation, Depletion, and Amortization Depreciation, depletion, and amortization (“DD&A”) was $1.6 million during the year ended December 31, 2016, compared to $0.6 million duringthe year ended December 31, 2015, an increase of $1.0 million, or 173%. The increase in DD&A was the result of the increase in production associated withthe acquisition of the oil and gas properties in the Delaware Basin, New Mexico and Winkler County, Texas after the Merger. As a result of the Merger, ourDD&A rate decreased to $12.25 per BOE in 2016 from $46.93 per BOE in 2015. The DD&A rate decreased primarily due to the volumes increase of 115,414barrels, or 927% from 12,449 BOE in 2015. Impairment of Evaluated Oil and Gas Properties Total impairment charges of $4.7 million were recorded during year ended December 31, 2016 as compared to $24.5 million during the year endedDecember 31, 2015, a decrease of $19.8 million or 81%. The decrease of $19.8 million was primarily due to full cost limitations recognized in the first andthird quarter of 2015. The impairment expense of $24.5 million in 2015 was attributable to the write off of our proved undeveloped oil and gas properties inthe DJ Basin due to lack of available capital to fund development coupled with significant decrease in oil prices, and to a lesser extent, natural gas prices,that started in late 2014 and continued throughout 2015. Years Ended December 31, 2016 2015 Variance % (In Thousands) Other income (expenses): Other income 90 3 87 2900%Debt conversion inducement expense (8,307) - (8,307) -% Gain on extinguishment of debt 250 - 250 -% Gain (loss) in fair value of derivative instruments (1,222) 1,638 (2,860) -175%Gain (loss) in fair value of conditionally redeemable 6% preferred stock (701) 514 (1,215) -236%Gain on modification of convertible debts 602 - 602 -% Interest expense (4,924) (1,697) (3,227) 190%Total other income (expenses) (14,212) 458 (14,670) -3203% Net loss (32,843) (32,361) (482) 1% Inducement Expense During the year ended December 31, 2016, an inducement expense of approximately $8.3 million was incurred as a result of debt and equityrestructuring associated with the Merger. The inducement expense resulted from the repricing of our warrants to induce conversion of our convertible debtand our Series A preferred stock into common stock. Gain on Extinguishment of Debt During the year ended December 31, 2016, we recognized a gain of approximately $0.3 million attributed to a discount from Heartland Bank tosettle the outstanding balance we owed under the Heartland Credit Agreement. Change in Fair Value in Derivative Instruments The change in fair values of derivative instruments comprised a loss of approximately $1.2 million during the year ended December 31, 2016, ascompared to an approximately $1.6 million gain during the year ended December 31, 2015, is as follows: ·Bristol Warrant Liabilities. On September 2, 2014, we entered into a Consulting Agreement with Bristol Capital, LLC (“Bristol”), pursuant to whichwe issued to Bristol a warrant to purchase up to 100,000 shares of our common stock at an exercise price of $20.00 per share (or, in the alternative,100,000 options, but in no case both). The agreement has a price protection feature that will automatically reduce the exercise price if we enter intoanother consulting agreement pursuant to which warrants are issued with a lower exercise price, which triggered in year 2016 and accordingly, theCompany agreed to issue additional warrants/options to purchase 541,026 shares of common stock at a revised exercise price of $3.12. The changein fair value of this warrant provision was a loss of $1.2 million and a gain of $0.4 million for the years ended December 31, 2016 and 2015,respectively. 45  ·Heartland Warrant Liability. On January 8, 2015, we entered into the Heartland Credit Agreement. In connection with the Heartland CreditAgreement, we issued to Heartland a warrant to purchase up to 22,500 shares of our common stock at an exercise price of $25.00. The warrantcontains a price protection feature that will automatically reduce the exercise price if we enter into another agreement pursuant to which warrants areissued with a lower exercise price. The change in fair value valuation from issuance was $0.03 million and $0.01 million for the year endedDecember 31, 2016 and 2015, respectively. ·SOSV Investments LLC Warrant Liability. On June 23, 2016, in conjunction with the Merger, we issued to SOSV Investments LLC (“SOS”) a warrantto purchase up to 200,000 shares of our common stock at an exercise price of $25.00. The warrant contains a price protection feature that willautomatically reduce the exercise price if we enter into another agreement pursuant to which warrants are issued with a lower exercise price. For theyear ended December 31, 2016, we incurred a change in the fair value of the derivative liability related to the warrant of approximately $0.1 million. Interest Expense For the years ended December 31, 2016 and 2015, we incurred an interest expense of approximately $4.9 million and $1.7 million, respectively, ofwhich approximately $4.2 million and $1.3 million was classified as non-cash interest expense in 2016 and 2015, respectively. The details of the non-cashinterest expense for the year ended December 31, 2016 are as follows: (i) accretion of $3.9 million of discount associated with bridge loans, convertible notes,the credit facility and term loan and (ii) amortization of the deferred financing costs of $0.3 million. The non-cash interest expense for the year endedDecember 31, 2015 was primarily attributable to the amortization of the deferred financing costs of approximately $0.1 million. At the current levels of net oil and gas production, cash balances, interest rates, and oil and gas prices, our revenue is unlikely to exceed ourexpenses. Unless and until we invest a substantial portion of our cash balances in interests in producing oil and gas wells or in one or more other ventures thatproduce revenue and net income, we are likely to experience net losses. With the exception of unanticipated environmental expenses and possible changes ininterest rates and oil and gas prices, we are not aware of any other trends, events, or uncertainties that have had or that are reasonably expected to have amaterial impact on net sales or revenues or income from continuing operations. 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 derivative securities and asset dispositions. Our primary uses of capital have been for the acquisition, development, exploration and exploitation of oiland natural gas properties, in addition to refinancing of debt instruments. In 2016, we entered into a new Credit Agreement and completed a preferred stockoffering to raise additional capital. We regularly evaluate alternative sources of capital to complement our cash flow from operations and other sources ofcapital as we pursue our long-term growth plans in the Delaware Basin. In order to fully fund our 2017 capital budget, we may be required to access to newcapital through one or more offerings of equity. We have reported net operating losses during the year ended December 31, 2016 and for the past five years. As a result, we funded our operations in2016 and the merger with Brushy Resources, Inc. through additional debt and equity financing. On September 29, 2016, we entered into a new Credit andGuaranty Agreement (the “Credit Agreement”) that provides for a three-year, senior, secured term loan with initial aggregate principal commitments of $31million and a maximum facility size of $50 million. The initial commitment on the term loan was funded with $25 million collected as of September 30,2016 and the additional $6 million collected as of November 11, 2016. As of December 31, 2016, the Company had a working capital balance and a cash balance of approximately $5.7 million and $11.5 million,respectively. As of March 1, 2017, after giving effect to a drawdown of $7.1 million in additional term loan debt under the Credit Agreement on February 7,2017, but excluding, the commitments entered into in connection with the March 2017 Private Placement (defined below) our cash balance wasapproximately $9.0 million. We believe that we will have sufficient capital to operate over the next 12 months. However, it is possible that we will seek toraise additional debt and equity capital depending on the pace of our drilling and leasing activity. 46  Information about our year-end cash flows are presented in the following table (in thousands): Year ended December 31, 2016 2015 Cash provided by (used in): Operating activities $(6,309) $(3,951)Investing activities (19,130) (1,703)Financing activities 37,067 5,254 Net change in cash $11,628 $(400) Operating activities. For the year ended December 31, 2016, net cash used in operating activities was $6.3 million, compared to $4.0 million for the sameperiod in 2015. The increase of $2.3 million cash used in operating activities was primarily attributable to the increase in operating costs and changes inworking capital. Investing activities. For the year ended December 31, 2016, net cash used in investing activities was $19.1 million compared to $1.7 million for the sameperiod in 2015. The $17.4 million increase in cash used in investing activities was primarily attributable to the following: ·a $7.5 million increase in drilling and completion costs on the Grizzly and Bison wells;·a $4.2 million increase in oil and gas lease extension fees;·a $2.3 million cash consideration for the Merger, net of cash acquired; and·a $3.4 million increase on other capital expenditures relating to the DJ Basin and the Delaware Basin properties. Financing activities. For the year ended December 31, 2016, net cash provided by financing activities was $37.1 million compared to cash provided byfinancing activities of $5.3 million during the same period of 2015. The increase of $31.8 million in net cash provided by financing activities was primarilyattributable to the following: ·an $18.2 million increase in net proceeds from the issuance of the Series B preferred stock;·a $30.0 million increase in net proceeds from the term loan facility executed during the third quarter of 2016;·a $0.3 million increase in proceeds received from the exercise of stock warrants;·offset by a $3.1 million decrease in net proceeds from the Bridge Loans; and·offset by an increase of $13.6 million in repayment of principal balances due to the Heartland Bank and Independent Bank. Merger with Brushy We paid deposits and operating expenses of Brushy toward completion of the Merger of approximately $3.0 million, net of $0.7 million cashacquired, which is recorded as additional consideration. In connection with the closing of the Merger, we entered into the following financing transactions: Series A Preferred Stock Conversion On June 23, 2016, after receiving the requisite shareholder approval and upon consummation of the Merger, each outstanding share of our Series Apreferred stock automatically converted into common stock at a conversion price of $5.00 resulting in the issuance of 1,500,000 shares of common stock. Inexchange for the reduction in price to convert into our common stock, all accrued, but unpaid dividends were forfeited. 47  Series B 6% Preferred Stock On June 15, 2016, we entered into a private placement to sell 20,000 shares of our Series B 6% convertible preferred stock (the “Series B PreferredStock”) with a conversion price of $1.10 and warrants to purchase up to 9,090,926 shares of common stock at an exercise price of $2.50, exercisableimmediately for a period of two years under certain circumstances, for gross proceeds of $20 million. For a more detailed description of the terms of the SeriesB Preferred Stock see Note 13-Shareholders Equity. In connection with the Series B Preferred Stock offering, we also paid a fee of $350,000 and $900,000 to T.R. Winston & Company, LLC (“TRW”)and KES 7 Capital Inc. (“KES 7”), respectively, who acted as co-placement agents with TRW also acting as administrative agent. Each of TRW and KES 7also received fee warrants to purchase up to 452,724 and 820,000 shares of common stock, respectively, at an exercise price of $1.30, exercisable on or afterSeptember 17, 2016, for a period of two years. In addition, TRW received 150 shares of Series B Preferred Stock and the related warrants to purchase 68,182shares of common stock at an exercise price of $2.50. Debentures On June 23, 2016, pursuant to the terms of the Debenture Conversion Agreement, dated as of December 29, 2015, our remaining outstanding 8%Convertible Debentures converted automatically upon consummation of the Merger at $5.00 per share, resulting in the issuance of 1,369,293 shares ofcommon stock. In exchange for the lowering the conversion price, all accrued but unpaid interest was forfeited. The modification of such conversion rateresulted in an immaterial gain. The Convertible Debentures and associated derivative liability was then reclassified to additional paid-in capital. Heartland Bank On January 8, 2015, we entered into the Credit Agreement with Heartland Bank (the “Heartland Credit Agreement”), as administrative agent and theLenders party thereto. The Heartland Credit Agreement provided for a three-year senior secured term loan in an initial aggregate principal amount of$3,000,000 (the “Heartland Term Loan”). In connection with the consummation of the Merger, on June 22, 2016, we repaid the balance of our outstanding indebtedness with Heartland at adiscount of $250,000, resulting in the elimination of $2.75 million in senior secured debt and the extinguishment of Heartland’s security interest in ourassets. Independent Bank and Promissory Note On June 22, 2016, in connection with the completion of the Merger, we entered into an amendment with Brushy and its senior secured lender,Independent Bank (the “Lender”), to Brushy’s Forbearance Agreement with the Lender (the “Fourth Amendment”), which, among other things, provided for apay-down of $6.0 million of the principal amount outstanding on the loan (the “Loan”), plus fees and other expenses incurred in connection with the Loan,in exchange for an extension of the maturity date through December 15, 2016, at an interest rate of 6.5%, payable monthly. Additionally, we agreed to (i)guaranty the approximately $5.4 million aggregate principal amount of the Loan, (ii) grant a lien in favor of the Lender on all of our real and personalproperty, (iii) restrict the incurrence of additional debt and (iv) maintain certain deposit accounts with various restrictions with the Lender. As a condition of the Fourth Amendment and pursuant to the Merger Agreement, Brushy also completed the divestiture of certain of its assets inSouth Texas to its subordinated lender, SOS Ventures (“SOS”), in exchange for the extinguishment of $20.5 million of subordinated debt, a cash payment of$500,000, the issuance of the SOS Note, and the issuance of the SOS Warrant. On September 29, 2016, we repaid the Independent Bank debt in full, resulting in the extinguishment of Independent Bank’s security interest. Convertible Notes In a series of transactions from December 29, 2015 to May 6, 2016, we issued an aggregate of approximately $5.8 million Convertible Notesmaturing on June 30, 2016 and April 1, 2017, at a conversion price of $5.00. In connection with the December 2015 and March 2016 financing transactions,we issued warrants to purchase an aggregate of approximately 1.7 million shares of common stock with an exercise price of $2.50 per share and in connectionwith the May 2016 transaction, we issued warrants to purchase an aggregate of approximately 625,000 shares of common stock with an exercise price of$0.10 per share. Subsequently, as an inducement to participate in the May Convertible Notes offering, warrants to purchase up to 620,000 shares of commonstock issued between December 2015 and March 2016 were amended and restated to reduce the exercise price to $0.10. As such, we recorded in otherexpense an inducement expense of $1.72 million. The proceeds of $5.8 million from these financing transactions were used to pay a $2.0 million refundabledeposit in connection with the Merger, to fund certain operating expenses of Brushy in an aggregate amount of $508,000, to fund approximately $1.3million of interest payments to Heartland and to fund approximately $2.0 million in working capital and accounts payables. 48  In connection with the closing of the Merger, on June 23, 2016, we entered into a Conversion Agreement with certain holders of Convertible Notesin an aggregate principal amount of approximately $4.0 million (the “Note Conversion Agreement”). The terms of the Note Conversion Agreement providedthat the Convertible Notes were automatically converted into common stock upon the closing of the Merger. Pursuant to the terms of the Note ConversionAgreement, in exchange for immediate conversion upon closing, the conversion price of the Convertible Notes was reduced to $1.10, which resulted in theissuance of 3,636,366 shares of common stock. The modification of such conversion rate resulted in a $3.4 million inducement charge recorded in otherexpense. Holders of these Convertible Notes waived and forfeited approximately $198,000 rights to receive accrued but unpaid interest. On August 3, 2016, we entered into the first amendment to the Convertible Notes with the remaining holders of approximately $1.8 million ofConvertible Notes. Pursuant to the first amendment: (i) the maturity date was changed to January 2, 2017, (ii) the conversion price was adjusted to $1.10 and(iii) the coupon rate was increased to 15% per annum. All accrued and unpaid interest on the Convertible Notes would have also been convertible in certaincircumstances at the conversion price. Additionally, if the aggregate principal amount outstanding on the Convertible Notes was not either converted by theholder or repaid in full on or before the maturity date, we agreed to pay a 25% premium on the maturity date. We accounted for the reduction in theconversion price of remaining outstanding convertible notes as an inducement expense and recognized approximately $1.6 million in other income(expense). In exchange for the holders’ willingness to enter into the first amendment, we issued to the holders of additional warrants to purchase up toapproximately 1.65 million shares of common stock. The warrants issued were valued using the following variables: (a) stock price of $1.15, (b) exerciseprice of $2.50, (c) contractual life of 3 years, (d) volatility of 203%, and (e) risk free rate of 0.76% for a total value of approximately $1.63 million. Thisamount was recorded as an inducement expense and an offset to additional paid-in capital. On September 29, 2016, in connection with our entry into the Credit Agreement, the remaining holders of the Convertible Notes converted theoutstanding principal amount of approximately $1.8 million and accrued and unpaid interest in an amount of approximately $138,000 into 1,772,456 sharesof common stock. Credit Agreement and Warrant Repricing Credit Agreement On September 29, 2016, we entered into the Credit Agreement which provides for a three-year senior secured term loan with initial commitments of$31 million in aggregate principal amount, of which $25 million was collected as of September 30, 2016 and the additional $6 million was collected as ofNovember 11, 2016. The initial aggregate principal amount may be increased to a maximum principal amount of $50,000,000 at our request, but at thediscretion of the Lenders, pursuant to an accordion advance provision in the Credit Agreement (the “Term Loan”). As discussed above, in connection with our entry into the Credit Agreement, on September 29, 2016, we used part of the proceeds of the Term Loanto repay the balance of Brushy’s outstanding indebtedness with Independent Bank, resulting in the elimination of approximately $5.4 million in seniorsecured debt, including accrued interest, fees and expenses, and the extinguishment of Independent Bank’s security interest in the assets of the InitialGuarantors and of our guaranty to Independent Bank in full. Funds borrowed under the Credit Agreement may be used by us to (i) fund drilling and development projects, (ii) purchase oil and gas assets andother acquisition targets, (iii) pay all costs and expenses arising in connection with the negotiation and execution of the Credit Agreement, and (iv) fund ourgeneral working capital needs. In connection with our entry into the Credit Agreement, we paid advisory fees to KES 7 and TRW in an amount of $420,000 and $200,000,respectively and a commitment fee to each of the Lenders equal to 2.0% of their respective initial loan advances. As partial consideration given to thelenders, we also amended certain warrants issued in the Series B preferred stock offering held by the lenders during the third and fourth quarters of the yearended December 31, 2016, to purchase up to an aggregate amount of approximately 2,840,000 and 681,822 shares of common stock, respectively, such thatthe exercise price per share was lowered from $2.50 to $0.01 on such warrants. The portion repriced in the fourth quarter was due to certain delayed fundingthat occurred after the initial commitment. The number of warrants amended for each Lender was based on the amount of each Lender’s respectiveparticipation in the initial Term Loan relative to the amount invested in the June 2016 Series B Preferred Stock private placement. All of the amendedwarrants are immediately exercisable from the original issuance date, for a period of two years, subject to certain conditions. We accounted for the reductionin the conversion price as a deferred financing cost of $714,000 and will be amortized over the length of the loan. 49  The Term Loan bears interest at a rate of 6.0% per annum and matures on September 30, 2019. We have the right to prepay the Term Loan, in wholeor in part, at any time at a prepayment premium equal to 6.0% of the amount repaid. Such prepayment premium must also be paid if the Term Loan is repaidprior to maturity as a result of a change in control. In certain situations, the Credit Agreement requires mandatory prepayments of the Term Loans at therequest of the Lenders, including in the event of certain non-ordinary course asset sales, the incurrence of certain debt and our receipt of proceeds inconnection with insurance claims. The Credit Agreement contains certain customary representations and warranties and affirmative and negative covenants, including covenantsrelating to maintenance of books and records, financial reporting and notification, compliance with laws, maintenance of properties and insurance, andlimitations on guaranties, investments, issuance of debt, lease obligations and capital expenditures. The Credit Agreement also provides for events of default,including failure to pay any principal or interest when due, failure to perform or observe covenants, cross-default on certain outstanding debt obligations, thefailure of a Guarantor to comply with the provisions of its Guaranty, and bankruptcy or insolvency events. The amounts under the Credit Agreement could beaccelerated and be due and payable upon an event of default. Subsequent Events Credit Agreement Drawdown On February 7, 2017, pursuant to the terms of the 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 total availability for borrowing remaining under the Credit Agreement is$11.9 million. We intend to use the proceeds to fund its drilling and development program, for working capital and for general corporate purposes. As partial consideration, we also amended certain warrants issued in the June 2016 private placement held by the Lenders to purchase up to anaggregate amount of approximately 738,638 shares of common stock such that the exercise price per share was lowered from $2.50 to $0.01 on such warrantsThe number of warrants amended for each Lender was based on the amount of each Lender’s respective participation in the initial Term Loan relative to theamount invested in the June 2016 private placement. All of the amended warrants are immediately exercisable from the original issuance date, for a period oftwo years, subject to certain conditions. March 2017 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 approximately an additional 2.6 million shares of common stock for an aggregate purchase price ofapproximately $20] million. Each unit consists of one share of common stock and a warrant to purchase 0.50 shares of common stock (each, a “Unit”), at aprice per unit of $3.85. Each warrant has an exercise price of $4.50 and may be subject to redemption by the Company, upon prior written notice, if the priceof the Company’s common stock closes at or above $6.30 for twenty trading days during a consecutive thirty trading day period. The closing of the Offeringis subject to the satisfaction of customary closing conditions. We expect to use the net proceeds from the Offering to support our planned 2017 capital budget, and for general corporate purposes includingworking capital. The securities to be sold in the private placement have not been registered under the Securities Act or any state securities laws and may not beoffered or sold in the United States absent registration or an applicable exemption from registration. However, in conjunction with the closing of the March2017 Private Placement, we have also entered into a registration rights agreement whereby we agreed to use our reasonable best efforts to register, on behalfof the investors, the shares of common stock underlying the Units and the shares of common stock underlying the warrants no later than April 1, 2017. Our 2017 capital budget may require additional financing above the level of cash generated by our operations and proceeds from recent financingactivities. We can provide no assurance that additional financing would be available to us on acceptable terms, if at all. 50  Off-Balance Sheet Arrangements We do not have any off-balance sheet arrangements. Critical Accounting Policies and Estimates The preparation of our consolidated financial statements in conformity with generally accepted accounting principles in the United States (“USGAAP”) requires our management to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well asthe disclosure of contingent assets and liabilities at the date of our financial statements and the reported amounts of revenues and expenses during thereporting period. The following is a summary of the significant accounting policies and related estimates that affect our financial disclosures. Critical accounting policies are defined as those significant accounting policies that are most critical to an understanding of a company’s 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 US GAAP requires us to make a number of estimates and assumptions relating to thereported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reportedamounts of revenues and expenses during the reporting period. Actual results could differ significantly from those estimates. Management evaluatesestimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity priceenvironment. Our most significant financial estimates are associated with our estimated proved oil and gas reserves, assessments of impairment in the carryingvalue of undeveloped acreage and proven properties. There are also significant financial estimates associated with the valuation of our Common Stock,options and warrants, inducement transactions and estimated derivative liabilities. Oil and Natural Gas Reserves We follow the full cost method of accounting. All of our oil and gas properties are located within the United States, and therefore all costs related tothe acquisition and development of oil and gas properties are capitalized into a single cost center referred to as a full cost pool. Depletion of exploration anddevelopment costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gasreserves. Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes maynot exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves less the future cashoutflows associated with the asset retirement obligations that have been accrued on the balance sheet plus the cost, or estimated fair value if lower, ofunproved properties. Should capitalized costs exceed this ceiling, impairment would be recognized. Under the SEC rules, we prepared our oil and gas reserveestimates as of December 31, 2016, using the average, first-day-of-the-month price during the 12-month period ended December 31, 2016. Estimating accumulations of gas and oil is complex and is not exact because of the numerous uncertainties inherent in the process. The processrelies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data canvary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as gas and oil prices, drilling and operatingexpenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of the quality and quantity of available data;the interpretation of that data, the accuracy of various mandated economic assumptions; and the judgment of the persons preparing the estimate. We believe estimated 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. 51  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 full cost pool and becomes subject to depletion calculations. 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. 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, NGLs and gas 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.The Company had no material oil, NGL or gas entitlement assets or liabilities as of December 31, 2016 or 2015. 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 8 of this Annual Report on Form 10-K. Item 7A.Quantitative and Qualitative Disclosures About Market Risk Not applicable. 52  Item 8.Financial Statements and Supplementary Data Our financial statements appear immediately after the signature page of this Annual Report on Form 10-K, which are incorporated herein byreference. See “Index to Financial Statements” included in this Annual Report on Form 10-K. Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure Not applicable Item 9A.Controls and Procedures Evaluation of Disclosure Controls and Procedures As required by Rule 13a-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), at the end of the period we carried out an evaluation,under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, the effectiveness ofthe design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based upon thatevaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31,2016 at the reasonable assurance level. Changes in Internal Control over Financial Reporting Management implemented internal audit activities to improve the Company’s governance and risk management based on assessment of systems andbusiness processes. Management has conducted an assessment of the effectiveness of the Company's internal control over financial reporting as of December31, 2016. The assessment was based on the criteria established in Internal Control - Integrated Framework issued by the Committee of SponsoringOrganizations of the Treadway Commission (2013 COSO Framework). Management’s assessment sufficiently addresses the risks of misstatements in financial reporting including risk of fraud identified within keybusiness processes. As a result, management has concluded that, as of December 31, 2016, the Company's internal control over financial reporting waseffective and that the previously identified material weakness in the Company’s Form 10-K filed for the year ended December 31, 2015 has been fullyremediated. Remediation of Material Weakness in Internal Control Continuing into the fourth quarter of 2016, a number of remedial actions were taken to address the previously existing material weaknesses.Management’s efforts included performing a top-down risk assessment to identify risk of financial misstatement and fraud risks related to key processes andactivities, including identification of relevant assertions for each significant account and disclosure. Additional measures included: 1)Management identified the risk of fraud for significant accounts and disclosures.2)Management identified key risks within each business process and implemented controls to address each risk.3)Management conducted walkthroughs for key processes.4)Management assessed operating effectiveness by performing test procedures on samples of transactions. In addition, starting in 2016, management augmented and high-graded key staff with more experience and expertise, supplemented with outsideconsultants, to put into place an effective mechanism for monitoring our system of internal control. Management’s Annual Report on Internal Control Over Financial Reporting Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control overfinancial reporting is a process designed by or under the supervision of our Chief Executive Officer and Chief Financial Officer and effected by our Board ofDirectors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of ourfinancial statements for external purposes in accordance with generally accepted accounting principles. Our management, with the participation of our ChiefExecutive Officer and Chief Financial Officer assessed the effectiveness of our internal control over financial reporting, as of December 31, 2016, based onthe criteria for effective internal control over financial reporting established in “Internal Control - Integrated Framework (2013)” which is issued by theCommittee of Sponsoring Organizations of the Treadway Commission. Based on the assessment and those criteria, our management determined that wemaintained effective internal control over financial reporting as of December 31, 2016. Item 9B. Other Information None. 53  PART III Item 10. Directors, Executive Officers and Corporate Governance The following table sets forth the names, ages and positions of the persons who are our directors and executive officers as of March 1, 2016: Name Age PositionAbraham “Avi” Mirman 47 Chief Executive Officer, DirectorRonald D. Ormand 58 Executive Chairman of the Board of DirectorsNuno Brandolini 63 DirectorR. Glenn Dawson 60 DirectorGeneral Merrill McPeak 81 DirectorPeter Benz 56 DirectorJoseph C. Daches 50 Executive Vice President, Chief Financial Officer and TreasurerBrennan Short 42 Chief Operating OfficerAriella Fuchs 35 Executive Vice President, General Counsel and SecretarySeth Blackwell 29 Executive Vice President of Land and Business Development Abraham Mirman: Chief Executive Officer, Director. Mr. Mirman joined our Board of Directors (the “Board” or the “Board of Directors”) onSeptember 12, 2014. He currently serves as our Chief Executive Officer and has held that position since April 21, 2014. Prior to being appointed to hiscurrent position of Chief Executive Officer, Mr. Mirman served as our President beginning in September 2013. During that same time, from April 2013 untilSeptember 2014, Mr. Mirman served as the Managing Director, Investment Banking at T.R. Winston & Company, LLC (“TRW”). Between 2012 andFebruary 2013, Mr. Mirman served as Head of Investment Banking at John Thomas Financial. From 2011 to 2012, Mr. Mirman served as Head of InvestmentBanking at BMA Securities. Lastly, from 2006 to 2011, Mr. Mirman served as Chairman of the Board of Cresta Capital Strategies LLC. During Mr. Mirman’sservice as Chief Executive Officer, we have completed several significant capital raising transactions and negotiated a final settlement with its senior securedlender. Director Qualifications: ·Leadership Experience - Chief Executive Officer of Lilis Energy, Inc.; Chairman of the Board of Cresta Capital Strategies LLC; Head ofInvestment Banking at BMA Securities; Head of Investment Banking at John Thomas Financial; Managing Director, Investment Banking atTRW.·Industry Experience - Personal investment in oil and gas industry, and experience as executive officer of our company. Ronald D. Ormand: Executive Chairman of the Board of Directors. Mr. Ormand joined Lilis’s 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 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. 54  Director Qualifications: ·Leadership Experience - Senior executive at Magnum Hunter Resources Corporation, Chairman and Head of Investment Banking at MLV andHead of US Oil and Gas for CIBC and investment banker.·Industry Experience - Extensive experience in oil and gas development and services industries at the entities and in the capacities describedabove 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. Mr. Brandolini served as a member of the general partner ofScorpion Capital Partners, L.P., a private equity firm organized as a small business investment company until June 2014. Prior to forming Scorpion Capitaland its predecessor firm, Scorpion Holding, Inc., in 1995, Mr. Brandolini served as managing director of Rosecliff, Inc., a leveraged buyout fund co-foundedby Mr. Brandolini in 1993. Mr. Brandolini served previously as a vice president in the investment banking department of Salomon Brothers, Inc., and aprincipal with the Batheus Group and Logic Capital, two venture capital firms. Mr. Brandolini began his career as an investment banker with Lazard Freres &Co. Mr. Brandolini is a director of Cheniere Energy, Inc. (NYSE MKT: LNG), a Houston-based company primarily engaged in LNG related businesses. Mr.Brandolini received a law degree from the University of Paris and an M.B.A. from the Wharton School. Director Qualifications: ·Leadership Experience - Executive positions with several private equity firms, and Board position with Cheniere Energy, Inc.·Industry Experience - Service on the Board of Cheniere Energy, Inc., as well as personal investments in the oil and gas industry. R. Glenn Dawson: Director. Mr. Dawson joined our Board of Directors on January 13, 2016. Mr. Dawson has over 30 years of experience in oil andgas exploration in North America and is currently President and Chief Executive Officer of Cuda Energy, Inc., a private Canadian-based exploration andproduction company. Mr. Dawson’s career includes serving as President of Bakken Hunter, a division of MHR, where he managed operations anddevelopment 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 their Canadian operations. From December 1985to September 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 NuLoch Resources, Inc. in 2005. Mr. Dawson graduated in 1980 from Weber State University of Utah with a Bachelor’s degree inGeology and attended the University of Calgary from 1980 to 1982 in the Masters Program for Geology. As a result of these professional experiences, Mr.Dawson possesses particular knowledge and experience in the operations of oil and gas companies that strengthen the Board’s collective qualifications,skills, and experience. 55  Director Qualifications: ·Leadership Experience - President and Chief Executive Officer of Cuda Energy, Inc.; former President of Bakken Hunter.·Industry Experience - Extensive experience in oil and gas exploration industry; co-founded numerous oil and gas exploration companies. 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 distinguished 37-year military career. Following retirement from active service in 1994,General McPeak launched a second career in business. He was a founding investor and chairman of Ethics Point, an ethics and compliance software andservices company, which was subsequently restyled as industry leader Navex Global, and acquired in 2011 by a private equity firm. General McPeak co-invested and remained 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 Los Angeles-based, privately held provider of metal processing and finishing services, primarily to the aerospace industry, which was also acquired ina private equity buyout. He remains a director of that company, now called Valence Surface Technologies. He also currently serves as a director of AerojetRocketdyne, Lion Biotechnologies 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. Since 2010, General McPeak has been Chairman of the American Battle MonumentsCommission, an agency of the executive branch of the federal government, responsible for operating and maintaining American cemeteries in foreigncountries holding the remains of 125,000 US servicemen. General McPeak has a B.A. degree in Economics from San Diego State College and an M.S. inInternational Relations from George Washington University. He is a graduate of the National War College and of the Executive Development Program of theUniversity of Michigan Graduate School of Business. He spent an academic year as Military Fellow at the Council on Foreign Relations Director Qualifications: ·Leadership Experience - Chief of Staff of the U.S. Air Force; Founding investor and chairman of Ethicspoint (subsequently Navex Global).·Industry Experience - Personal investments in the oil and gas industry. Peter Benz: Director. Mr. Benz joined our Board of Directors on June 23, 2016 in connection with the completion of the merger with Brushy. Priorto that, Mr. Benz had served on Brushy’s Board of Directors since January 20, 2012. Mr. Benz serves as the Chairman and Chief Executive Officer of VikingAsset 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 these professional experiences, Mr. Benzpossesses particular knowledge and experience in developing companies and capital markets that strengthen the board of director’s collective qualifications,skills, and experience. Director Qualifications: ·Leadership Experience –Chairman and CEO of Viking Asset Management; founded three public companies. 56  ·Industry Experience –Extensive experience in the investment banking and corporate advisory services industries; founded Bi CoastalConsulting, a consulting company advising companies regarding private placements, initial public offerings, secondary public offerings andacquisitions. 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, effective immediately. Prior to joining our company, Mr. Daches mostrecently held the position of Chief Financial Officer and Senior Vice President of Magnum Hunter Resources Corp. (“MHR”) from July 2013 to June 2016,where he finished his tenure by successfully guiding MHR through a restructuring, and upon emergence was appointed Co-CEO by MHR’s new board ofdirectors until his departure. Mr. Daches has over 20 years of experience and expertise in directing strategy, accounting and finance in primarily small andmid-size oil and gas companies and has helped guide several of those companies through financial strategy, capital raises and private and public offerings.Prior to joining MHR, Mr. Daches served as Executive Vice President, Chief Accounting Officer and Treasurer of Energy & Exploration Partners, Inc. fromSeptember 2012 until June 2013 and as a director of that company from April 2013 through June 2013. He previously served as a partner and ManagingDirector of the Willis Consulting Group, LLC, from January 2012 to September 2012. From October 2003 to December 2011, Mr. Daches served as theDirector of E&P Advisory Services at Sirius Solutions, LLC, where he was primarily responsible for financial reporting, technical and oil and gas accountingand the overall management of the E&P Advisory Services practice. Mr. Daches earned a Bachelor of Science in Accounting from Wilkes University inPennsylvania, and he is a certified public accountant in good standing with the Texas State Board of Public Accountancy. Brennan Short: Chief Operating Officer. On January 27, 2017, our Board appointed Brennan Short to the position of Chief Operating Officer,effective immediately. Mr. Short most recently held the position of President at MMZ Consulting Inc. from May 2012 to January 2017, where he providedfull cycle drilling & completions engineering and operational support to multiple clients. Mr. Short has over 20 years of proven expertise in domestic oil &gas exploration and production operations, field supervision, management and petroleum engineering consulting. Prior to forming MMZ Consulting Inc.,Mr. Short held the position of Drilling Engineering Specialist at EOG Resources, Inc. from March 2010 to May 2012, where he was a drilling engineer in theinfancy of the Eagleford Shale Play in South Texas. Previous to his role EOG Resources, Inc., Mr. Short was a Drilling Engineer at SM Energy from November2007 to March 2010 and a Drilling Engineer at Samson Investment Company from March 2005 to November 2007. Mr. Short earned his Bachelor’s degree inPetroleum Engineering from Texas A&M University. Ariella Fuchs: Executive Vice President, General Counsel and Secretary. Ariella Fuchs joined our company in March 2015. Prior to that, Ms.Fuchs was an associate with Baker Botts L.L.P. from April 2013 to February 2015, specializing in securities transactions and corporate governance. Prior tojoining Baker Botts L.L.P, she served as an associate at White & Case LLP and Dewey and LeBoeuf LLP from January 2010 to March 2013 in their mergersand acquisitions groups. Ms. Fuchs received a J.D. from New York Law School and a B.A. in Political Science from Tufts University. Seth Blackwell: Executive Vice President of Land and Business Development. Seth Blackwell joined our company in December 2016. Mr.Blackwell is a Professional Landman with extensive knowledge and experience in all facets of land management. Prior to joining our company, Mr.Blackwell held the position of Vice President of Land for XOG Resources where he managed all land and business development efforts for 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 startedhis career blocking together large acreage positions in excess of 30,000 acres throughout Central and East Texas. Mr. Blackwell is an active member of theAmerican Association of Professional Landman, North Houston Association of Professional Landman and the Houston Association of Professional Landman.Mr. Blackwell holds a bachelor’s degree in Business Management from Fort Hays State University and is currently pursuing his MBA in Energy from theUniversity of Tulsa. 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. None of the above individuals has any familyrelationship with any other. It is expected that our Board of Directors will elect officers annually following each annual meeting of stockholders. 57  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 2016 and through the date of this report, except asfollows: ·Kevin Nanke filed one Form 4, reporting one transaction late.·R. Glenn Dawson filed one Form 4 reporting one transaction late. After the reporting period, Mr. Dawson filed one Form 4 reporting onetransaction late.·Sean O-Sullivan Revocable Living Trust (the “SOS Trust”) filed one Form 3 late, as well as an amendment to such Form 3 reporting hisinitial beneficial ownership late. The SOS Trust filed three Form 4s reporting eight transactions late, as well as an amendment to one of thelate Form 4s, reporting an additional two transactions late.·SOSVentures LLC filed one Form 3 late.·Ronald D. Ormand filed one Form 4 amendment reporting two transactions late.·Peter Benz filed one Form 4 amendment reporting one transaction late.·Joseph C. Daches filed one Form 3 reporting his initial beneficial ownership late. The Board of Directors and Committees Thereof Our Board of Directors conducts its business through meetings and through its committees. Our Board of Directors held ten meetings in 2016 andtook action by unanimous written consent on nine occasions. Each director attended at least 75% of (i) the meetings of the Board held after such director’sappointment and (ii) the meetings of the committees on which such director served, after being appointed to such committee. Our policy regarding directors’attendance at the annual meetings of stockholders is that all directors are expected to attend, absent extenuating circumstances. Affirmative Determinations Regarding Director Independence and Other Matters Our Board of Directors follows the standards of independence established under the rules of the Nasdaq Stock Market, or the Nasdaq, as well as ourCorporate Governance Guidelines on Director Independence, which was amended on December 10, 2015, a copy of which is available on our website atwww.lilisenergy.com under “Investors-Corporate Governance-Highlights” in determining if directors are independent. The Board has determined that four ofour current directors, Mr. Brandolini, General McPeak, Mr. Benz and Mr. Dawson are “independent directors” under the Nasdaq rules referenced 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. 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 and a nominating and corporate governance committee. The membership and function of these committees aredescribed below. 58  Audit Committee During the year ended December 31, 2016, each of Mr. Brandolini, General McPeak, Mr. Dawson and Mr. Benz served on the audit committee.Currently, the audit committee consists of Mr. Benz, Mr. Brandolini and General McPeak. Mr. Benz is the acting as chairman of the audit committee andmeets the definition of an audit committee financial expert. Our Board of Directors determined that each of Mr. Brandolini, General McPeak, Mr. Dawson andMr. Benz were independent as required by Nasdaq for audit committee members. The audit committee met four times during the year ended December 31, 2016, but met separately on several occasions in connection with a meetingof the full Board of Directors. The audit committee is governed by a written charter that is reviewed, and amended if necessary, on an annual basis. A copy ofthe 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, General McPeak and Mr. Dawson. Mr. Ormand had also served on thecompensation committee, but resigned following a determination that he should not be considered independent and eligible for compensation committeeservice based on the above-described compensation paid to his investment bank. General McPeak is the chairman of the compensation committee. The compensation committee met six times during the year ended December 31, 2016, and acted by written consent twice. The compensationcommittee has also met separately on several occasions in connection with a meeting of the full Board. The Board determined that each of Mr. Brandolini,General McPeak and Mr. Dawson were independent as required by Nasdaq for compensation committee members. 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,compensation of our executive and senior officers, trends in management compensation and any other factors that it deems appropriate. Under its charter, thecompensation committee may create and delegate such tasks to such standing or ad hoc subcommittees as it may determine to be necessary or appropriate forthe discharge of its responsibilities, as long as the subcommittee has at least the minimum number of directors necessary to meet any regulatory requirements.The compensation committee may engage consultants in determining or recommending the amount of compensation paid to our directors and executiveofficers. The compensation committee is governed by a written charter that is reviewed, and amended if necessary, on an annual basis. A copy of the charter isavailable 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 once during the year ended December 31,2016, but met separately on several occasions in connection with a meeting 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 of Directors, potential candidates to become members of the Board of Directors, recommending membership on standingcommittees of the Board of Directors, developing and recommending to the entire Board of Directors corporate governance principles and practices for ourcompany and assisting in the implementation of such policies, and assisting in the identification, evaluation and recommendation of potential candidates tobecome officers of our company. The nominating and corporate governance committee will review our code of business conduct and ethics and itsenforcement, and reviews and recommends to our Board of Directors whether waivers should be made with respect to such code. A copy of the nominatingand corporate governance committee charter may be found on our website at www.lilisenergy.com under “Investor Relations-Corporate Governance-Highlights.” During fiscal year 2016, there have been no material changes to the procedures by which security holders may recommend nominees to ourBoard of Directors. 59  Communications with the 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: General Counsel. Allcommunications are compiled by the general counsel and forwarded to the 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, which we refer to as the Code, that applies to all of our officers andemployees, including our chief executive officer, chief financial officer or controller, and persons performing similar functions. Our code of business conductand ethics codifies the business and ethical principles that govern all aspects of our business. A copy of our code of business conduct and ethics is availableon our website at www.lilisenergy.com under “Investors-Corporate Governance-Highlights.” We undertake to provide a copy of our code of business conductand ethics to any person, 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: General Counsel. If any substantive amendments are made to our code of business conduct and ethics, or if anywaiver (including any implicit waiver) is granted from any provision of the code of business conduct and ethics to our chief executive officer, chief financialofficer or 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 Executive Compensation for Fiscal Year 2016 The compensation earned by our executive officers for the year ending December 31, 2016 consisted of base salary, short-term incentivecompensation consisting of cash payments and long-term incentive compensation consisting of awards of stock grants. All share and per share amounts, fairvalues per share and exercise prices that appear in this section have been adjusted to reflect the 1-for-10 reverse stock split of our outstanding common stockeffected on June 23, 2016. Summary Compensation Table The table below sets forth compensation paid to our named executive officers (NEOs) for the years ending December 31, 2016 and 2015. Name and PrincipalPosition Year Salary($) Bonus($) StockAwards($)(1) OptionAwards($)(2) All OtherCompensation($)(3) Total($) Abraham “Avi” Mirman 2016 350,000 175,000(4) ─ 4,295,894 22,484 4,843,378 (Chief Executive Officer) 2015 325,466 100,000(5) 90,000 1,397,721 31,504 1,944,691 Ronald D. Ormand(6) 2016 150,000 ─ 1,875,000 533,092 69,502 2,627,594 (Chairman of the Board of Directors) Ariella Fuchs 2016 240,000 112,500(4) ─ 1,288,768 8,417 1,649,685 (General Counsel and Secretary) 2015 182,083 ─ 48,000 234,887 10,538 475,508 60  (1)Represents restricted stock awards. The grant date fair values for restricted stock awards were computed in accordance with FASB ASC Topic 718. Theamounts reported in this column reflect the accounting cost for the stock awards and do not necessarily correspond to the actual economic value thatmay be received for the stock awards.(2)Awards in this column are reported at grant date fair value, if awarded in the period, and any incremental fair value, if modified in the period, in eachcase in accordance with FASB ASC Topic 718. Mr. Mirman was granted 1,250,000 options on each of June 24, 2016 and December 15, 2016; Mr.Ormand was granted 250,000 options on December 15, 2016; and Ms. Fuchs was granted 375,000 options on each of June 24, 2016 and December 15,2016. The grant date fair values for options granted on June 24, 2016 and December 15, 2016 were $1.30 (rounded) and $2.13 (rounded), respectively.For both Mr. Mirman and Ms. Fuchs, their options granted June 24, 2016 were modified December 15, 2016 to provide for accelerated exercisabilityupon an involuntary employment termination and upon a change in control, and for extension of the post-termination exercise period upon anemployment termination other than for cause. However, there was no incremental fair value for those modified options. The amounts reported in thiscolumn reflect the accounting cost for the options and do not correspond to the actual economic value that may be received for the options. Theassumptions used to calculate the fair value of options are set forth in the notes to our consolidated financial statements included in this Annual Reporton Form 10-K.(3)For 2016, reflects reimbursement of health insurance premiums for all of the NEOs. For Mr. Ormand, the amount also reflects $55,000 in director feespaid to him for his Board service in 2016 prior to the time he became an officer.(4)Reflects a bonus payable under the officer’s employment agreement for the successful completion of the Brushy merger.(5)Reflects a sign-on bonus.(6)Effective July 11, 2016, Mr. Ormand began to serve as Executive Chairman of the Board, which is an officer position. Prior to July 11, 2016, Mr.Ormand was a nonemployee director of the Board and his compensation from January 1 to July 10, 2016 is reflected under All Other Compensation. Outstanding Equity Awards at Fiscal Year-End Option Awards Stock Awards Name Number ofSecuritiesUnderlyingUnexercisedOptions(#)Exercisable Number ofSecuritiesUnderlyingUnexercisedOptions(#)Unexercisable OptionExercisePrice($) OptionExpirationDate Number ofShares orUnits ofStock ThatHave NotVested(#) MarketValue ofShares orUnits ofStock ThatHave NotVested($) Abraham “Avi” Mirman 170,000 330,000(1) 2.98 12/15/2026 ─ ─ 425,000 825,000(2) 1.34 6/24/2026 ─ ─ 60,000 ─ 21.10 9/16/2023 ─ ─ Ronald D. Ormand 85,000 165,000(1) 2.98 12/15/2026 833,333(3) 2,583,332 31,666 13,334(4) 16.50 4/20/2025 ─ ─ Ariella Fuchs 127,500 247,500(1) 2.98 12/15/2026 ─ ─ 127,500 247,500(2) 1.34 6/24/2026 ─ ─ (1)Options vest in equal installments on each of December 15, 2017 and 2018, subject to acceleration provisions and continued service(2)Options vest in equal installments on each of June 24, 2017 and 2018, subject to acceleration provisions and continued service.(3)Restricted shares vest in equal installments on each of July 7, 2017 and July 7, 2018, subject to acceleration provisions and continued service.(4)Options vest in equal installments on each of April 20, 2017 and 2018, subject to acceleration provisions and continued service. 61  Employment Agreements and Other Compensation Arrangements 2012 Equity Incentive Plan (“2012 EIP”) (formerly the Recovery Energy, Inc. 2012 Equity Incentive Plan) Our Board and stockholders approved our 2012 EIP in August 2012. The 2012 EIP provided for grants of equity incentives to: attract, motivate andretain the best available personnel for positions of substantial responsibility; provide additional incentives to our employees, directors and consultants; andpromote the success and growth of our business. Equity incentives that were available for grant under our 2012 EIP included stock options, stockappreciation rights (SARs), restricted stock awards, restricted stock units (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 totake all actions and to make all determinations required or provided for under the 2012 EIP. Under our 2012 EIP, 1,000,000 shares of our common stock were available for issuance. As a result of the adoption of our 2016 Plan, awards are nolonger made under the 2012 EIP, as discussed below. 2016 Omnibus Incentive Plan (“2016 Plan”) Background Our 2016 Plan was approved by our Board effective April 20, 2016 and approved by our stockholders at their 2016 annual meeting on May 23,2016. Our 2016 Plan replaced our 2012 EIP. The purposes of our 2016 Plan are to create incentives that are designed to motivate eligible directors, officers, employees and consultants to putforth maximum effort toward our success and growth, and to enable us to attract and retain experienced individuals who by their position, ability anddiligence are able to make important contributions to our success. Eligibility Awards may be granted under our 2016 Plan to officers, employees, directors, consultants and advisors of the Company and its affiliates. Tax-qualified incentive stock options may be granted only to employees of the Company or its subsidiaries. Administration Our 2016 Plan may be administered by our Board or its compensation committee. Our compensation committee, in its discretion, 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 When initially approved by our stockholders, 50,000,000 shares of our common stock were made available for issuance under our 2016 Plan. As aresult of our 1-for-10 reverse stock split, which took effect on June 23, 2016, the number of shares available for issuance under our 2016 Plan wasautomatically reduced to 5,000,000. On August 25, 2016, our Board approved an amendment to our 2016 Plan to increase the maximum number of sharesthat may be issued from 5,000,000 to 10,000,000, and our stockholders approved that amendment at a special meeting on November 3, 2016. 62  In addition, as of May 23, 2016, any awards then outstanding under our 2012 EIP remain subject to and will be paid under the 2012 EIP and anyshares then subject to outstanding awards under the 2012 EIP that subsequently expire, terminate or are surrendered or forfeited for any reason withoutissuance of shares will automatically become available for issuance under our 2016 Plan. Up to 5,000,000 shares may be granted as tax-qualified incentivestock options under our 2016 Plan. The shares issuable under our 2016 Plan will consist of authorized and unissued shares, treasury shares or sharespurchased on the open market or otherwise. If any award is canceled, terminates, expires or lapses for any reason prior to the issuance of shares or if shares are issued under our 2016 Plan andthereafter are forfeited to the Company, the shares subject to those awards and the forfeited shares will not count against the aggregate number of sharesavailable for grant under the plan. In addition, the following items will not count against the aggregate number of shares available for grant under our 2016Plan: (1) the payment in cash of dividends or dividend equivalents under any outstanding award, (2) any award that is settled in cash rather than by issuanceof 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 anaward or (4) awards granted in assumption of or in substitution for awards previously granted by an acquired company. Limits on Awards to Nonemployee Directors The maximum number of shares subject to awards under our 2016 Plan granted during any calendar year to any nonemployee member of our Board,taken together with any cash fees paid to the director during the fiscal year, may not exceed $500,000 in total value (calculating the value of any such awardsbased on the grant date fair value of such awards for financial reporting purposes). Types of Awards Our 2016 Plan permits the granting of any or all of the following types of awards: stock options, which entitle the holder to purchase a specifiednumber of shares at a specified price; SARs, which, upon exercise, entitle the holder to receive payment per share in stock or cash equal to the excess of theshare’s fair market value on the date of exercise over the grant price of the SAR; restricted stock, which are shares of common stock subject to specifiedrestrictions; RSUs, which represent the right to receive shares of our common stock in the future; other types of equity or equity-based awards; andperformance awards, which entitle participants to receive a payment from the Company, the amount of which is based on the attainment of performance goalsestablished by the compensation committee over a specified award period. No Repricing Without shareholder approval, our compensation committee is not authorized to (1) lower the exercise or grant price of a stock option or SAR after itis granted, except in connection with certain adjustments to our corporate or capital structure permitted by our 2016 Plan, such as stock splits, (2) take anyother action that is treated as a repricing under generally accepted accounting principles or (3) cancel a stock option or SAR at a time when its exercise orgrant price exceeds the fair market value of the underlying stock, in exchange for cash, another stock option or SAR, restricted stock, RSUs or other equityaward, unless the cancellation and exchange occur in connection with a change in capitalization or other similar change. Clawback All awards granted under our 2016 Plan will be subject to all applicable laws regarding the recovery of erroneously awarded compensation, anyimplementing rules and regulations under such laws, any policies we adopt to implement such requirements and any other compensation recovery policies aswe may adopt from time to time. Transferability 2016 Plan awards are not transferable other than by will or the laws of descent and distribution, except that in certain instances transfers may bemade to or for the benefit of designated family members of the participant for no value. 63  Effect of Change in Control Under our 2016 Plan, in the event of a change in control, outstanding awards will be treated in accordance with the applicable transactionagreement. If no treatment is provided for in the transaction agreement, each award holder will be entitled to receive the same consideration that stockholdersreceive in the change in control for each share of stock subject to the award holder’s awards, upon the exercise, payment or transfer of the awards, but theawards will remain subject to the same terms, conditions and performance criteria applicable to the awards before the change in control, unless otherwisedetermined by our compensation committee. In connection with a change in control, outstanding stock options and SARs can be cancelled in exchange forthe 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 upon the change in control. For performance awards, the amount vestingwill be based on the greater of (1) achievement of all performance goals at the “target” level or (2) the actual level of achievement of performancegoals as of our fiscal quarter end preceding the change in control, and will be prorated based on the portion of the performance period that had beencompleted 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 if the award recipient has a separation from service within two years after a change in control other than for cause or by the award recipientfor good reason. For performance awards, the amount vesting will be based on the greater of (1) achievement of all performance goals at the “target”level or (2) the actual level of achievement of performance goals as of fiscal quarter end preceding the change in control, and will be prorated basedon the portion of the performance period that had been completed through the date of the separation from service. Term, Termination and Amendment of 2016 Plan Unless earlier terminated by our Board, our 2016 Plan will terminate, and no further awards may be granted, 10 years after the date on which it isapproved by stockholders. Our Board may amend, suspend or terminate our 2016 Plan at any time, except that, if required by applicable law, regulation orstock exchange rule, stockholder approval will be required for any amendment. The amendment, suspension or termination of our 2016 Plan or theamendment of an outstanding award generally may not, without a participant’s consent, materially impair the participant’s rights under an outstanding award. Equity Grants for Fiscal Year 2016 During our year ended December 31, 2016, we granted 1,780,052 shares of restricted common stock and 5,683,500 options to purchase shares ofcommon stock to employees and directors. Also during the year ended December 31, 2016, our employees forfeited and we cancelled 335,000 stock optionspreviously issued in connection with the termination of certain employees and directors. As a result, as of December 31, 2016, the Company had 1,068,305restricted shares of common stock and 5,956,833 options to purchase shares of common stock outstanding to employees and directors. Options issued toemployees and directors generally vest in equal installments over specified time periods during the service period or upon achievement of certainperformance based operating thresholds. 64  Employment Agreements Mr. Mirman Effective as of March 30, 2015, we entered into an amended and restated employment agreement with Mr. Mirman, which replaced his prioremployment agreement. The agreement had a three-year term and provided for a $100,000 cash bonus due upon signing, base compensation of $350,000 peryear, and 200,000 stock options, where one-third of the options vested immediately and two-thirds were scheduled to vest in two annual installments on eachof the next two anniversaries of the grant date. The agreement also provided for additional bonuses due based on our achievement of certain performancemeasures. On July 5, 2016, we entered into a new employment agreement with Mr. Mirman under which he will serve as our CEO. This agreement becameeffective June 24, 2016 upon the closing of our merger with Brushy. The initial term of the agreement is scheduled to end on December 31, 2017, and theagreement will renew automatically for additional one-year periods beginning on December 31, 2017, unless either party gives notice of non-renewal at least180 days before the end of the then-current term. The agreement replaces in its entirety Mr. Mirman’s prior employment agreement with the Company. Mr. Mirman’s base salary (which will be reviewed by the Board for adjustments) is $350,000 for the first year of the agreement, $375,000 for thesecond year of the agreement, and $425,000 for the third year of the agreement. Mr. Mirman was entitled to a bonus under the agreement equal to $175,000,payable in cash on the first regular payroll date of the Company following June 24, 2016 (the closing date of the merger with Brushy). Mr. Mirman will alsobe eligible to receive a cash bonus equal to a percentage of his base salary (ranging from 0% to 400%) depending on the level of achievement of certain BOEper day, EBITDAX and cash on hand performance measures. Mr. Mirman will also be eligible to receive awards of equity and non-equity compensation andto participate in our annual and long-term incentive plans, in each case as determined by our Board in its discretion. On June 24, 2016, Mr. Mirman receiveda grant of 1,250,000 stock options under our 2016 Plan, with an exercise price of $1.34. This grant is scheduled to vest over two years, with 34% vesting onthe 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 continuedservice through each vesting date. Under his employment agreement, Mr. Mirman 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. Mirman for good reason within 12 months following 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. Mirman will be entitled to a lump sum severancepayment equal to six months of COBRA premiums. All severance payments under Mr. Mirman’s employment agreement are subject to his execution andnon-revocation of a release of claims against us. The severance payments are also subject to reduction in order to avoid an excise tax associated with Section280G of the Internal Revenue Code, but only if that reduction would 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 agreement will be subject to clawback in the event required by applicable law. Further, Mr.Mirman is subject to non-competition, non-solicitation, anti-raiding and confidentiality provisions under his employment agreement. Mr. Ormand On July 5, 2016, we entered into an employment agreement with Ronald D. Ormand, effective as of July 11, 2016, under which he will serve as ourExecutive Chairman. The initial term of the agreement is scheduled to end on December 31, 2017, and the agreement will renew automatically for additionalone-year periods beginning on December 31, 2017, unless either party gives notice of non-renewal at least 180 days before the end of the then-current term. 65  Mr. Ormand’s base salary (which will be reviewed by the Board for adjustments) is $300,000 for the first year of the agreement, $350,000 for thesecond year of the agreement, and $400,000 for the third year of the agreement. Mr. Ormand will be eligible to receive a cash bonus equal to a percentage ofhis base salary (ranging from 0% to 400%) depending on the level of achievement of certain BOE per day, EBITDAX and cash on hand performancemeasures. Mr. Ormand will also be eligible to receive awards of equity and non-equity compensation and to participate in our annual and long-term incentiveplans, in each case as determined by our Board in its discretion. On July 7, 2016, Mr. Ormand received a grant of restricted stock under our 2016 Plan for 1.25million shares of common stock. The restricted stock vests over two years, with 34% vesting on the date of the grant, 33% vesting on the first anniversary ofthe date of the grant and 33% vesting on the second anniversary of the date of the grant, subject to continued service through each vesting date. 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 following 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 andnon-revocation of a release of claims against us. The severance payments are also subject to reduction in order to avoid an excise tax associated with Section280G of the Internal Revenue Code, but only 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. Ms. Fuchs In connection with the appointment of Ms. Fuchs as our General Counsel, we entered into an employment agreement with her dated March 16, 2015.The agreement provided, among other things, that Ms. Fuchs would receive an annual salary of $230,000. Additionally, as of the effective date of theagreement, Ms. Fuchs was granted (i) 5,000 shares of restricted stock and (ii) 30,000 stock options, which were scheduled to vest in equal installments on thefirst three anniversaries of the effective date of the agreement. Ms. Fuchs was also eligible receive a cash incentive bonus if we achieved certain productionthresholds. On July 5, 2016, we entered into a new employment agreement with Ms. Fuchs under which she will continue to serve as our General Counsel. Thisagreement became effective June 24, 2016 upon the closing of our merger with Brushy. The initial term of the agreement is scheduled to end on December31, 2017, and the agreement will renew automatically for additional one-year periods beginning on December 31, 2017, unless either party gives notice ofnon-renewal at least 180 days before the end of the then-current term. The agreement replaces in its entirety Ms. Fuchs’ prior employment agreement with us. Ms. Fuchs’ initial base salary under the agreement (which will be reviewed for adjustments) is $250,000. Ms. Fuchs was entitled to a bonus under theagreement equal to $112,500, payable in cash on the first regular payroll date of the Company following June 24, 2016 (the closing date of the merger withBrushy). Ms. Fuchs is also eligible to receive a cash bonus equal to a percentage of her base salary (ranging from 0% to 400%) depending on the level ofachievement of certain BOE per day, EBITDAX and cash on hand performance measures. Ms. Fuchs is also eligible to receive awards of equity and non-equity compensation and to participate in our annual and long-term incentive plans, in each case as determined by our Board in its discretion. On June 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 is scheduled to vest over twoyears, 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 through each vesting date. 66  Under her employment agreement, Ms. Fuchs’ will be entitled to a lump sum severance payment equal to six months of base salary and six months ofCOBRA premiums upon a termination by the Company without cause or a termination by her for good reason. Upon a termination by the Company withoutcause or a termination by Ms. Fuchs for good reason within 12 months following a change in control, she will be entitled to a lump sum severance paymentequal to 24 months of base salary and 24 months of COBRA premiums. Upon a termination due to disability, Ms. Fuchs will be entitled to a lump sumseverance payment equal to six months of COBRA premiums. All severance payments under Ms. Fuchs employment agreement are subject to her executionand non-revocation of a release of claims against the Company. The severance payments are also subject to reduction in order to avoid an excise taxassociated with Section 280G of the Internal Revenue Code, but only if that reduction would result in Ms. Fuchs receiving a greater net after tax benefit as aresult of the reduction. All payments to Ms. Fuchs under her employment agreement will be subject to clawback in the event required by applicable law. Further, Ms. Fuchsis subject to non-competition, non-solicitation, anti-raiding and confidentiality provisions under her employment agreement. Potential Payments Upon Termination or Change-In-Control Mr. Mirman Under his employment agreement, Mr. Mirman 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 the Company without cause ora termination by Mr. Mirman for good reason within 12 months following a change in control, he will be entitled to a lump sum severance payment equal to24 months of base salary and 24 months of COBRA premiums. Upon a termination due to disability, Mr. Mirman will be entitled to a lump sum severancepayment equal to six months of COBRA premiums. All severance payments under Mr. Mirman’s employment agreement are subject to his execution andnon-revocation of a release of claims against us. The severance payments are also subject to reduction in order to avoid an excise tax associated with Section280G of the Internal Revenue Code, but only if that reduction would 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 agreement will be subject to clawback in the event required by applicable law. Further, Mr. Mirman issubject to non-competition, non-solicitation, anti-raiding and confidentiality provisions under his employment agreement. Mr. Ormand 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 following 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 andnon-revocation of a release of claims against the Company. The severance payments are also subject to reduction in order to avoid an excise tax associatedwith Section 280G of the Internal Revenue Code, but only if that reduction would result in Mr. Ormand receiving a greater net after tax benefit as a result ofthe 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. Ms. Fuchs Under her employment agreement, Ms. Fuchs’ will be 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 following a change in control, she will be entitled to a lump sum severance payment equal to 24 months ofbase salary and 24 months of COBRA premiums. Upon a termination due to disability, Ms. Fuchs will be entitled to a lump sum severance payment equal tosix months of COBRA premiums. All severance payments under Ms. Fuchs employment agreement are subject to her execution and non-revocation of arelease of claims against us. The severance payments are also subject to reduction in order to avoid an excise tax associated with Section 280G of the InternalRevenue Code, but only if that reduction would 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 will be subject to clawback in the event required by applicable law. Further, Ms. Fuchs is subject to non-competition, non-solicitation, anti-raiding and confidentiality provisions under her employment agreement. 67  Stock Options Each of Mr. Mirman, Mr. Ormand and Ms. Fuchs hold unvested options under our 2016 Plan, all of which become fully exercisable (1) immediatelyupon the officer’s separation from service other than for cause or for good reason, and (2) immediately prior to, and contingent upon, a change in control priorto the officer’s separation from service. Retirement and Other Benefits All employees, including our NEOs, may participate in our 401(k) retirement savings plan (“401(k) Plan”). Each employee may make before taxcontributions in accordance with Internal Revenue Service limits. We provide this 401(k) Plan to help our employees save a portion of their cashcompensation for retirement in a tax efficient manner. In prior years, we have made a matching contribution in an amount equal to 100% of the employee’selective deferral contribution below 3% of the employee’s compensation and 50% of the employee’s elective deferral that exceeds 3% of the employee’scompensation but does not exceed 5% of the employee’s compensation. Compensation of Nonemployee Directors Name Fees Earnedor Paid inCashCompensation($) Stock Awards($)(1) OptionAwards($)(2) All OtherCompensation($) Total($) G. Tyler Runnels(3) ─ ─ ─ ─ ─ Nuno Brandolini(4) 72,500 135,000 ─ ─ 207,500 General Merrill McPeak(5) 85,000 135,000 ─ ─ 220,000 R. Glenn Dawson(6) 70,522 255,750 81,000 ─ 407,272 Peter Benz(7) 43,901 135,000 67,500 ─ 246,401 (1)Represents restricted stock awards. The grant date fair values for restricted stock awards were determined in accordance with FASB ASC Topic 718.The amounts reported reflect the accounting cost for the awards and do not correspond to the actual economic value that may be received for theawards.(2)Awards in this column are reported at grant date fair value in accordance with FASB ASC Topic 718. The amounts reported reflect the accounting costfor the options and do not correspond to the actual economic value that may be received for the options. The assumptions used to calculate the fairvalue of options are set forth in the notes to our consolidated financial statements included in this Annual Report on Form 10-K. As of December 31,2016, our nonemployee directors held the following equity awards: Mr. Brandolini - 45,000 options, 50,000 restricted shares and 41,666 restrictedstock units; General McPeak - 45,000 options, 33,333 restricted shares and 66,666 restricted stock units; Mr. Dawson - 45,000 options and 113,667restricted shares; and Mr. Benz - 45,000 options and 33,333 restricted shares.(3)Mr. Runnels served as a director from November 21, 2014, through January 13, 2016.(4)Mr. Brandolini has served as a director since February 13, 2014.(5)General McPeak was appointed to the board on January 29, 2015.(6)Mr. Dawson was appointed to the Board on January 13, 2016.(7)Mr. Benz was appointed to the Board on June 23, 2016. 68  On April 16, 2015, our Board adopted an amended nonemployee director compensation program (the “Prior Program”). The Prior Program wascomprised of the following components: ·Initial Grant: Each nonemployee director would receive 100,000 restricted shares of common stock on the first anniversary of the date of thedirector’s appointment, which would vest in three equal installments over a three-year period, (subject to the continued service of the directorand certain accelerated vesting provisions);·Annual Stock Award: Each nonemployee director would receive an annual stock award equal to $60,000 divided by the most recent per shareclosing price of the common stock prior to the date of each annual grant, payable on each anniversary of the date an independent director wasinitially appointed to our Board, and subject to certain accelerated vesting provisions;·Option Award: Each nonemployee director would receive a one-time initial grant of 25,000 stock options, which would vest immediately,and 20,000 options that would vest in equal installments over a three-year period beginning on the first anniversary of the grant date; and·Committee Fees: On a quarterly basis, beginning at the end of the first full quarter following the appointment of the nonemployee director toChairman of the Board, Chairman of the Audit Committee or Chairman of the Compensation Committee, the director would receive $12,500,$6,250 and $6,250, respectively, in cash compensation, which at the election of the director would be payable in cash or stock (calculated bydividing the value of cash compensation (or a portion thereof), by the most recent per share closing price of the common stock prior to thedate of the grant). Beginning January 1, 2017, our Board adopted an amended nonemployee director compensation program (the “New Program”). The New Program issubstantially similar to the Prior Program. However, the New Program sets forth an annual equity date (which will be the first business day on or after January31 of each year) pursuant to which each nonemployee director will receive an Annual Stock Award, subject to substantially the same terms and conditions setforth above. In addition, the New Program establishes annual limits on the number of shares subject to our equity compensation plan awards that may begranted during any calendar year to any director, which, taken together with any cash fees paid to the director during the year, cannot exceed $500,000 intotal value. 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. 69  Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters Securities Authorized for Issuance under Equity Compensation Plans The following table represents the securities authorized for issuance under our equity compensation plans at December 31, 2016. Plan category Number ofsecurities tobe issuedupon exerciseof outstandingoptions,warrants andrights (1) Weighted-averageexercise price ofoutstandingoptions, warrantsand rights (2) Number ofsecuritiesremainingavailable forfuture issuanceunder equitycompensationplans Equity compensation plans approved by security holders 5,354,794 1.74 3,574,742 Equity compensation plans not approved by security holders - - Total 5,354,794 1.74 3,574,742 (1)Includes stock options and restricted stock units outstanding under our 2016 Plan and our 2012 EIP as of December 31, 2016. Does not include shares ofrestricted stock 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, 2016. 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 Capital LLC 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 per share (or, in the alternative, 641,026 options, but in no case both), (ii) consulting agreements with Market Development Consulting Group, Inc.pursuant to which 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 thewarrant to purchase 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) aninvestment banking agreement with TRW pursuant to which we issued 900,000 warrants at an exercise price of $4.25 per share; and (iv) various agreementspursuant to which issued an aggregate amount of 150,000 and 300,000 five year warrants to purchase shares of common stock at an exercise price of $2.50and $2.00, respectively. With respect to the warrants awarded to Bristol Capital, we recorded the warrants as a derivative due to the price reset provisionencompassed in the warrants. 70  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 1, 2017, by each of our executiveofficers 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 1, 2017 of 24,387,793. Unless otherwise indicated, the persons and entitiesnamed in the table have sole voting and sole investment power with respect to the shares set forth opposite the stockholder’s name. Beneficial ownership isdetermined in accordance with Rule 13d-3 under the Securities Exchange Act of 1934, as amended. In computing the number of shares beneficially owned bya person or a group and the percentage ownership of that person or group, shares of our common stock subject to options or warrants currently exercisable orexercisable within 60 days after March 1, 2017 are deemed outstanding by such person or group, but are not deemed outstanding for the purpose ofcomputing the percentage ownership of any other person. All share amounts that appear in this report have been adjusted to reflect a 1-for-10 reverse stocksplit of our outstanding common stock effected on June 23, 2016. Unless otherwise indicated, the address of each stockholder listed in the table is c/o LilisEnergy, Inc., 300 E. Sonterra Blvd. Ste. 1220, San Antonio, Texas 78258 Series B Preferred Stock Common Stock Name and Address of BeneficialOwner Shared Beneficially Owned (1) % of Class LiliscommonstockHeldDirectly LiliscommonstockAcquirableWithin 60Days(2) TotalBeneficiallyOwned(2) Percent ofClassBeneficiallyOwned(2) Directors and Named Executive Officers Abraham Mirman, Chief Executive Officerand Director 1,650 10.59% 762,906(3) 643,334(4) 1,406,240 5.6%(5)Ronald D. Ormand, Executive Chairman ofthe Board 1,000 6.42% 2,495,752(6) 115,001(7) 2,610,753 10.7%(8)Joseph Daches, Chief Financial Officer — — 45,000 250,000(9) 295,000 1.2%Ariella Fuchs, Executive Vice President,General Counsel and Secretary — — — 250,000(10) 250,000 1.0%Peter Benz, Director — — 75,000 25,000(11) 100,000 * Nuno Brandolini, Director — — 402,060 159,574(12) 561,634 2.3%R. Glenn Dawson, Director — — 440,861 108,486(13) 549,347 2.2%General Merrill McPeak, Director — — 406,207 143,521(14) 549,728 2.2%Directors and Officers as a Group (10 persons) 2,650 17.0% 4,627,786 1,694,916(15) 6,322,702 24.2%(16) 5% Stockholders Bryan Ezralow, 23622 Calabasas Road,Suite 200, Calabasas, CA 913012 900 5.8% 1,564,969(17) —(18) 1,564,969 6.42%Marc Ezralow, 23622 Calabasas Road, Suite200, Calabasas, CA 913012 750 4.8% 1,221,566(19) —(20) 1,221,566 5.01% *Represents beneficial ownership of less than 1% of the outstanding shares of common stock. (1)Applicable percentages are based on 15,588 shares of Series B Preferred Stock outstanding as of the date March 1, 2017. Series B Preferred Stock isnon-voting, and currently, no holder of shares of Series B Preferred Stock may convert such shares if, upon conversion, such holder would beneficiallyown more than 4.99% of the Company’s then-outstanding stock. Accordingly, holders of 5% or more of shares of Series B Preferred Stock have beenexcluded from this beneficial ownership table. 71  (2) The terms of the Series B Preferred Stock, and each of the Company’s outstanding warrants, the “Blocker Securities”) contain a provision prohibitingthe conversion of such Series B Preferred Stock, and the exercise of warrants into common stock of the Company if, upon such conversion or exercise,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%, except that upon 61 days prior notice to the Company, a holder of Series B Preferred Stockmay increase the percentage limitation with respect to the Series B Preferred up to a maximum of 9.99%. However, the foregoing restrictions do notprevent such holder from converting or exercising, as applicable, some of its holdings, selling those shares, and then converting or exercising, asapplicable, more of its holdings, while still staying below the respective percentage limitation. As a result, the holder could sell more than anyapplicable ownership limitation while never actually holding more shares than the applicable limitations allow. Accordingly, the share numbers in theabove table represent ownership without regard to the beneficial ownership limitations described in this footnote. While the ownership percentages arealso given without regard to this beneficial ownership limitation, specific footnotes indicate what the effect of each ownership limitation would be asof March 1, 2017. (3)Consists of: (i) 11,087 shares of common stock held by The Bralina Group, LLC; and (ii) 751,819 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. (4)Represents shares of common stock subject to options exercisable within 60 days. In addition, Mr. Mirman beneficially owns an aggregate of 2,566,274 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, suchBlocker Securities have been excluded from the table. These Blocker Securities consist of the following: (i) 1,500,000 shares of common stock issuableupon conversion of shares of Series B Preferred held by the Bralina Group; (ii) 305,187 shares of common stock issuable upon exercise of warrants heldby the Bralina Group and (iii) 761,087 shares of common stock issuable upon exercise of warrants held directly by Mr. Mirman. (5)Including the Blocker Securities, and ignoring the Blocker Limitation, Mr. Mirman beneficially owns a total 3,972,514 shares of common stock, whichrepresents 14.4% of our currently issued and outstanding common stock. (6) Consists of: (i) 1,259,388 shares of common stock held directly by Mr. Ormand; (ii) 100,000 shares of common stock held by Perugia Investments L.P.(“Perugia”); and (iii) 1,136,364 shares of common stock held by The Bruin Trust, an irrevocable trust managed by Jerry Ormand, Mr. Ormand’s brother,as trustee and whose beneficiaries include the adult children of Mr. Ormand. Mr. Ormand is the manager of Perugia and has sole voting and dispositivepower over the securities held by Perugia. (7)Represents shares of common stock subject to options exercisable within 60 days. In addition, Mr. Ormand beneficially owns an aggregate of 1,874,011 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, suchBlocker Securities have been excluded from the table. These Blocker Securities consist of the following: (i) 464,920 shares of common stock issuableupon exercise of warrants held by Perugia; (ii) 500,000 shares of common stock issuable upon exercise of warrants held by The Bruin Trust; and (iii)909,091 shares of common stock issuable upon conversion of shares of Series B Preferred Stock held by Perugia. (8)Including the Blocker Securities, and ignoring the Blocker Limitation, Mr. Ormand beneficially owns a total 4,484,764 shares of common stock, whichrepresents 17% of our currently issued and outstanding common stock. (9)Represents shares of common stock subject to options exercisable within 60 days. 72  (10) Represents shares of common stock subject to options exercisable within 60 days. (11)Represents shares of common stock subject to options exercisable within 60 days. (12)Consists of: (i) 45,000 shares of common stock subject to options exercisable within 60 days; and (ii) 114,574 shares of common stock issuable uponexercise of warrants. The effect of any Blocker Limitation with respect to the securities described here has been excluded, as Mr. Brandolini is belowthe threshold of any such limitation. (13)Consists of: (i) 31,667 shares of common stock subject to options exercisable within 60 days; and (ii) 76,819 shares of common stock issuable uponexercise of warrants. The effect of any Blocker Limitation with respect to the securities described here has been excluded, as Mr. Dawson is below thethreshold of any such limitation. (14)Consists of: (i) 38,333 shares of common stock subject to options exercisable within 60 days; (ii) 105,188 shares of common stock issuable uponexercise of warrants. The effect of any Blocker Limitation with respect to the securities described here has been excluded, as General McPeak is belowthe threshold of any such limitation. (15)As indicated in the above footnotes, this amount excludes an aggregate of 4,440,285 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 10,762,987shares of common stock, which represents 37.34% of our currently issued and outstanding common stock. (17)Based solely on a Schedule 13G filed by Bryan Ezralow on February 14, 2017. Collectively, the shares of Common Stock reported herein in whichBryan Ezralow has shared voting and dispositive power over such shares is an aggregate of 1,011,451 shares. Such shares are held directly by (a) theEzralow Family Trust u/t/d 12/9/1980 (the “Family Trust”) in the amount of 36,723 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 42,583 shares, where Bryan Ezralow as a co-trustee of the Marital Trust shares voting and dispositivepower over such shares, and thus, may be deemed to beneficially own such shares; (c) Elevado Investment Company, LLC, a Delaware limited liabilitycompany (“Elevado Investment”), in the amount of 140,821 shares, where Bryan Ezralow as a co-trustee and manager, respectively, of the two trustsand limited liability company that comprise the managing members of Elevado Investment, shares voting and dispositive power over such shares, andthus, may be deemed to beneficially own such shares; (d) EMSE LLC (“EMSE”), a Delaware limited liability company, in the amount of 81,949 shares,where Bryan Ezralow, as a manager of EMSE, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own suchshares; (e) EZ Colony Partners, LLC, a Delaware limited liability company (“EZ Colony”), in the amount of 709,372 shares, where Bryan Ezralow asthe sole trustee of one of the trusts that is a manager of EZ Colony, shares voting and dispositive power over such shares, and thus, may be deemed tobeneficially 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 Bryan 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 twotrusts and limited liability company that comprise the managing members of one of the other managers of EZ MM&B, shares voting and dispositivepower over such shares, and thus, may be deemed to beneficially own such shares. Collectively, the shares of Common Stock reported herein in which Bryan Ezralow has sole voting and dispositive power over such shares are 553,518shares. Such shares are held directly by (a) the Bryan Ezralow 1994 Trust u/t/d/ 12/22/1994, Bryan Ezralow, Trustee (the “Bryan Trust”) in the amountof 518,669 shares, where Bryan Ezralow as sole trustee of the Bryan Trust has sole voting and dispositive power over such shares, and thus, may bedeemed to beneficially own such shares; and (b) the Marc Ezralow Irrevocable Trust u/t/d 6/1/2004 (the “Irrevocable Trust”) in the amount of 34,849shares, where Bryan Ezralow as sole trustee of the Irrevocable Trust has sole voting and dispositive power over such shares, and thus, may be deemed tobeneficially own such shares. 73  (18)In addition, Bryan Ezralow beneficially owns an aggregate of 2,137,598 additional shares of common stock acquirable within 60 days, each of which issubject 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: (A) (i) 272,728 shares of commonstock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 529,091 shares of common stock issuable upon the exercise of warrants,each held by the Bryan Trust; (B) (i) 45,455 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 68,546shares of common stock issuable upon the exercise of warrants, each held by the Irrevocable Trust; (C) (i) 136,364 shares of common stock issuableupon conversion of shares of Series B Preferred Stock, and (ii) 200,371 shares of common stock issuable upon the exercise of warrants, each held byElevado; (D) (i) 90,910 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 75,550 shares of common stockissuable upon the exercise of warrants, each held by EMSE; (E) (i) 181,819 shares of common stock issuable upon conversion of shares of Series BPreferred Stock, and (ii) 343,168 shares of common stock issuable upon the exercise of warrants, each held by EZ Colony; (F) (i) 45,455 shares ofcommon stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 53,234 shares of common stock issuable upon the exercise ofwarrants, each held by the Marital Trust; and (H) (i) 45,455 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and(ii) 49,452 shares of common stock issuable upon the exercise of warrants, held by the Family Trust. (19)Based solely on a Schedule 13G filed by Marc Ezralow on February 14, 2017. Collectively, the shares of Common Stock reported herein in which MarcEzralow has shared voting and dispositive power over such shares are an aggregate of 1,011,451 shares. Such shares are held directly by (a) the EzralowFamily Trust u/t/d 12/9/1980 (the “Family Trust”) in the amount of 36,723 shares, where Marc Ezralow, as a co-trustee of the Family Trust, sharesvoting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; (b) the Ezralow Marital Trust u/t/d 1/12/2002(the “Marital Trust”) in the amount of 42,583 shares, where Marc Ezralow, as a co-trustee of the Marital Trust, shares voting and dispositive power oversuch shares, and thus, may be deemed to beneficially own such shares; (c) Elevado Investment Company, LLC, a Delaware limited liability company(“Elevado Investment”), in the amount of 140,821 shares, where Marc Ezralow as a co-trustee and manager, respectively, of the two trusts and limitedliability company that comprise the managing members of Elevado Investment, shares voting and dispositive power over such shares, and thus, bedeemed to beneficially own such shares; (d) EMSE LLC (“EMSE”), a Delaware limited liability company, in the amount of 81,949 shares, where MarcEzralow, as a manager of EMSE shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; (e) EZColony Partners, LLC, a Delaware limited liability company (“EZ Colony”), in the amount of 709,372 shares, where Marc Ezralow as the sole trustee ofone of the trusts that is a manager of EZ Colony, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially ownsuch 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 asthe 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 liabilitycompany that comprise the managing members of one of the other managers of EZ MM&B, shares voting and dispositive power over such shares, andthus, 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 are210,115 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 175,266 shares, where Marc Ezralow as sole trustee of the Marc Trust has sole voting and dispositive power over such shares, and thus, maybe deemed to beneficially own such shares; and (b) the SPA Trust u/t/d 9/13/2004 (the “SPA Trust”), in the amount of 34,849 shares, where MarcEzralow as sole trustee of the SPA Trust has sole voting and dispositive power over such shares, and thus, may be deemed to beneficially own suchshares. (20)In addition, Marc Ezralow beneficially owns an aggregate of 1,769,416 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: (A) (i) 45,455 shares of commonstock issuable upon conversion of shares of Series B Preferred Stock and (ii) 68,546 shares of common stock issuable upon exercise of warrants, eachheld the SPA Trust; (B) (i) 136,364 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 297,273 shares ofcommon stock issuable upon exercise of warrants, each held by the 1997 Trust; (C) (i) 136,364 shares of common stock issuable upon conversion ofshares of Series B Preferred Stock, and (ii) 200,371 shares of common stock issuable upon the exercise of warrants, each held by Elevado; (D) (i) 90,910shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 75,550 shares of common stock issuable upon theexercise of warrants, each held by EMSE; (E) (i) 181,819 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and(ii) 343,168 shares of common stock issuable upon the exercise of warrants, each held by EZ Colony; (F) (i) 45,455 shares of common stock issuableupon conversion of shares of Series B Preferred Stock, and (ii) 53,234 shares of common stock issuable upon the exercise of warrants, each held by theMarital Trust; and (H) (i) 45,455 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 49,452 shares ofcommon stock issuable upon the exercise of warrants, held by the Family Trust. To Lilis’s knowledge, except as noted above, no person or entity is the beneficial owner of 5% or more of Lilis’s common stock. 74  Item 13.Certain Relationships and Related Transactions, and Director Independence Related Party Transactions We describe below transactions and series of similar transactions, since January 1, 2016, 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 lasttwo completed fiscal years; and·Any of our directors, executive officers, or holders of more than 5% of our capital stock, or any member of the immediate family of, orperson sharing 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 the followingsummaries of related party transactions have not been adjusted to reflect the 1-for-10 reverse split of our issued and outstanding common stock, unlessspecifically 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 “Purchasers”) inconnection with the Series B preferred stock offering. For more information on the Series B preferred stock offering see Note 13-Shareholders Equity. On June 6, 2016, as subsequently amended, we entered into a Transaction Fee Agreement with TRW, a more than 5% shareholder of our companyduring the year ended December 31, 2016, in connection with the Series B preferred stock offering to act as co-broker dealers along with KES7, and asadministrative 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 into the Series B preferredstock offering in exchange for 150 shares of Series B preferred stock and the related warrants to purchase 68,182 shares of common stock at an exercise priceof $2.50. These fees were recorded as a reduction to equity. Certain other Purchasers in the Series B preferred stock offering include certain of our related parties, such as Abraham Mirman, our Chief ExecutiveOfficer and a director, through the Bralina Group, LLC for which Mr. Mirman holds shared voting and dispositive power ($1.65 million); Ronald D. Ormand,the Chairman of our Board of Directors through Perugia Investments LP for which Mr. Ormand holds sole voting and dispositive power ($1.0 million), KevinNanke, the Company’s former Executive Vice President and Chief Financial Officer during the year ended December 31, 2016, through KKN Holdings LLC,for which Mr. Nanke holds sole voting and dispositive power ($200,000), R. Glenn Dawson, a director of our company ($125,000), Pierre Caland throughWallington Investment Holdings, Ltd. a more than 5% shareholder of our company ($250,000) during the year ended December 31, 2016 and Bryan Ezralowand Marc Ezralow through various entities beneficially owned by them ($1.3 million). Credit and Guarantee Agreement and Warrant Reprice On September 29, 2016, we entered into the Credit Agreement. For more information about the Credit Agreement see Management’s Discussion andAnalysis—Credit Agreement and Warrant Reprice. Certain parties to the Credit Agreement included certain of our related parties such as TRW, acting as collateral agent, and Bryan Ezralow, MarcEzralow and Marshall Ezralow through certain of their investment entities ($2.8 million). Debenture Conversion Agreement On December 29, 2015, we entered into the Debenture Conversion Agreement with all of the remaining holders of the Debentures. For moreinformation about the Debentures see Management’s Discussion and Analysis—Debentures. Certain parties to the Debenture Conversion Agreement included certain of our related parties at that time, such as the Steven B. Dunn and LauraDunn Revocable Trust dated 10/28/10, of which its respective Debenture amount converted was approximately $1.02 million, Bryan Ezralow through EZColony Partners, LLC of which his respective Debenture amount converted was approximately $1.54 million and Pierre Caland through WallingtonInvestment Holdings, Ltd., of which its respective Debenture amount converted was approximately $2.09 million. Steven B. Dunn and Laura DunnRevocable Trust dated October 28, 2010 who held more than 5% of our Common Stock during the year ended December 31, 2016. 75  Series A Preferred Stock On May 30, 2014, we entered into a securities purchase agreement with accredited investors, pursuant to which it issued an aggregate of $7.5 millionin Series A preferred stock with a conversion price of $24.10 and warrants to purchase up to 155,602 shares of common stock. On June 23, 2016, after the receipt of requisite stockholder approval and in connection with the consummation of the Merger, all outstanding sharesof Series A preferred stock were converted into common stock at a reduced conversion price of $5.00 a share, resulting in the issuance of 1,500,000 shares ofcommon stock. In exchange for the reduction in conversion price from $24.10 per share to $5.00 per share, all accrued but unpaid dividends were forfeited. Several of our officers, directors and affiliates were investors in the Series A preferred stock and converted their shares at $5.00 including AbrahamMirman ($250,000), Ronald D. Ormand (through Perugia Investments ($500,000), Nuno Brandolini ($100,000), General Merrill McPeak ($250,000), TRW($779,000) and Pierre Caland through Wallington Investment Holdings, Ltd. ($125,000). Convertible Notes In a series of transactions from December 29, 2015 to May 6, 2016, we issued an aggregate of approximately $5.8 million in Convertible Notesmaturing on June 30, 2016 and April 1, 2017 at a conversion price of $5.00 and warrants to purchase an aggregate of approximately 2.3 million shares ofcommon stock with an exercise price of $2.50 for warrants issued between December 2015 and March 2016 and $0.10 for the warrants issued in May 2016.The purchasers include certain of our related parties, including Abraham Mirman, our Chief Executive Officer and director of our company ($750,000), theBruin Trust (the “Bruin Trust”), an irrevocable trust managed by an independent trustee and whose beneficiaries include the adult children of Ronald D.Ormand, Chairman of our Board of Directors ($1.15 million), General Merrill McPeak, a director of our company ($250,000), Nuno Brandolini, a director ofour company ($250,000), Glenn Dawson, a director of our company ($50,000), Kevin Nanke, the Company’s former Executive Vice President and ChiefFinancial Officer during the year ended December 31, 2016 ($100,000, which was reinvested instead of a cash bonus payment due to Mr. Nanke pursuant tohis prior executive employment agreement), Pierre Caland through Wallington Investment Holdings, Ltd. ($300,000), who held more than 5% of ourcommon stock during the year ended December 31, 2016, Bryan and Marc Ezralow, through various entities who held more than 5% of our common stockduring the year ended December 31, 2016 ($905,381) and TRW ($400,000). Subsequently, warrants to purchase up to 620,000 shares of common stock issued in connection with the Convertible Notes between December 2015and March 2016 were amended and restated to reduce the exercise price to $0.10 in exchange for additional consideration given to us in the form ofparticipation in the May Convertible Notes offering. Of those warrants, a total of 80,000 warrants were exercised. Additionally, during the three monthsended June 30, 2016, in exchange for several offers to immediately exercise a portion of each investor’s outstanding warrants issued between 2013 and 2014,we reduced the exercise price on warrants to purchase a total of 416,454 shares of common 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 issuance of an aggregate amount of 300,706 shares of common stock due to certaincashless exercises. TRW net exercised warrants to purchase 80,000 shares of common stock at a reset exercise price of $0.10, resulting in the issuance of75,820 shares. TRW also received an advisory fee on the Convertible Notes in the amount of $350,000, which was subsequently reinvested in full into the Series BPreferred Offering for 350 shares of Series B Preferred Stock and related warrants to purchase up to 159,091 shares of common stock. On June 23, 2016, we entered into the Note Conversion Agreement. Certain parties to the Note Conversion Agreement include certain of our relatedparties, such as each officer and director who invested in the Notes, each of whom converted their outstanding amounts in full. In addition, Pierre Caland,through Wallington Investments, Ltd., was signatory to the Note Conversion Agreement and converted its outstanding amounts in full. On August 3, 2016, we entered into the first amendment to the Notes with the remaining holders of approximately $1.8 million of our Notes. Each ofBryan Ezralow and Marc Ezralow through various entities and TRW was a party to the first amendment. For a detailed description of the first amendment tothe Convertible Notes see—Note 8—Long Term Debt. 76  SOS In connection with the Merger, SOS, Brushy’s former subordinated lender, and a more than 5% shareholder of our Company during the year endedDecember 31, 2016, agreed to extinguish approximately $20.5 million of its outstanding debt in exchange for Brushy’s divestiture of its properties to SOS inthe Giddings Field, the SOS Note and the SOS Warrant, which was completed on June 23, 2016. March 2017 Private Placement On February 28, 2017, we entered into a Securities Purchase Agreement in connection with the March 2017 Private Placement. For more informationon the March 2017 Private Placement see Management’s Discussion and Analysis—Liquidity and Capital Resources—Subsequent Events—March 2017Private Placement. The subscribers include certain of our related parties, including Bryan and Marc Ezralow through various entities ($2.6 million) and TRW, describedfurther below. G. Tyler Runnels and T.R. Winston We have participated in several transactions with TRW, of which G. Tyler Runnels, a former member of our Board of Directors, is chairman andmajority owner. During the year ended December 31, 2016, Mr. Runnels beneficially held more than 5% of our common stock, including the holdings ofTRW and his personal holdings, and has personally participated in certain transactions with us. On January 31, 2014, we entered into the Debenture Conversion Agreement with all of the holders of the Debentures, including TRW and Mr.Runnels’ personal trust. On June 23, 2016, all of the outstanding Debentures were converted at $5.00. See “—Debenture Conversion Agreement.” On May 3, 2016 through May 5, 2016, in exchange for several offers to immediately exercise outstanding warrants issued between 2013 and 2014,we reduced the exercise price on warrants to purchase a total of 265,803 shares of common stock from a range of $42.50 to $25.00 per share to $0.10 per sharewhich resulted in the issuance of a total of 250,520 shares of common stock. TRW received a total of 758,203 shares of common stock in this transaction. On June 6, 2016, as subsequently amended, we entered into a Transaction Fee Agreement with TRW in connection with the Series B preferred stockoffering. See “—Series B Private Placement.” 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. On February 28, 2017, we entered into a Subscription Agreement in connection with the March 2017 Private Placement, for which TRW acted asplacement agent and received a fee of $459,060. Additionally, TRW was a participant in the offering for an aggregate amount of $750,000. Ronald D. Ormand On March 20, 2014, we entered into an Engagement Agreement (the “Engagement Agreement”) with MLV & Co. LLC (“MLV”), which is nowowned by FBR & Co., after it acquired MLV in September of 2015, pursuant to which MLV acted as our exclusive financial advisor. Ronald D. Ormand, amember of our Board of Directors since February 2015 and the current Executive Chairman of our Board of Directors, was previously the Managing Directorand Head of the Energy Investment Banking Group at MLV. The Engagement Agreement provided for a fee of $25,000 to be paid monthly to MLV, subjectto certain adjustments and other specific fee arrangements in connection with the nature of financial services being provided. We expensed $75,000 and$175,000 for the three and six months ended June 30, 2015, respectively. On May 27, 2015, MLV agreed to take $150,000 of its accrued fees in our commonstock and was issued 75,000 shares in lieu of payment. The closing share price on May 27, 2015 was $1.56. The term of Engagement Agreement expired onOctober 31, 2015. On November 8, 2016, we paid FBR $100,000 as final settlement of outstanding fees owed under the Engagement Agreement. Additionally, MLV had been involved in certain initial discussions relating to the Merger for which it did not receive a fee. 77  Agreements with Former Executive Officers Kevin Nanke, Former Executive Vice President and Chief Financial Officer On February 13, 2017, we entered into a Separation and Release of Claims Agreement (the “Separation Agreement”) with Mr. Nanke, providing forhis separation as an officer of our company, effective January 23, 2017. Pursuant to the Separation Agreement and the terms of his employment agreement,Mr. Nanke will receive (1) a lump sum severance payment in an amount equal to 24 months of base salary in effect immediately prior to the date oftermination, (2) a lump sum payment equal to 24 months of COBRA premiums based on the terms of our group health plan and Mr. Nanke’s coverage undersuch plan as of the date of termination, and (3) a lump sum bonus payment of $175,000. For consideration of the separation benefits listed above, Mr. Nanke(1) provided a general release of claims against us, our affiliates, and related parties, (2) to the extent reasonable, shall continue to provide full and continuedcooperation in good faith with our company, our subsidiaries, and affiliates for 24 months following the date of termination in connection with certainmatters relating to our company, and (3) agreed to be bound by confidentiality commitments to our company. Additionally, pursuant to Mr. Nanke’s former employment agreement with us, dated as of March 18, 2016, he was entitled to receive a performancebonus of $100,000 if we were to achieve certain compliance goals set forth therein. In May 2016, our Board of Directors approved the reinvestment by Mr.Nanke of his performance bonus in the amount of $100,000 into the May Offering, pursuant to the same terms as the May Offering. Edward Shaw, Former Executive Vice President and Chief Operating Officer of the Company On February 13, 2017, we entered into a Separation and Release of Claims Agreement (the “Settlement Agreement”) with Mr. Shaw, providing forhis separation as an officer of our company, effective January 24, 2017 (the “Separation Date”). Pursuant to the Settlement Agreement, Mr. Shaw received (1)a lump sum severance payment in an amount equal to 3 months of base salary in effect immediately prior to the date of termination, (2) a lump sum paymentequal to 3 months of COBRA premiums based on the terms of our group health plan and Mr. Shaw’s coverage under such plan as of the date of termination,and (3) a period of three months from the separation date to exercise all vested options. For consideration of the separation benefits listed above, Mr. Shaw (1)provided a general release of claims against us, our affiliates, and related parties, (2) to the extent reasonable, shall continue to provide full and continuedcooperation in good faith with our company, our subsidiaries, and affiliates for 24 months following the date of termination in connection with certainmatters relating to our company, and (3) agreed to be bound by confidentiality commitments to our company. For additional information on the above-mentioned agreements, see “Employment Agreements and Other Arrangements” above. Compensation of Directors See “Executive Compensation—Compensation of Nonemployee Directors” above. Conflict of Interest Policy Our Board of Directors has recognized that transactions between us and certain related persons present a heightened risk of conflicts of interest. Wehave a corporate conflict of interest policy that prohibits conflicts of interests unless approved by our Board of Directors. Our Board of Directors hasestablished a course of conduct whereby it considers in each case, whether the proposed transaction is on terms as favorable or more favorable to us thanwould be available from a non-related party. Our Board of Directors also looks at whether the transaction is fair and reasonable to us, taking into account thetotality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us. Each of therelated party transactions described above was presented to our Board of Directors for consideration and each of these transactions was unanimouslyapproved by our Board of Directors after reviewing the criteria set forth in the preceding two sentences. 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 firm Marcum LLP for the years ended December 31, 2016 and 2015: 78  Year Ended December 31, Fee Category 2016 2015 (In thousands) Audit Fees $358 $264 Audit-Related Fees 341 5 Tax Fees - - All Other Fees - - Total Fees $699 $269 Audit Fees consist of the aggregate fees for professional services rendered for the audit of our annual financial statements and the reviews of thefinancial statements included in our Quarterly Reports on Forms 10-Q and for any other services that were normally provided by our auditors in connectionwith 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. Majority of these services were related to the Brushy merger. Tax Fees consist of the aggregate fees billed for professional services rendered for tax consulting. Included in such Tax Fees were fees forconsultancy, review, and advice related to our income tax provision and the appropriate presentation on our financial statements of the income tax relatedaccounts. 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, 2016, we had no non-auditservices provided by our independent registered public accounting firm. 79  PART IV Item 15. Exhibits, Financial Statement Schedules a)Index to Financial Statements Report of Independent Registered Public Accounting FirmF-1Consolidated Balance Sheets as of December 31, 2016 and 2015F-2Consolidated Statements of Operations for the years ended December 31, 2016 and 2015F-4Consolidated Statements of Stockholders’ Equity (Deficit) for the years ended December 31, 2016 and 2015.F-5Consolidated Statements of Cash Flows for the years ended December 31, 2016 and 2015F-6Notes to Consolidated Financial StatementsF-7 b)Exhibits The information required by this Item is set forth on the exhibit index that follows the signature page to this Annual Report on Form 10-K and is incorporatedherein by reference. c)Financial Statement Schedules Not applicable. 80  SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on itsbehalf by the undersigned, thereunto duly authorized. LILIS ENERGY, INC. Date: March 3, 2017By:/s/ Abraham Mirman Abraham Mirman 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/ Abraham Mirman Chief Executive Officer, Director March 3, 2017Abraham Mirman (Principal Executive Officer) /s/ Joseph C. Daches Executive Vice President and Chief Financial Officer March 3, 2017Joseph C. Daches (Principal Financial and Accounting Officer) /s/ Ronald D. Ormand Executive Chairman of the Board March 3, 2017Ronald D. Ormand /s/ Peter Benz Director March 3, 2017Peter Benz /s/ Nuno Brandolini Director March 3, 2017Nuno Brandolini /s/ R. Glenn Dawson Director March 3, 2017R. Glenn Dawson /s/ General Merrill McPeak Director March 3, 2017General Merrill McPeak 81  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. and BrushyResources, 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).3.1Amended and Restated Articles of Incorporation of Recovery Energy, Inc., dated as of October 10, 2011 (incorporated herein by reference toExhibit 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 of June12, 2014 (incorporated herein by reference to Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31,2014, filed on June 17, 2014).3.5Certificate 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 onOctober 31, 2014).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).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 January 5,2016).4.9Form of Warrant (incorporated herein by reference to Exhibit 4.1 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 to theCompany’s Quarterly Report on Form 10-Q filed on August 25, 2016).4.12Form of Warrant (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on February 28, 2017).4.13Form 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).4.14†Lilis Energy, Inc. 2016 Omnibus Incentive Plan and forms of agreement thereunder (incorporated herein by reference to Exhibit 4.1 to theCompany’s Current Report on Form 8-K 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 reference toAnnex C to the Company’s Definitive Proxy filed on September 30, 2016).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 the Company’sAnnual 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 Annex A to theCompany’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. and SOSventures,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 as placementagent, and each Debenture holder (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed onJanuary 5, 2016).  10.8Form of Convertible Note Purchase Agreement (incorporated herein by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K filed on January 5, 2016).10.9Form of Note Exchange Agreement (incorporated herein by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K filed onJanuary 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-K filedon 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-K filedon 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 the Company’sCurrent Report on Form 8-K filed on July 8, 2016).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 the Company’sCurrent 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 herein byreference 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, 2016 filedon 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 Signature Bank(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 filedon 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 filed onJuly 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., ImPetro Operating,LLC, ImPetro Resources, LLC, the Lenders party thereto and T.R. Winston & Company, LLC acting as collateral agent (incorporated hereinby 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, 2016.10.29†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 filed on February 17, 2017).10.30Securities Subscription Agreement, dated February 28, 2017, by and among the Company and the Purchasers thereto (incorporated herein byreference 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).21.1*List of Subsidiaries of the Company.23.1*Consent of Marcum LLP, for the Company.23.2*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 200232.2*Certifications Pursuant to Section 906 of Sarbanes Oxley Act of 200299.1*Report of Cawley, Gillespie & Associates, Inc., dated January 12, 2016, for the Company101.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.  Report of Independent Registered Public Accounting Firm To the Audit Committee of theBoard of Directors and Shareholdersof Lilis Energy, Inc. and Subsidiaries We have audited the accompanying consolidated balance sheets of Lilis Energy, Inc. and Subsidiaries (the “Company”) as of December 31, 2016and 2015, and the related consolidated statements of operations, changes in stockholders’ equity (deficit) and cash flows for the years then ended. Thesefinancial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based onour audits. We conducted our audits 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 audits provide 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. andSubsidiaries, as of December 31, 2016 and 2015, and the consolidated results of its operations and its cash flows for the years then ended in conformity withaccounting principles generally accepted in the United States of America. /s/ Marcum LLPMarcum LLPNew York, NYMarch 3, 2017 F-1  Lilis Energy, Inc. and SubsidiariesConsolidated Balance Sheets(In thousands, except share and per share data) December 31, 2016 2015 ASSETS Current assets: Cash and cash equivalents $11,738 $110 Accounts receivables, net of allowance of $106 and $80, respectively 2,247 952 Prepaid expenses and other current assets 767 79 Total current assets 14,752 1,141 Oil and gas properties, full cost method of accounting Unproved 24,461 - Proved 69,809 50,096 Less: accumulated depreciation, depletion, amortization and impairment (55,771) (49,573)Total oil and gas properties, net 38,499 523 Other property and equipment, net 52 44 Other assets 216 2,000 Total other assets 268 2,044 Total assets $53,519 $3,708 The accompanying notes are an integral part of these consolidated financial statements. F-2  Lilis Energy, Inc. and SubsidiariesConsolidated Balance Sheet(In thousands, except share and per share data) December 31, 2016 2015 LIABILITIES, REDEEMABLE PREFERRED STOCK AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable $5,166 $1,331 Accrued liabilities 2,706 3,496 Dividends payable 808 719 Asset retirement obligations 338 - Current portion of long-term debt 17 11,067 Total current liabilities 9,035 16,613 Asset retirement obligations 919 209 Long-term debt 30,226 - Long-term derivative liabilities 1,400 56 Total liabilities 41,580 16,878 Commitments and contingencies (Note 9) 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 1,173 Stockholders’ Equity (Deficit): Series A Preferred stock, $0.0001 par value; stated rate $1,000:10,000 shares authorized, 0 and 7,500 shares issuedand outstanding as of December 31, 2016 and 2015, respectively. - 6,794 Series B Preferred stock, $0.0001 par value; stated rate $1,000: 20,000 shares authorized; 17,000 and 0 sharesissued and outstanding at December 31, 2016 and 2015, respectively, with a liquidation preference of $20,627 atDecember 31, 2016. 13,432 - Common stock, $0.0001 par value per share; 100,000,000 shares authorized, 20,918,901 and 2,786,275 sharesissued and outstanding as of December 31, 2016 and 2015, respectively. 2 - Additional paid-in capital 219,837 159,773 Accumulated deficit (223,206) (180,910)Total stockholders’ equity (deficit) 10,065 (14,343) Total liabilities, redeemable preferred stock and stockholders’ equity $53,519 $3,708 The accompanying notes are an integral part of these consolidated financial statements F-3  Lilis Energy, Inc. and SubsidiariesConsolidated Statements of Operations(In thousands, except share and per share data) Years Ended December 31, 2016 2015 Oil, natural gas and natural gas liquid sales $3,435 $396 Costs and expenses: Production costs 1,247 195 Production taxes (167) 28 General and administrative 14,570 7,930 Depreciation, depletion and amortization 1,566 574 Accretion of asset retirement obligations 132 10 Impairment of evaluated oil and gas properties 4,718 24,478 Total operating expenses 22,066 33,215 Loss from operations (18,631) (32,819) Other income (expenses): Other income 90 3 Debt conversion inducement expense (8,307) - Gain on extinguishment of debt 250 - Gain (loss) in fair value of derivative instruments (1,222) 1,638 Gain (loss) in fair value of conditionally redeemable 6% preferred stock (701) 514 Gain on modification of convertible debts 602 - Interest expense (4,924) (1,697)Total other income (expenses) (14,212) 458 Net loss (32,843) (32,361)Dividends on redeemable preferred stock (407) (120)Loss on extinguishment of Series A Convertible Preferred Stock (540) - Dividend and deemed dividend Series B Convertible Preferred stock (8,506) (600)Net loss attributable to common stockholders $(42,296) $(33,081) Net loss per common share basic and diluted $(3.73) $(12.13)Weighted average common shares outstanding: Basic and diluted 11,328,252 2,726,775 The accompanying notes are an integral part of these consolidated financial statements. F-4  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, January 1, 2015 7,500 $6,794 - $- 2,699,273 $- $155,101 $(147,829) $14,066 Issuances of common stock - - - - 87,002 - 365 - 365 Fair value of warrants issued for professionalservices - - - - - - 425 - 425 Fair value of warrants issued for bridge termloan - - - - - - 1,222 - 1,222 Stock based compensation - - - - - - 2,660 - 2,660 Dividend Preferred stockholders - - - - - - - (120) (120)Deemed dividend Series A ConvertiblePreferred Stock - - - - - - - (600) (600)Net loss - - - - - - - (32,361) (32,361)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 for financing costs - - - - - - 713 - 713 Issuance and repricing of warrants to induceconversion - - - - - - 8,307 - 8,307 Gain on modification of convertible debentures - - - - - - (602) - (602)Fair value of warrants issued for debt discount - - - - - - 1,479 - 1,479 Common stock issued for conversion ofconvertible notes and accrued interest - - - - 6,778,115 1 14,871 - 14,872 Common stock and warrants issued inconnection with the Brushy merger - - - - 5,785,119 - 7,111 - 7,111 Series B Preferred stock issued for cash, net offees - - 20,000 18,195 - - - - 18,195 Warrants issued for Series B Preferred Stockoffering fees - - - (1,590) - - 1,590 - - Common stock issued for conversion of SeriesA Preferred Stock and accrued dividends (7,500) (6,794) - - 1,500,000 1 7,681 - 888 Loss on extinguishment of Series A PreferredStock - - - - - - 540 (540) - Common stock issued for conversion of SeriesB Preferred Stock and accrued dividends - - (3,000) (3,173) 2,937,018 - 3,230 - 57 Dividends and deemed dividends for PreferredStock - - - - - - 7,879 (8,913) (1,034)Net Loss - - - - - - - (32,843) (32,843)Balance, December 31, 2016 - $- 17,000 $13,432 20,918,901 $2 $219,837 $(223,206) $10,065 The accompanying notes are an integral part of these consolidated financial statements. F-5  Lilis Energy, Inc. and SubsidiariesConsolidated Statements of Cash Flows(In thousands) Years Ended December 31, 2016 2015 Cash flows from operating activities: Net loss $(32,843) $(32,361)Adjustments to reconcile net loss to net cash used in operating activities: Equity instruments issued for services and compensation 7,078 3,450 Bad debt expense 494 - Inducement Expense 8,307 - Amortization of deferred financing cost 328 52 Accretion of debt discount 2,857 - Gain on extinguishment of debt (250) - Gain (loss) in fair value of derivative instruments 1,222 (1,604)Gain (loss) in fair value of conditionally redeemable 6% preferred stock 701 (514)Gain on modification of convertible debt (602) - Depreciation, depletion, amortization and accretion of asset retirement obligation 1,698 584 Impairment of evaluated oil and gas properties 4,718 24,478 Changes in operating assets and liabilities: Accounts receivable (1,264) (120)Other assets 1,554 57 Accounts payable, accrued expenses and other liabilities (307) 2,027 Net cash used in operating activities (6,309) (3,951) Cash flows from investing activities: Cash advance to Brushy Resources, Inc. - (1,750)Cash consideration for Brushy merger, net of cash acquired (2,302) - Restricted cash - 145 Capital expenditures (16,828) (98)Net cash used in investing activities (19,130) (1,703) Cash flows from financing activities: Net proceeds from issuance of Series B Preferred Stock 18,195 - Proceeds from bridge notes, net 2,863 5,950 Proceeds from warrant exercise 187 - Dividend payments on preferred stock - (180)Debt issuance costs (1,299) (266)Proceeds from issuance of term loan 31,000 - Repayment of debt (13,879) (250)Net cash provided by financing activities 37,067 5,254 Increase (decrease) in cash 11,628 (400)Cash at beginning of period 110 510 Cash at end of period $11,738 $110 Supplemental disclosure: Cash paid for interest $762 $365 The accompanying notes are an integral part of these consolidated financial statements. F-6  Lilis Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements NOTE 1 – ORGANIZATION On September 21, 2007, Universal Holdings, Inc. (“Universal”), a Nevada corporation, completed the acquisition of Coronado Acquisitions, LLC(“Coronado”). Under the terms of the acquisition, Coronado was merged into Universal. On October 12, 2009, Universal changed its name to RecoveryEnergy, Inc. On December 1, 2013, Recovery Energy, Inc. changed its name to Lilis Energy, Inc. (“Lilis”, “Lilis Energy” and the “Company”). The Company is an independent oil and gas exploration and production company focused on the Delaware Basin in Winkler and Loving Counties,Texas and Lea County, New Mexico and the Denver-Julesburg Basin (“DJ Basin”) in Wyoming, Colorado, and Nebraska. On June 23, 2016, the Company effected a 1-for-10 reverse stock split of its Common Stock (the “Reverse Split”). The accompanying consolidatedfinancial statements and these notes to the consolidated financial statements give retroactive effect to the Reverse Split for all periods presented. All references to production, sales volumes and reserves quantities are net to the Company’s interest unless otherwise indicated. NOTE 2 – MANAGEMENT PLANS AND LIQUIDITY The Company has reported net operating losses during the year ended December 31, 2016 and for the past five years. As a result, the Companyfunded its operations in 2016 and the merger with Brushy Resources, Inc. through additional debt and equity financing. On September 29, 2016, theCompany entered into a new Credit and Guaranty Agreement (the “Credit Agreement”) that provides for a three-year, senior, secured term loan with initialaggregate principal commitments of $31 million and a maximum facility size of $50 million. The term loan was funded in two draws, with $25 millioncollected as of September 30, 2016 and the additional $6 million collected as of November 11, 2016. As of December 31, 2016, the Company had a working capital balance and a cash balance of approximately $5.7 million and $11.7 million,respectively. As of March 1, 2017, the Company’s cash balance was approximately $9.0 million, which included a drawdown of additional principal under itsCredit Agreement on February 7, 2017 of $7.1 million and excluded net proceeds of the equity offering completed on March 1, 2017, or approximately $18.6million. The Company believes that it will have sufficient capital to operate over the next 12 months from the date of the filing of this annual report.However, it is possible that the Company will seek to raise additional debt, equity capital, or both depending on the pace of its drilling and leasing activity. NOTE 3 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND ESTIMATES Principles of Consolidation The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. The Company’s wholly ownedsubsidiaries include Brushy Resources, Inc (“Brushy”), ImPetro Operating, LLC (“ImPetro Operating”) and ImPetro Resources, LLC (“ImPetro”), and LilisOperating Company, LLC (“Lilis Operating”). All significant intercompany accounts and transactions have been eliminated in consolidation. Use of Estimates The preparation of consolidated financial statements in conformity with generally accepted accounting principles in the United States (“U.S.GAAP”) requires the Company to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities; disclosure ofcontingent assets and liabilities at the date of the financial statements; the reported amounts of revenues and expenses during the reporting period; and thequantities and values of proved oil, natural gas and NGL reserves used in calculating depletion and assessing impairment of its oil and gas properties. F-7  The most significant financial estimates are associated with the Company’s estimated volumes of proved oil and natural gas reserves, assetretirement obligations, assessments of impairment imbedded in the carrying value of undeveloped acreage and undeveloped properties, fair value of financialinstruments, including derivative liabilities, depreciation and accretion, income taxes and contingencies. Although management believes that these estimatesare reasonable, actual results could differ significantly from those estimates. Reclassifications Certain prior-period amounts have been reclassified for comparative purposes to conform with the fiscal 2016 presentation. These reclassificationshave no effect on the Company’s previously reported results of operations. Cash and Cash Equivalent Cash and cash equivalents include highly liquid instruments with an original maturity of three months or less when purchased to be cashequivalents as these instruments are readily convertible to known amounts of cash and do not bear significant risk of changes in value due to their shortmaturity period. Accounts Receivable The Company records actual and estimated oil and gas revenue receivable from third parties at its net revenue interest. The Company also reflectscosts incurred on behalf of joint interest partners. The Company typically has the right to withhold future revenue disbursements to recover outstanding jointinterest billings on outstanding receivables from joint interest owners. Management periodically reviews accounts receivable amounts for collectability andrecords its allowance for uncollectible receivables using the allowance method based on past experience. Allowance for doubtful accounts are basedprimarily on joint interest billings for expenses related to oil and natural gas wells. Receivables which derive from sales of certain oil and gas production arecollateral under the Company’s Credit Agreement. Concentration of Credit Risk The Company’s cash is invested at major financial institutions primarily within the United States. At December 31, 2016 and 2015, the Company’scash was maintained in accounts that are insured up to the limit determined by the federal governmental agency. The Company may at times have balances inexcess of the federally insured limits. Periodically, the Company evaluates the creditworthiness of the financial institutions, and has not experienced anylosses in such accounts. Significant Customers The Company’s major customers include, Noble Energy, Texican and Energy Transfer, Inc. These customers accounted for approximately 41%, 38%and 16% of the Company’s revenue for the year ended December 31, 2016. The Company’s major customers include, Shell Trading (US), PDC Energy andNoble Energy, which accounted for approximately 43%, 26% and 21% of its revenue for the year ended December 31, 2015. However, the Company believe that the loss of a single purchaser could not materially affect the Company’s business because alternative purchasersare available. Reserves All of the reserves data included herein are estimates. Estimates of the Company’s crude oil and natural gas reserves are prepared in accordance withguidelines established by the Securities Exchange Commission (“SEC”), including rule revisions designed to modernize the oil and gas company reservesreporting requirements, which the Company implemented effective December 31, 2010. Reservoir engineering is a subjective process of estimatingunderground accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and naturalgas reserves. Uncertainties include the projection of future production rates and the expected timing of development expenditures. The accuracy of anyreserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserves estimatesmay be different from the quantities of crude oil and natural gas that are ultimately recovered. In addition, the ability to produce economic reserves isdependent on the oil and gas prices used in the reserves estimate. The Company’s reserves estimates are based on 12-month average commodity prices, unlesscontractual arrangements otherwise designate the price to be used, in accordance with the SEC rules. However, oil and gas prices are volatile and, as a result,the Company’s reserves estimates may change in the future. F-8  Estimates of proved crude oil and natural gas reserves significantly affect the Company’s depreciation, depletion, and amortization (“DD&A”)expense. For example, if estimates of proved reserves decline, the DD&A rate will increase, resulting in a decrease in net income. A decline in estimates ofproved reserves could also result in an impairment charge, which would reduce earnings. Oil and Gas Properties The Company uses the full cost method of accounting for oil and gas operations. Under this method, costs related to the exploration, non-productionrelated development and acquisition of oil and natural gas reserves are capitalized. Such costs include land acquisition costs, geological and geophysicalexpenses, carrying charges on non-producing properties, costs of drilling, developing and completing productive wells and/or plugging and abandoningnon-productive wells, and any other costs directly related to acquisition and exploration activities. Proceeds from property sales are generally applied as acredit against capitalized exploration and development costs, with no gain or loss recognized, unless such a sale would significantly alter the relationshipbetween capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of provedreserves. 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 cost 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 gas reserves. Costs included in the depletion base to be amortized include (a) all proved capitalized costsincluding capitalized asset retirement costs net of estimated salvage values, less accumulated depletion, (b) estimated future development cost to be incurredin developing proved reserves; and (c) estimated decommissioning and abandonment/restoration costs, net of estimated salvage values, that are not otherwiseincluded 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 full cost pool which is subject to depletion calculations. Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes maynot exceed an amount equal to the sum of the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves and the costof unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that arenot subject to amortization. Should capitalized costs exceed this ceiling, an impairment expense is recognized. During 2016, commodity prices continued totrade in a low range. With low commodity prices sustained for the majority of 2016 in the DJ Basin, some of the Company’s properties became uneconomictriggering an impairment charge of $4.7 million at December 31, 2016. Due to the decline in commodity prices and lack of liquidity the Company recordedan impairment charge during the year ended December 31, 2015. During the years ended December 31, 2016 and 2015, the Company recorded $4.7 millionand $24.5 million impairment charges, respectively. 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 gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves (assumingthe 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 gas reserves in commercial quantities. Such wells continue to be classified as wells in progress and withheld from the depletion calculationand the ceiling test until such time as either proved reserves can be assigned, or the wells are otherwise abandoned. Upon either the assignment of provedreserves 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. F-9  Other Property and Equipment Property and equipment include office equipment and furniture which are stated at cost. Depreciation is calculated using the straight-line methodover the estimated useful lives of the assets. The estimated useful lives of property and equipment range from three to seven years. The Company recordedapproximately $0.04 million and $0.03 million of depreciation for the years ended December 31, 2016 and 2015, respectively. Impairment of Long-lived Assets The Company accounts for long-lived assets (other than oil and gas properties) at cost. The Company may impair these assets whenever events orchanges in circumstances indicate that the carrying amount of such assets may not be fully recoverable. Recoverability is measured by comparing thecarrying amount of an asset to the expected undiscounted future net cash flows generated by the asset. If it is determined that the asset may not berecoverable, and if the carrying amount of an asset exceeds its estimated fair value, an impairment charge is recognized to the extent of the difference. Asset Retirement Obligation The Company incurs retirement obligations for certain assets at the time they are placed in service. The fair values of these obligations are recordedas liabilities 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 calculations, the Company includes estimated dismantlement andabandonment cost, net of salvage values, associated with future development activities that have not yet been capitalized as asset retirement obligations.Asset retirement obligations incurred are classified as Level 3 (unobservable inputs) fair value measurements. The asset retirement liability is allocated tooperating expense using a systematic and rational method. Fair Value of Financial Instruments As of December 31, 2016 and 2015, the carrying value of cash and cash equivalents, accounts receivable, accounts payable, accrued expenses,interest and dividends payable and advance from joint interest partners approximates fair value due to the short-term nature of such items. The carrying valueof the Company’s secured debt is carried at cost which is approximately the fair value of the debt as the related interest rate are at the terms approximates ratescurrently available to the Company. 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, NGLs and gas 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.The Company had no material oil, NGL or gas entitlement assets or liabilities as of December 31, 2016 or 2015.Stock Based Compensation The Company measures the fair value of stock-based compensation expense awards made to employees and directors, including stock options,restricted stock units, and restricted stock, on the date of grant using a Black-Scholes model. For equity awards, compensation expense is based on the fairvalue on the grant or modification date and is recognized in the Company’s financial statements over the vesting period. The measurement of share-basedcompensation expense is based on several criteria, including but not limited to, the valuation model used and associated input factors, such as expected termof the award, stock price volatility, risk free interest rate, dividend rate and award cancellation rate. These inputs are subjective and are determined usingmanagement’s judgment. If differences arise between the assumptions used in determining share-based compensation expense and the actual factors, whichbecome known over time, the Company may change the input factors used in determining future share-based compensation expense. 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. F-10  Warrant Modification Expense The Company accounts for the modification of warrants as an exchange of the old award for a new award. The incremental value is measured as theexcess, if any, of the fair value of the modified award over the fair value of the original award immediately before modification, and is either expensed as aperiod expense or amortized over the performance or vesting date. The Company estimates the incremental value of each warrant using the Black-Scholesoption pricing model. The Black-Scholes model is highly complex and dependent on key estimates by management. The estimate with the greatest degree ofsubjective judgment is the estimated volatility of the Company’s stock price. Earnings (Loss) Per Share Basic income (loss) per share was calculated by dividing net income or loss applicable to common shares by the weighted average number ofcommon shares outstanding during the periods presented. The calculation of diluted income (loss) per share should include the potential dilutive impact ofshares issuable upon the conversion of debt or preferred stock, vested restricted stock and exercise of warrants and options during the period, unless theireffect is anti-dilutive. At December 31, 2016 and 2015, shares underlying restricted stock units, restricted stock, options, warrants, preferred stock anddebentures have been excluded from the diluted share calculations as they were anti-dilutive as a result of net losses incurred. The Company has included3,522,735 warrants, with an exercise price of $.01, in its earnings per share calculation for the year ended December 31, 2016. The Company had the following shares of Common Stock equivalents at December 31, 2016 and 2015: December 31, 2016 2015 Stock Options 5,956,833 6,083,333 Restricted Stock Units 149,584 1,869,000 Restricted Stock 1,068,305 - Series A Preferred Stock - 3,112,033 Series B Preferred Stock 15,454,545 - Stock Purchase Warrants 12,392,776 24,383,161 Convertible Debentures - 3,423,233 Convertible Bridge Notes - 5,900,004 35,022,043 44,770,764 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, 2016and 2015, 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, 2016 and 2015. Further, the Company does not expect that the total amount of unrecognized tax benefits willsignificantly increase or decrease during the next 12 months. 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. F-11  In January 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, 2017, and expects that the adoption of this ASU couldhave a material impact on future consolidated financial statements for acquisitions that are not considered to be businesses. The FASB issued ASU 2016-18, “Restricted Cash (Topic 230),” to clarify the presentation of restricted cash in the statement of cash flows. Theamendments require that a statement of cash flows explain the change during the period in restricted cash or restricted cash equivalents. In additions tochanges in cash and cash equivalents, restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling thebeginning-of-period and end-of-period total amounts shown on the statement of cash flows. As a result, transfers between cash and restricted cash will not bepresented as a separate line item in the operating, investing or financing section of the cash flow statement. The amendments are effect for public businessentities for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted. The Company willadopt this ASU in 2017. The adoption of this ASU will affect the presentations in the Company’s consolidated balance sheets and consolidated statement ofcash flows and will not materially impact the results of operations. In February 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. The effect of this guidance relating to the Company’s existing long-term leases will not have material impact on the Company’s consolidated financialstatements. As of December 31, 2016, the Company currently has only one 2-year operating lease. The FASB issued ASU 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting.This ASU will simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equityor liabilities, and classification on the statement of cash flows. This ASU is effective for annual and interim periods beginning in 2017 with early adoptionpermitted. The Company adopted this ASU on January 1, 2017 and does not believe that the simplification of accounting for share-based compensation andrelated income taxes will have a material impact on its consolidated financial statements. In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations(Reporting Revenue Gross versus Net). This ASU amends the principal versus agent guidance in ASU No. 2014-09, Revenue from Contracts with Customers(Topic 606), which was issued in May 2014 (“ASU 2014-09”). Further, in April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts withCustomers (Topic 606): Identifying Performance Obligations and Licensing. This ASU also amends ASU 2014-09 and is related to the identification ofperformance obligations and accounting for licenses. The effective date and transition requirements for both of these amendments to ASU 2014-09 are thesame as those of ASU 2014-09, which was deferred for one year by ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of theEffective Date. That is, the guidance under these standards is to be applied using a full retrospective method or a modified retrospective method, as outlinedin the guidance, and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption ispermitted only for annual periods, and interim period within those annual periods, beginning after December 15, 2016. The Company has not selected atransition method and is evaluating its revenue recognition policies and existing customer contracts to determine the impact this guidance will have on itsfinancial statements. In March 2016, the FASB issued ASU No. 2016-06, “Derivatives and Hedging (Topic 815): Contingent Put and Call Options in Debt Instruments”(“ASU 2016-06”). This new standard simplifies the embedded derivative analysis for debt instruments containing contingent call or put options by removingthe requirement to assess whether a contingent event is related to interest rates or credit risks. This new standard will be effective for the Company on January1, 2017. The Company expects the adoption of this standard may have material impact on the Company’s result of operations from its continued efforts inraising capital to fund its operations and develop its oil and gas properties from issuing convertible equity or debt instruments. 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), (“ASU 2016-15”). The amendments in ASU 2016-15 address eight specific cash flow issues and apply to all entities, including bothbusiness entities and not-for-profit entities that are required to present a statement of cash flows under FASB Accounting Standards Codification (FASB ASC)230, Statement of Cash Flows. The amendments in ASU 2016-15 are effective for public business entities for fiscal years beginning after December 15, 2017,and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The Company adopted this ASU onJanuary 1, 2017 and expects the adoption will only affect the classifications within the consolidated statement of cash flows. F-12  In September 2015, the FASB issued ASU No. 2015-16, “Business Combinations (Topic 805), Simplifying the Accounting for Measurement-PeriodAdjustments” (“ASU 2015-16”). The update requires that the acquirer in a business combination recognize adjustments to provisional amounts that areidentified during the measurement period in the reporting period in which the adjustment amounts are determined (not retrospectively as with priorguidance). Additionally, the acquirer must record in the same period’s financial statements the effect on earnings of changes in depreciation, amortization orother income effects as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the time of acquisition. Theacquiring entity is required to disclose, on the face of the financial statements or in the footnotes to the financial statements, the portion of the amountrecorded in current period earnings, by financial statement line item, that would have been recorded in previous reporting periods if the adjustment to theprovisional amounts had been recognized as of the acquisition date. The guidance in ASU No. 2015-16 is effective for fiscal years beginning afterDecember 15, 2015, including interim periods within those fiscal years. Earlier application is permitted for financial statements that have not been issued.The Company adopted this standard on January 1, 2016 and there were no material impact on its consolidated financial statements. In April 2015, the FASB issued ASU No. 2015-03 (“ASU 2015-03”), “Interest - Imputation of Interest (Subtopic 835-30): Simplifying thePresentation of Debt Issuance Costs.” ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet asa direct deduction from the carrying amount of the related debt liability, consistent with debt discounts, instead of being presented as an asset. ASU 2015-03is effective for the Company on January 1, 2016. Once adopted, entities are required to apply the new guidance retrospectively to all prior periods presented.The retrospective application represents a change in accounting principle. Early adoption is permitted for financial statements that have not been previouslyissued. The Company adopted this standard on January 1, 2016. The adoption of ASU 2015-03 only affects the presentation of the Company’s accompanyingconsolidated balance sheets and related financial statement disclosures in Note 9. In conjunction with the adoption of ASU 2015-03, $1.8 million and $0.2million of debt issuance costs, previously presented as part of other assets was included as part of long-term debt which was reclassified as a direct deductionfrom the carrying amount of that debt liability as of December 31, 2016 and 2015, respectively. In August 2014, the FASB issued ASU No. 2014–15 (“ASU 2014-15”), “Presentation of Financial Statements – Going Concern.” ASU 2014-15provides GAAP guidance on management’s responsibility in evaluating whether there is substantial doubt about a company’s ability to continue as a goingconcern and about related footnote disclosures. For each reporting period, management will be required to evaluate whether there are conditions or eventsthat raise substantial doubt about a company’s ability to continue as a going concern within one year from the date the financial statements are issued. Thenew standard is effective for the Company on January 1, 2017. As of December 31, 2016, the Company believes that it has sufficient capital to operate for thenext 12 months – see management’s assessment and analysis of its plans and liquidity in Note 2 - Management Plans and Liquidity above. NOTE 4 – OIL AND GAS PROPERTIES The following table sets forth a summary of oil and gas property costs (net of divestitures) not being amortized at December 31, 2016 and 2015: December 31, 2016 2015 (In thousands) Undeveloped unevaluated acreage Beginning Balance $- $2,886 Lease purchases 546 - Assets conveyed 23,915 - Transfer and other reclassification to evaluated properties - (2,886)Total undeveloped acreage $24,461 $- Wells in progress: Beginning Balance $- $6,042 Additions 7,453 - Disposition of wells in progress for elimination of accrued expenses for drilling - (5,198)Reclassification to evaluated properties - (844)Total wells in progress and not subject to DD&A $7,453 $- F-13  During the year ended December 31, 2016, the Company entered the Delaware Basin through the Merger. Since then, Lilis has increased itsDelaware Basin acreage position by 53% and has added 860 net contiguous acres further expanding its Delaware Basin footprint. At December 31, 2016 and2015, the Company completed an assessment of its inventory of unevaluated acreage, which resulted in a transfer of $0 and $2.9 million, respectively fromunevaluated acreage to evaluated properties. Depreciation, depletion and amortization (“DD&A”) expenses related to the proved properties were approximately $1.6 million and $0.6 million forthe years ended December 31, 2016 and 2015, respectively. NOTE 5 – MERGER WITH BRUSHY RESOURCES, INC. AND RELATED TRANSACTIONS On June 23, 2016, the Company completed the merger transaction contemplated by the Agreement and Plan of Merger dated as of December 29,2015, as amended to date (the “Merger Agreement”) by and among the Company, Brushy and Lilis Merger Sub, Inc., a Delaware corporation, a wholly-ownedsubsidiary of the Company (“Merger Sub”). Pursuant to the terms of the Merger Agreement, at the effective time (the “Effective Time”), Merger Sub mergedwith and into Brushy (the “Merger”), with Brushy continuing as the surviving corporation and becoming a wholly-owned subsidiary of Brushy. The Mergerresulted in the acquisition of Brushy’s properties in the Delaware Basin as well as the majority of its current operating activity. The results of Brushy, sincethe closing date of the Merger are included in the Company’s consolidated statement of operations. The Merger was effected through the issuance ofapproximately 5.785 million shares of Common Stock in exchange for all outstanding shares of Brushy common stock using a ratio of 0.4550916 shares ofLilis Common Stock for each share of Brushy common stock and the assumption of Brushy's liabilities, including approximately $11.4 million ofoutstanding debt with Independent Bank, Brushy’s former senior lender, and approximately $6.2 million of accounts payable, accrued expenses and assetretirement obligations. In connection with the closing of the Merger, Lilis paid-down $6.0 million of the principal amount outstanding on Brushy’s term loanwith Independent Bank, made a cash payment of $500,000 to SOSV Investments, LLC (“SOS”), Brushy's former subordinated lender and issued a $1 millionpromissory note to SOS (the “SOS Note”), along with a warrant to purchase 200,000 shares of Common Stock (the “SOS Warrant”). In connection with the Merger, Lilis incurred costs of approximately $3.22 million to date, including (i) $3.05 million of consulting, investment,advisory, legal and other Merger-related fees, and (ii) $170,000 of value in conjunction with the warrants issued to SOS recorded additional Mergerconsideration. Allocation of Purchase Price - The Merger has been accounted for as a business combination, using the acquisition method. The following table representsthe allocation of the total purchase price of Brushy to the assets and liabilities assumed based on the fair value on the closing date of the Merger. The following table sets forth the Company’s purchase price allocation (in thousands, except shares data and stock price): Shares of Lilis Common Stock issued to Brushy shareholders 5,785,119 Lilis Common Stock closing price on June 23, 2016 $1.20 Fair value of Common Stock issued $6,942 Cash consideration paid to SOS 500 SOS Note 1,000 Fair value of SOS warrant 170 Warrant liability - repricing derivative 164 Advance to Brushy pre-merger 2,508 Total purchase price 11,284 Plus: liabilities assumed by Lilis Current Liabilities Account payable and accrued expenses $5,447 Term loan - Independent Bank 11,379 16,826 Long-Term Debt 19 Asset Retirement Obligation 777 Amount attributable to liabilities assumed 17,622 $28,906 Fair Value of Brushy Assets Current Assets: Cash $706 Other current assets 624 $1,330 Oil and Gas Properties: Evaluated properties 7,512 Unevaluated properties 19,662 27,174 Other assets Other Property Plant & Equipment 42 Other assets 360 402 Total Asset Value $28,906 F-14  Pro forma Financial Information - The following pro forma condensed combined financial information was derived from the historical financialstatements of Lilis and Brushy and gives effect to the Merger as if it had occurred on January 1, 2015 for the year ended December 31, 2015. Belowinformation reflects pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including (i)Lilis’s Common Stock issued to convert Brushy’s outstanding shares of common stock as of the closing date of the Merger, (ii) adjustments to conformBrushy’s historical policy of accounting for its oil and natural gas properties from the successful efforts method to the full cost method of accounting, (iii)depletion of Brushy's fair-valued proved oil and gas properties, and (iv) the estimated tax impacts of the pro forma adjustments. The pro forma results ofoperations do not include any cost savings or other synergies that may result from the Merger or any estimated costs that have been or will be incurred byLilis to integrate the Brushy assets. The pro forma combined financial information has been included for comparative purposes and is not necessarilyindicative of the results that might have actually occurred had the Merger taken place on January 1, 2015; furthermore, the financial information is notintended to be a projection of future results. December 31, 2016 2015 (In thousands, except share data) Revenue $4,989 $3,173 Net loss $(35,835) $(75,808)Net loss attributable to common stockholders $(45,288) $(76,528)Net loss per common share basic and diluted $(4.00) $(13.32)Weighted average shares outstanding: Basic and diluted 11,328,252 5,745,785 NOTE 6 – 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. F-15  Asset Retirement Obligation The fair value of the Company’s asset retirement obligation liability is calculated at the point of inception by taking into account, the cost ofabandoning oil and gas wells, which is based on the Company’s and/or Industry’s historical experience for similar work, or estimates from independent third-parties; the economic lives of its properties, which are based on estimates from reserve engineers; the inflation rate; and the credit adjusted risk-free rate,which takes into account the Company’s credit risk and the time value of money. Given the unobservable nature of the inputs, the initial measurement of theasset retirement obligation liability is deemed to use Level 3 inputs. Executive Compensation In September 2013, the Company announced the appointment of Abraham Mirman as its new president. In connection with Mr. Mirman’sappointment, the Company entered into an employment agreement with Mr. Mirman (the “Mirman Agreement”). The Mirman Agreement provides for anincentive bonus package that, depending upon the relative performance of the Company’s Common Stock compared to the performance of stocks of certainpeer group companies as measured from Mr. Mirman’s initial date of employment through December 31, 2014, may result in a cash bonus payment to Mr.Mirman of up to 3.0 times his base salary. The incentive bonus is recorded as a liability and valued at each reporting period. The Company engaged avaluation firm (“VFIRM”) to complete a valuation of this incentive bonus. As previously announced, on March 30, 2015, the Company entered into anamended and restated employment agreement, which the Company refers to as the Mirman CEO Agreement with Mr. Mirman. The Mirman CEO Agreementalso provides for Mr. Mirman to receive a cash incentive bonus if certain production thresholds are achieved by the Company. Mr. Mirman’s new incentivebonus liability was valued by VFIRM at $104,000 at December 31, 2015. As of December 31, 2016, there was no bonus liability due to Mr. Mirman since theproduction thresholds were not met by the Company. As of December 31, 2015, the Company provided for $87,000 of the bonus liability which representsthe amount earned as of December31, 2015. On March 6, 2015, the Company announced the appointment of Kevin Nanke as its new Executive Vice President and Chief Financial Officer. Mr.Nanke would also receive a cash incentive bonus if certain production thresholds were achieved by the Company and a performance bonus of $100,000 if theCompany achieved certain goals set forth in Mr. Nanke’s employment agreement. Mr. Nanke’s new incentive bonus liability was valued by VFIRM at$83,000 at December 31, 2015. As of December 31, 2016, there was no bonus liability due to Mr. Nanke since the production thresholds were not met by theCompany. As of December 31, 2015, the Company provided for $69,000 of the liability which represents the amount earned as of that date. On March 16, 2015, the Company entered into an employment agreement with Ariella Fuchs for services to be performed as General Counsel to theCompany. Ms. Fuchs will also receive a cash incentive bonus if certain production thresholds are achieved by the Company. Ms. Fuchs’ new incentive bonusliability was valued by VFIRM at $80,000 at December 31, 2015. As of December 31, 2016, there was no bonus liability due to Ms. Fuchs since theproduction thresholds were not met by the Company. As of December 31, 2015, the Company provided for $67,000 of the liability which represents theamount earned as of that date. Change in Warrant Liability On September 2, 2014, the Company entered into a Consulting Agreement with Bristol Capital, LLC, pursuant to which the Company issued toBristol a warrant to purchase up to 100,000 shares of Common Stock at an exercise price of $20.00 per share (or, in the alternative, 100,000 options, but in nocase both). The agreement has a price protection feature that will automatically reduce the exercise price if the Company enters into another consultingagreement pursuant to which warrants are issued with a lower exercise price, which triggered during fiscal year 2016. On December 31, 2016, the Companyrevalued the warrants/option using the revised terms as follows: (i) 641,026 total warrants/options issued; (ii) stock price of $3.10; (iii) exercise price of$3.12; (iv) expected life of 2.67 years; (v) volatility of 101%; (vi) risk free rate of 1.38% for a total value of $1.2 million, which adjusted the change in fairvalue valuation of the derivative by $1.0 million. On December 31, 2015, the Company revalued the warrants/options using the following variables: (i)100,000 total warrants/options issued (as stated above, the Company will only issue a total of 100,000 shares of Common Stock under the option or thewarrant, but no more than 100,000 shares of Common Stock in the aggregate); (ii) stock price of $2.00; (iii) exercise price of $2.00; (iv) expected life of 3.7years; (v) volatility of 100%; risk free rate of 1.5% for a total value of approximately $44,000, which adjusted the change in fair value valuation of thederivative by $350,000 for the year ended December 31, 2015. On January 8, 2015, the Company entered into the Credit Agreement. In connection with the Credit Agreement, the Company issued to Heartland awarrant to purchase up to 22,500 shares of Common Stock at an adjusted exercise price of $4.05 with the initial advance, which contains an anti-dilutionfeature that will automatically reduce the exercise price if the Company enters into another agreement pursuant to which warrants are issued with a lowerexercise price. On December 31, 2015, the Company revalued the warrants issued to the Heartland Bank using the following variables: (i) 22,500 warrants issued;(ii) stock price of $2.00; (iii) exercise price of $ 25.00; (iv) expected life of 4.0 years; (v) volatility of 100%; (vi) risk free rate of 1.5% for a total value of$12,000, which adjusted the change in fair value valuation of the derivative by $12,000 for the year ended December 31, 2015. On December 31, 2016, theCompany revalued the warrants using the following variables: (i) 22,500 warrants issued; (ii) stock price of $3.10; (iii) adjusted exercise price of $ 4.05; (iv)expected life of 3.02 years; (v) volatility of 101%; (vi) risk free rate of 1.5% for a total value of approximately $42,000, which adjusted the change in fairvalue valuation of the derivative by $18,675 for the year ended December 31, 2016. F-16  Pursuant to the Merger Agreement and as a condition to the Fourth Amendment (defined below), the Company was required to make a cash paymentof $500,000, issue the SOS Note and the SOS Warrant. The SOS Warrant contains a price protection feature that will automatically reduce the exercise price ifthe Company enters into another financing agreement pursuant to which warrants are issued with a lower exercise price after June 23, 2016. This initial valueof $164,000 was recorded as additional Merger consideration. On December 31, 2016, the Company evaluated the SOS Warrant using the followingvariables: (i) stock price of $3.10 (ii) exercise price of $25.00 (iii) contractual life of 1.48 years; (iv) volatility of 101%; (v) risk free rate of 1.02% for a totalvalue of approximately $144,000, which adjusted the fair value valuation of the derivative by approximately $284,000 for the year ended December 31,2016. Debentures Conversion Derivative Liability As of December 31, 2015, the Company had $6.85 million in remaining Debentures, which, subject to stockholder approval, were convertible at anytime at the holders’ option into shares of Common Stock at $20.00 per share, or 342,323 underlying conversion shares prior to the execution of the DebentureConversion Agreement. The Debentures have elements of a derivative due to the potential for certain adjustments, including both the conversion option andthe price protection embedded in the Debentures. The conversion option allows the Debenture holders to convert their Debentures to underlying CommonStock at a conversion price of $20.00 per share, subject to certain adjustments, including the requirement to reset the conversion for any subsequent offeringat a lower price per share amount. The Company values this conversion liability at each reporting period using a Monte Carlo pricing model. On June 23, 2016, pursuant to the terms of the Debenture Conversion Agreement, dated December 29, 2015, the Company's remaining outstanding8% Convertible Debentures (the “Debentures”) of approximately $6,846,000 converted automatically upon consummation of the Merger. The conversionprice was modified from $20.00 per share to $5.00 per share, resulting in the issuance of 1,369,293 shares of Common Stock. Upon the conversion of theDebentures, the associated conversion liability of approximately $43,000 was reclassified to additional paid-in capital. At December 31, 2016 and 2015, theCompany valued the conversion feature associated with the Debentures at $0 and $6,000, respectively. As of December 31, 2016, the remaining debentureswere fully converted into 1,369,293 shares of the Company’s common stock. The following table provides a summary of the recurring fair values of assets and liabilities measured at fair value (in thousands): December 31, 2016 Level 1 Level 2 Level 3 Total Recurring fair value measurements: Warrant liabilities - - (1,400) (1,400)Total recurring fair value measurements $- $- $(1,400) $(1,400) December 31, 2015 Level 1 Level 2 Level 3 Total Recurring fair value measurements: Executive employment agreement $- $- $(223) $(223)Warrant liabilities - - (56) (56)Convertible debenture conversion derivative liability - - (6) (6)Total recurring fair value measurements $- $- $(285) $(285) F-17  The following table provides a summary of changes in fair value of the Company’s Level 3 financial assets and liabilities as of December 31, 2016and 2015 (in thousands): Conversionderivative liability Bristol/ Heartland/SOSwarrant liability Incentive bonus Total 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 liability 60 (1,180) (102) (1,222)Balance at December 31, 2016 $- $(1,400) $- $(1,400) Conversion derivative liability Bristol/Heartlandwarrant liability Incentive bonus Total Balance at January 1, 2015 $(1,249) $(394) $(40) $(1,683)Additional liability - (56) (149) (205)Change in fair value of liability 1,243 394 (34) 1,603 Balance at December 31, 2015 $(6) $(56) $(223) $(285) Assets and liabilities measured at fair value on a nonrecurring basis. Certain assets and liabilities are measured at fair value on a nonrecurring basis.These assets and liabilities are not measured at fair value on an ongoing basis, but are subject to fair value adjustments in certain circumstances. These assetsand liabilities can include proved and unproved oil and gas properties and other long-lived assets that are written down to fair value when they are impairedor held for sale. Proved oil and gas properties. The Company estimates the expected undiscounted future cash flows of its oil and natural gas properties andcompares such amounts to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amountexceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and natural gas properties to fair value. Thefactors used to determine fair value are subject to management’s judgement and expertise and include, but are not limited to, recent sales prices ofcomparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates or proved reserves, futurecommodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current marketconditions associated with realizing the expected cash flows projected. These assumptions represent Level 3 inputs. Impairment of oil and gas assets for theyear ended December 31, 2016 and 2015 was $4.7 million and $24.5 million, respectively. The following table provides a summary of the non-recurring fair values of assets and liabilities measured at fair value (in thousands): December 31, 2016 Level 1 Level 2 Level 3 Total Non-recurring fair value measurements Impairment of proved oil and gas properties - - 4,700 4,700 Total non-recurring fair value measurements $- $- $4,700 $4,700 December 31, 2015 Non-recurring fair value measurements Impairment of proved oil and gas properties - - 24,500 24,500 Total non-recurring fair value measurements $- $- $24,500 $24,500 The Company did not have any transfers of assets or liabilities between Level 1, Level 2 or Level 3 of the fair value measurement hierarchy duringthe years ended December 31, 2016 and 2015. F-18  NOTE 7 – ASSET RETIREMENT OBLIGATIONS (ARO) The information below reconciles the value of the asset retirement obligation for the periods presented (in thousands): Year Ended December 31, 2016 2015 (In thousands) Balance, beginning of year $208 $200 Liabilities assumed from the Merger 777 - Liabilities incurred 311 - Accretion expense 132 10 Conveyance of liability with oil and gas properties conveyance (92) - Change in estimate (79) (1)Balance, end of year 1,257 209 Less: current portion of ARO at end of year (338) - Total Long-term ARO at end of year $919 $209 NOTE 8 – LONG-TERM DEBTS As of December 31, 2016 2015 (In thousands) Term Loan: 6% Senior Secured Term Loan, due 2019, net of deferred financing costs and debt discount $29,214 $- Senior Secured Term Loan, interest at prime rate, due 2018, net of deferred financing costs and debt discount - 2,492 6% note payable to SOS Investment, LLC, due 2019 1,000 - Convertible Notes: 12% convertible related party note, due 2016, net of deferred financing costs and debt discount - 1,055 12% convertible non-related party note, due 2016, net of deferred financing costs and debt discount - 674 Convertible Debentures: 8% convertible debentures, due 2018, net of deferred financing costs and debt discount 6,846 Other notes payable 29 - $30,243 $11,067 Less: current portion (17) (11,067) $30,226 $- Credit and Guarantee Agreement On September 29, 2016, the Company entered into a credit and guaranty agreement (the “Credit and Guarantee Agreement”) by and among theCompany and its wholly owned subsidiaries, Brushy, ImPetro Operating, LLC (“Operating”) and ImPetro Resources, LLC (“Resources”, and together withBrushy and Operating, the “Initial Guarantors”), and the lenders party thereto (each a “Lender” and together, the “Lenders”) and T.R. Winston & Company,LLC (“TRW”) acting as collateral agent. The Credit and Guarantee Agreement provides for a three-year senior secured term loan with initial commitments of $31 million, of which $25million was collected as of September 30, 2016, and the additional $6 million was collected at December 31, 2016. The initial aggregate principal amountmay be increased to a maximum principal amount of $50 million at the Company’s request and with the consent of the Lenders holding loans in excess of60% of the then outstanding loans pursuant to an accordion advance provision in the Credit and Guarantee Agreement (the “Term Loan”). In connection with the Company’s entry into the Credit and Guarantee Agreement, it incurred commitment fees to each of the Lenders equal to 2.0%of their respective initial loan advances and advisory fees totaled to approximately $1.2 million as of December 31, 2016. The Company accounted for the$1.2 million as deferred financing costs to be amortized over the term of the loan. As partial consideration given to the lenders, we also amended certainwarrants issued in the Series B preferred stock offering held by the lenders during the third and fourth quarters of the year ended December 31, 2016, topurchase up to an aggregate amount of approximately 2,850,000 and approximately 672,000, shares of common stock respectively, such that the exerciseprice per share was lowered from $2.50 to $0.01 on such warrants. The portion repriced in the fourth quarter was due to certain delayed funding that occurredafter the initial commitment. Additionally, each lender received a 2.0% commitment fee equal to their respective initial loan advance. All of the amendedwarrants are immediately exercisable from the original issuance date, for a period of two years, subject to certain conditions. The Company accounted for thereduction in the conversion price as a debt discount of $714,000 and will be accreted over the term of the loan. For the year ended December 31, 2016, theCompany amortized approximately $108,000 of deferred financing costs and accreted approximately $119,000 of debt discount relating to the loan. Theseamounts were recorded as a component of non-cash interest expense. As of December 31, 2016, the unamortized portion of the debt discount and deferredfinancing costs were $0.6 million and $1.2 million, respectively. F-19  The Term Loan bears interest at a rate of 6.0% per annum and matures on September 30, 2019. The Company has the right to prepay the Term Loan,in whole or in part, at any time at a prepayment premium equal to 6.0% of the amount repaid. Such prepayment premium must also be paid if the Term Loanis repaid prior to maturity as a result of a change in control. In certain situations, the Credit and Guarantee Agreement requires mandatory prepayments of theTerm Loans at the request of the Lenders, including in the event of certain non-ordinary course asset sales, the incurrence of certain debt, and receipt ofproceeds in connection with insurance claims. The Credit and Guarantee Agreement also provides for events of default, including failure to pay any principal or interest when due, failure toperform or observe covenants, cross-default on certain outstanding debt obligations, the failure of a Guarantor to comply with the provisions of its Guaranty,and bankruptcy or insolvency events. The amounts under the Credit Agreement could be accelerated and be due and payable upon an event of default. SOS Investment LLC Note On June 30, 2016, pursuant to the Merger Agreement and as a condition of the Fourth Amendment, the Company was required to make a cashpayment of $500,000 to SOSV LLC, and also executed a subordinated promissory note with SOSV LLC, for $1 million, at an interest rate of 6% per annumwhich matures on June 30, 2019. In conjunction with cash payment and the note, the Company also issued 200,000 warrants at an exercise price of $25.00.The Company accounted for the cost of warrants of $0.2 million as part of the Merger transaction costs for the year ended December 31, 2016. Independent Bank and Promissory Note On June 22, 2016, in connection with the completion of the Merger, the Company, Brushy and Independent Bank (the “Lender”), Brushy’s seniorsecured lender, entered into an amendment to Brushy’s forbearance agreement with the Lender (the “Fourth Amendment”), which, among other things,provided for a pay-down of approximately $6.0 million of the principal amount outstanding on the loan (the “Loan”), plus fees and other expenses incurredin connection with the Loan, in exchange for an extension of the maturity date through December 15, 2016, at an interest rate of 6.5%, payable monthly.Additionally, the Company agreed to (i) guaranty the approximately $5.4 million aggregate principal amount of the Loan, (ii) grant a lien in favor of theLender on all of the Company’s real and personal property, (iii) restrict the incurrence of additional debt and (iv) maintain certain deposit accounts withvarious restrictions with the Lender. On September 29, 2016, in connection with the Company’s entry into the Credit and Guarantee Agreement, theCompany used part of the proceeds of the Term Loan to repay the balance of Brushy’s outstanding indebtedness with Independent Bank in full. Heartland Bank On January 8, 2015, the Company entered into the Credit Agreement with Heartland Bank (the “Credit Agreement”), as administrative agent and theLenders party thereto. The Credit Agreement provided for a three-year senior secured term loan in an initial aggregate principal amount of $3 million, or theTerm Loan. On December 29, 2015, after a default on an interest payment and in connection with the Merger, the Company entered into the ForbearanceAgreement with Heartland (the “Heartland Forbearance Agreement”). The Heartland Forbearance Agreement, restricted Heartland from exercising any of itsremedies until April 30, 2016, which was subject to certain conditions, including a requirement for the Company to make a monthly interest payment toHeartland. Following the First Amendment to the Credit Agreement entered into on March 1, 2016, on May 4, 2016, as a result of a default on the requiredMarch 1, April 1 and May 1 interest payments pursuant to the Forbearance Agreement, the Company entered into a second amendment to the ForbearanceAgreement (the “Second Amendment”). Pursuant to the Second Amendment, the limit on the amount of New Subordinated Debt the Company had beenpermitted to raise was eliminated and the Forbearance Expiration Date was extended to May 31, 2016. As consideration for the forgoing, the Company paidHeartland the overdue interest owed pursuant to the Term Loan and interest due through June 23, 2016 in the approximate amount of $160,000 andreimbursement of a portion of Heartland’s fees and expenses in an approximate amount of $53,000. During the year ended December 31, 2016, the Companyamortized approximately $38,000 of debt discount. This amount is recorded as a component of non-cash interest expense. As of December 31, 2016 and2015, the unamortized deferred financing costs were $0 and $38,000, respectively. In connection with the consummation of the Merger, on June 23, 2016, the Company repaid the entire balance of its outstanding indebtedness withHeartland at a discount of $250,000 (recognized as a gain in other income (expense), resulting in the elimination of $2.75 million in senior secured debt andthe extinguishment of Heartland’s security interest in the assets of the Company. F-20  Convertible Notes From December 29, 2015 to January 5, 2016, the Company entered into 12% Convertible Subordinated Note Purchase Agreements with variouslending parties, which the Company refers to as the Purchasers, for the issuance of an aggregate principal amount of $3.75 million unsecured subordinatedconvertible notes, or the Convertible Notes, which includes the $750,000 of short-term notes exchanged for Convertible Notes by the Company and warrantsto purchase up to an aggregate of approximately 1,500,000 shares of Common Stock at an exercise price of $2.50 per share. The proceeds from this financingwere used to pay a $2 million refundable deposit in connection with the Merger, to fund approximately $1.3 million of interest payments to the Company’slenders and for its working capital and accounts payable. The Convertible Notes bear interest at a rate of 12% per annum, payable at maturity on June 30, 2016. The Convertible Notes and the accrued butunpaid interest thereon are convertible in whole or in part from time to time at the option of the holders thereof into shares of the Company’s Common Stockat a conversion price of $5.00. The Convertible Notes may be prepaid in whole or in part (but with payment of accrued interest to the date of prepayment) atany time at a premium of 103% for the first 120 days and a premium of 105% thereafter, so long as no Senior Debt is outstanding. The Convertible Notescontain customary events of default, which, if uncured, entitle each noteholder to accelerate the due date of the unpaid principal amount of, and all accruedand unpaid interest, subject to certain subordination provisions. Additionally, on March 18, 2016, the Company issued an additional aggregate principal amount of $500,000 of Convertible Notes, which have thesame terms and conditions as the Convertible Notes with the exception of the maturity date, which is April 1, 2017. The proceeds from these ConvertibleNotes were used to make advances to Brushy for payment of operating expenses pending completion of the Merger. These notes were fully convertedfollowing the consummation of the Merger. In connection with the closing of the Merger, on June 23, 2016, certain holders of Convertible Notes in an aggregate principal amount ofapproximately $4.0 million entered into a Conversion Agreement with the Company (the "Note Conversion Agreement"). The terms of the Note ConversionAgreement provided that the Convertible Notes were automatically converted into Common Stock upon the closing of the Merger. Pursuant to the terms ofthe Note Conversion Agreement, in exchange for immediate conversion upon closing, the conversion price of the Convertible Notes was reduced to $1.10,which resulted in the issuance of 3,636,366 shares of Common Stock. The modification of such conversion rate resulted in a $3.4 million inducement chargerecorded in other expense. Holders of these Convertible Notes waived and forfeited approximately $198,000 rights to receive accrued but unpaid interest. On August 3, 2016, the Company entered into the first amendment to the Convertible Notes with the remaining holders of approximately $1.8million of Convertible Notes. Pursuant to the first amendment: (i) the maturity date was changed to January 2, 2017, (ii) the conversion price was adjusted to$1.10 and (iii) the coupon rate was increased to 15% per annum. All accrued and unpaid interest on the Convertible Notes would also be convertible incertain circumstances at the conversion price. Additionally, if the aggregate principal amount outstanding on the Convertible Notes was not either convertedby the holder or repaid in full on or before the maturity date, the Company agreed to pay a 25% premium on the maturity date. The Company accounted forthe reduction in the conversion price of remaining outstanding convertible notes as an inducement expense and recognized approximately $1.6 million inother income (expense). In exchange for the holders’ willingness to enter into the first amendment, the Company issued to the holders additional warrants topurchase up to approximately 1.65 million shares of Common Stock. The warrants issued were valued using the following variables: (i) stock price of $1.12;(ii) exercise price of $2.50; (iii) contractual life of 3 years; (iv) volatility of 203%; (v) risk free rate of 0.76% for a total value of approximately $1.63 million.This amount was recorded as an inducement expense and an increase to additional paid-in capital. On September 29, 2016, in connection with the Company’s entry into the Credit and Guarantee Agreement the remaining holders of the ConvertibleNotes converted the outstanding principal amount of approximately $1.8 million and accrued and unpaid interest in an amount of approximately $138,000into 1,772,456 shares of Common Stock. Convertible Debentures In numerous separate private placement transactions between February 2011 and October 2013, the Company issued an aggregate of approximately$15.6 million of Debentures, secured by mortgages on several of its properties. On January 31, 2014, the Company entered into a debenture conversionagreement (the “First Conversion Agreement”) with all of the holders of the Debentures. F-21  Pursuant to the terms of the First Conversion Agreement, $9.0 million in Debentures (approximately $8.73 million of principal and $270,000 ininterest) was converted by the holders to shares of Common Stock at a conversion price of $20.00 per share. In addition, the Company issued warrants to theDebenture holders to purchase one share of Common Stock for each share issued in connection with the conversion of the Debentures, at an exercise priceequal to $25.00 per share. Under the terms of the First Conversion Agreement, the balance of the Debentures may be converted to Common Stock on the terms provided therein(including the terms related to the warrants) at the election of the holder, subject to receipt of stockholder approval as required by Nasdaq continued listingrequirements. On December 29, 2015, the Company entered into a second agreement with the holders of its Debentures, which provides for the full automaticconversion of Debentures into shares of the Company’s Common Stock at a price of $5.00 per share, upon the receipt of requisite stockholder approval andthe consummation of the Merger. If the Debentures are converted on these terms, it would result in the issuance of 1,369,293 shares of Common Stock and theelimination of $8.08 million in short-term debt obligations including accrued but unpaid interest which would be forfeited and cancelled upon conversionpursuant to the terms of the agreement. On June 23, 2016, pursuant to the terms of the Debenture Conversion Agreement, dated December 29, 2015, the Company's remaining outstanding8% Convertible Debentures (the “Debentures”) of approximately $6,846,000 converted automatically upon consummation of the Merger. The conversionprice was modified from $20.00 per share to $5.00 per share, resulting in the issuance of 1,369,293 shares of Common Stock. In exchange for the reduction inconversion price, all accrued but unpaid interest of approximately $1,835,000 was forgiven by the Debenture holders, resulting in a net gain on themodification and conversion of the Debentures of approximately $602,000 and recorded as other income and expenses in the accompanying consolidatedstatements of operations. Upon the conversion of the Debentures, the associated conversion liability of approximately $43,000 was reclassified to additionalpaid-in capital. There were no unamortized deferred financing costs and debt discount at December 31, 2016 and 2015, respectively. Interest Expense Interest expense for the years ended December 31, 2016 and 2015 was approximately $4.9 million and $1.7 million, respectively. The non-cashinterest expense during the years ended December 31, 2016 and 2015 was approximately $4.2 million and $1.3 million, respectively. The non-cash interestexpenses consisted of non-cash interest expense and amortization of the deferred financing costs, accretion of the Debentures payable discount, andDebentures interest paid in Common Stock. NOTE 9 – COMMITMENTS AND CONTINGENCIES Environmental and Governmental Regulation At December 31, 2016, there were no known environmental or regulatory matters which are reasonably expected to result in a material liability tothe Company. Many aspects of the oil and gas industry are extensively regulated by federal, state, and local governments in all areas in which the Companyhas operations. Regulations govern such things as drilling permits, environmental protection and air emissions/pollution control, spacing of wells, theunitization and pooling of properties, reports concerning operations, land use, and various other matters including taxation. Oil and gas industry legislationand administrative regulations are periodically changed for a variety of political, economic, and other reasons. As of December 31, 2016 the Company hadnot been fined or cited for any violations of governmental regulations that would have a material adverse effect upon the financial condition of theCompany. Legal Proceedings The Company may from time to time be involved in various legal actions arising in the normal course of business. In the opinion of management,the Company’s liability, if any, in these pending actions would not have a material adverse effect on the financial position of the Company. The Company’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 Denver, Colorado and New York City, New York and corporate apartment leases in San Antonio, Texas. Rent expense for theyears ended December 31, 2016 and 2015, was approximately $201,000 and $73,000, respectively. As of December 31, 2016, the Company hasapproximately $0.4 million of minimum lease payments on its operating lease which consists of annual minimum lease payments of approximately $0.2million in 2017 and $0.2 million in 2018. F-22  NOTE 10 – RELATED PARTY TRANSACTIONS During the years ended December 31, 2016 and 2015, the Company has engaged in the following transactions with related party: December 31, Related Party Transactions 2016 2015 More than 5% Shareholder: (In thousands) T.R. Winston & Company LLC ("TRW") Cash paid for Series B Preferred Stock offering fees $500 $- Reinvest fee for 150 shares of Series B Preferred Stock and68,182 warrants at exercise price of $2.50 150 - Cash paid for advisory fee on Convertible Notes 350 - Sublet office space in New York to Lilis Energy, Inc for rent of$10,000 per month 15 - Participated in Convertible Notes maturing on June 30, 2016and April 1, 2017 400 - Cashless net exercised warrants to purchase 80,000 shares ofCommon Stock at a reset exercise price of $0.10, resulting inthe issuance of 75,820 shares. - - Total: $1,415 $- Steven B. Dunn and Laura Dunn Revocable Trustdated 10/28/10 Conversion of convertible debentures into common stock $1,020 $1,017 Bryan Ezralow (EZ Colony Partners, LLC) Conversion of convertible debentures into common stock $1,540 $- Participated in the Series B Preferred offering 1,300 - Total: $2,840 $- Pierre Caland (Wallington Investment Holdings,Ltd.) Conversion of convertible debentures into common stock $2,090 $2,090 Participated in the Series B Preferred offering 250 - Conversion of Series A Preferred stock into common stock 125 - Participated in Convertible Notes maturing on June 30, 2016and April 1, 2017 300 - Total: $2,765 $2,090 Directors and Officers: Nuno Brandolini (Director) Conversion of Series A Preferred stock into common stock $100 $- Participated in Convertible Notes maturing on June 30, 2016and April 1, 2017 250 150 Total: $350 $150 F-23  General Merrill McPeak (Director) Conversion of Series A Preferred stock into common stock $250 $- Participated in Convertible Notes maturing on June 30, 2016and April 1, 2017 250 250 Total: $500 $250 R. Glenn Dawson (Director) Participated in the Series B Preferred offering $125 $- Participated in Convertible Notes maturing on June 30, 2016and April 1, 2017 50 50 Total: $175 $50 Ronald D Ormand (Executive Chairman) Participated in the Series B Preferred offering through PerugiaInvestments LP (1) $1,000 $- Conversion of convertible debentures into common stockthrough Perugia Investments LP 500 - Participated in Convertible Notes maturing on June 30, 2016and April 1, 2017 through Brian Trust(2) 1,150 1,150 Consulting fee paid to MLV & Co. LLC (“MLC”) which Mr.Ormand previously was the Managing Director and Head of theEnergy Investment Banking Group at MLV 100 150 Total: $2,750 $1,300 Abraham Mirman (Chief Executive Officer andDirector) Participated in the Series B Preferred offering through BralinaGroup, LLC(3) $1,650 $- Conversion of Series A Preferred stock into common stock 250 - Participated in Convertible Notes maturing on June 30, 2016and April 1, 2017 through Bralina Group, LLC 750 1,000 Total: $2,650 $1,000 Kevin Nanken (former Executive Vice Presidentand Chief Financial Officer) Participated in the Series B Preferred offering through KKNHoldings LLC(4) $200 $- Participated in Convertible Notes maturing on June 30, 2016and April 1, 2017 through KKN Holdings LLC 100 - Total: $300 $- (1)Mr. Ormand is the manager of Perugia Investments L.P. ("Perugia") and has sole voting and dispositive power over the securities held by Perugia(2)An irrevocable trust managed by Jerry Ormand, Mr. Ormand's brother, as trustee and whose beneficiaries are adult children of Mr. Ormand(3)Mr. Mirman has shared voting and dispositive power over the securities held by The Bralina Group, LLC with Susan Mirman.(4)Mr, Nanke is the natural person with sole voting and dispositive power over the securities held by KKN Holdings LLC. F-24  NOTE 11 – INCOME TAXES The income tax provision (benefit) for the years ended December 31, 2016 and 2015 consisted of the following: December 31, 2016 2015 (In thousands) U.S. Federal: Current $- $- Deferred (2,971) (10,560) State and local: Current - - Deferred (124) (914) (3,095) (11,474)Change in valuation allowance 3,095 11,474 Income tax provision $- $- The tax effects of temporary differences that give rise to the Company’s deferred tax asset as of December 31, 2016 and 2015 consisted of thefollowing: December 31, 2016 2015 (In thousands) Deferred tax assets: Oil and gas properties and equipment $5,156 $3,848 Net operating loss carry-forward 42,017 41,389 Share based compensation 2,135 1,279 Abandonment obligation 445 77 Derivative instruments - 21 Accrued liabilities - 37 Debt conversion costs 482 488 Other 28 29 Total deferred tax asset 50,263 47,168 Valuation allowance (50,263) (47,168)Deferred tax asset , net of valuation allowance $- $- Deferred tax liabilities: Oil and gas properties and equipment $- $- Total deferred tax liability - - Net deferred tax asset (liability) $- $- Reconciliation of the Company’s effective tax rate to the expected U.S. federal tax rate is: For the Year Ended December 31, 2016 2015 Effective federal tax rate 34.00% 34.00%State tax rate, net of federal benefit 1.42% 2.94%Change in fair value derivative liability -1.32% 1.42%Debt discount amortization -4.11% -0.01%Share based compensation differences and forfeitures -2.28% -4.18%Change in rate -5.90% 2.34%Other permanent differences -12.29% -1.07%Other -0.10% 0.01%Valuation allowance -9.42% -35.45%Net -% -% F-25  The net operating losses for these years will not be available to reduce future taxable income until the returns are filed. Assuming these returns arefiled, as of December 31, 2016 and 2015, the Company had net operating loss carry-forwards for federal income tax purposes of approximately $118.6million and $112.0 million, respectively, available to offset future taxable income. To the extent not utilized, the net operating loss carry-forwards as ofDecember 31, 2016 will expire beginning in 2027 through 2036. The net operating loss carryovers may be subject to reduction or limitation by applicationof Internal Revenue Code Section 382 from the result of ownership changes. A full Section 382 analysis has not been prepared and the Company's netoperating losses could be subject to limitation under Section 382. 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. Management had no positive evidence to consider. Negative evidence considered by management includes cumulative book andtax losses in recent years, forecasted book and tax losses, no taxable income in available carryback years, and no tax planning strategies contemplated torealize the valued deferred tax assets. As of December 31, 2016 and 2015, management assessed the available positive and negative evidence to estimate if sufficient future taxableincome would be generated to use the Company’s deferred tax assets and determined that it is not more-likely-than-not that the deferred tax assets would berealized in the near future. Therefore, the Company recorded a full valuation allowance of approximately $50. million and $47.2 million on its deferred taxassets as of December 31, 2016 and 2015, respectively. NOTE 12 – STOCKHOLDERS’ EQUITY May 2014 Private Placement - Series A 8% Convertible Preferred Stock On May 30, 2014, the Company consummated a private placement of 7,500 shares of Series A Preferred Stock, along with detachable warrants topurchase up to 155,602 shares of Common Stock, at an exercise price of $28.90 per share, for aggregate gross proceeds of $7.50 million. The Series APreferred Stock has a par value of $0.0001 per share, a stated value of $1,000 per share, a conversion price of $24.10 per share, and a liquidation preference toany junior securities. Except as otherwise required by law, holders of Series A Preferred Stock shall not be entitled to voting rights, except with respect toproposals to alter or change adversely the powers, preferences or rights given to the Series A Preferred Stock, authorize or create any class of stock rankingsenior to the Series A Preferred Stock as to dividends, redemption or distribution of assets upon liquidation, amend its certificate of incorporation or othercharter documents in any manner that adversely affects any rights of the Preferred Stock holder, or increase the number of authorized Series A Preferred Stock.The holders of the Series A Preferred Stock are entitled to receive a dividend payable, at the election of the Company (subject to certain conditions as setforth in the Certificate of Designations), in cash or shares of Common Stock, at a rate of 8% per annum payable a day after the end of each quarter. The SeriesA Preferred Stock is convertible at any time at the option of the holders, or at the Company’s discretion when the Common Stock trades above $75.00 for tenconsecutive days with a daily dollar trading volume above $300,000. In addition, the Company has the right to redeem the shares of Series A Preferred Stock,along with any accrued and unpaid dividends, at any time, subject to certain conditions as set forth in the Certificate of Designations. In addition, holders ofthe Series A Preferred Stock can require the Company to redeem the Series A Preferred upon the occurrence of certain triggering events, including (i) failure totimely deliver shares of Common Stock after valid delivery of a notice of conversion by the holder; (ii) failure to have available a sufficient number ofauthorized and unreserved shares of Common Stock to issue upon conversion; (iii) the occurrence of certain change of control transactions; (iv) theoccurrence of certain events of insolvency; and (v) the ineligibility of the Company to electronically transfer its shares via the Depository Trust Company oranother established clearing corporation. In connection with issuance of the Series A Preferred Stock, the beneficial conversion feature (“BCF”) was valued at $2.21 million and the fair valueof the warrant was valued at $1.35 million. The aggregate value of the Series A Preferred Stock and warrant, valued at $3.56 million, was considered a deemeddividend and the full amount was expensed immediately. The Company determined the transaction created a beneficial conversion feature which iscalculated by taking the net proceeds of $6.79 million and valuing the warrants as of May 2014, utilizing a Black Scholes option pricing model. The inputsfor the pricing model are: $24.80 market price per share; exercise price of $28.90 per share; expected life of 3 years; volatility of 70%; and risk free rate of0.20%. The Company calculated the total consideration given to be $8.40 million comprised of $6.80 million for the Series A Preferred and $1.6 million forthe warrants. The Company deemed the value of the beneficial conversion feature to be $2.21 million and immediately accreted that amount as a deemeddividend. As of December 31, 2015, the Company has accrued a cumulative dividend for approximately $0.6 million. F-26  On June 23, 2016, in connection with the completion of the Merger, each outstanding share of the Company’s Series A Preferred Stock (the “Series APreferred Stock”) automatically converted into Common Stock at a conversion price of $5.00, resulting in the issuance of 1,500,000 shares of Common Stockwith a market value of $1.20 per share. As consideration for the automatic conversion, the Company reduced the conversion price on the Series A PreferredStock from $24.10 to $5.00. The modification of such conversion price and forgiveness of accrued but unpaid dividend of approximately $0.9 millionresulted in a net loss on the conversion of the Series A Preferred Stock of approximately $0.5 million. 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 theRedeemable Preferred. All 2,000 shares of Redeemable Preferred were issued in September 2014, pursuant to the Settlement Agreement with Hexagon. TheRedeemable Preferred has the same par value and stated value characteristics as the Series A Preferred Stock, yet the Conditionally Redeemable 6% PreferredStock is not convertible into Common Stock or any other securities of the Company. Except as otherwise required by law, holders of the RedeemablePreferred shall not be entitled to voting rights. The Redeemable Preferred Stock bears a 6% dividend per annum, payable quarterly, and is redeemable at face value (plus any accrued and unpaiddividends) at any time at the Company’s option, or at the Holders option upon the Company’s achievement of certain production and reserves thresholds.These thresholds include, the Company’s annualized gross production average for 90 consecutive days at 2,500 BOE per day or higher or the Company’s PV-10 value of its producing developed properties filed with the Securities and Exchange Commission exceeds $50 million. As of December 31, 2016 and 2015,the Company has accrued a cumulative dividend of $240,000 and $120,000, respectively. The total outstanding Redeemable Preferred was valued atapproximately $1.9 million and $1.2 million at December 31, 2016 and 2015, respectively. 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 is 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. Except as otherwise required by law, holders of the Series B Preferred Stock shall not beentitled to voting rights. The Series B Preferred Stock is convertible at any time, subject to certain conditions, at the option of the holders, or at theCompany’s discretion when the Company’s Common Stock trades above $10.00 (subject to any reverse or forward stock splits and the like) for tenconsecutive days. In addition, the Company has the right to redeem the shares of Series B Preferred Stock, along with any accrued and unpaid dividends, atany time, subject to certain conditions as set forth in the Certificate of Designation. The holders of the Series B Preferred Stock are entitled to receive adividend payable (subject to certain conditions as set forth in the Certificate of Designation), in cash or shares of Common Stock of the Company, at theelection of the Company, at a rate of 6% per annum. The Series B Preferred Stock is 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; vi) and 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 option pricing 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, 2016, approximately 3,000 shares of the Series B Preferred Stock plus approximately $0.6 million of cumulative dividendpayable were converted into approximately 2.7 million shares of the Company’s Common Stock at conversion price of $1.10 per share. As of December 31,2016, the Company accrued approximately $0.6 million of cumulative dividend for Series B Preferred Stock. F-27  Warrants A summary of warrant activity for the twelve months ended December 31, 2016 and 2015 (adjusted to reflect 1-for10 reverse stock split on June 23,2016): Warrants Weighted- Average Exercise Price Outstanding at January 1, 2015 1,700,707 $1.76 Warrants issued to consultants 60,000 16.30 Warrants issued to Heartland 22,500 8.70 Warrants issued with Convertible Notes 1,180,000 2.50 Exercised, forfeited, or expired (484,891) (61.30)Outstanding at December 31, 2015 2,478,316 $14.80 Warrants issued to Series B Preferred Stock 9,090,926 1.54 Warrants issued for fees 1,272,727 1.30 Warrants issued with Convertible Notes 1,145,238 2.47 Warrants issued to amend Convertible Notes 1,648,267 2.50 Additional warrants issued to Bristol 541,026 3.12 Warrants issued to SOS in connection with the Merger 200,000 2.50 Exercised, forfeited, or expired (460,989) (34.74)Outstanding at December 31, 2016 15,915,511 $3.34 The aggregate intrinsic value associated with outstanding warrants was approximately $18.3 million and zero at December 31, 2016 and 2015,respectively, as the strike price of all warrants exceeded the market price for Common Stock, based on the Company’s closing Common Stock price of $3.10and $2.10, respectively. The weighted average remaining contract life was 1.64 years and 2.13 years as of December 31, 2016 and 2015. During the year ended December 31, 2016, the Company issued approximately 13.16 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. The fair value of each stock warrant issued is determined using the Black-Scholes-Merton pricing model based on the following variables assummarized in the table below (fair value in thousands): Fair Valueof Warrants Number of Warrants Stock Price Exercise Price Expected Volatility Risk Free Rate Contractual LifeAs of December 31, 2016: Warrants issued for SeriesB Preferred Stock $9,486 9,090,926 $1.30 $2.50 238% 0.78% 2 yearsWarrants issued for SeriesB Preferred Stockoffering fees $1,590 1,272,724 $1.30 $1.30 238% 0.92% 3 yearsWarrants issued withConvertible Notes $1,446 975,051 $1.70 $1.00 245% 0.75% 2 yearsWarrants issued withConvertible Notes $277 170,187 $1.70 $1.10 245% 0.75% 3 yearsWarrants issued to amendconvertible debts $1,625 1,648,270 $1.12 $2.50 203% 0.76% 3 yearsWarrants issued to SOS $170 200,000 $1.20 $25.00 199% 0.76% 3 yearsAdditional warrantsissued to Bristol $1,214 541,026 $3.10 $3.12 101% 1.38% 3 years As of December 31, 2015: Warrants issued for bridgeterm loan $1,222 1,180,000 $2.48 $2.89 170% 0.20% 3 yearsWarrants issued forconsultants $425 60,000 $23.30 $42.50 99% 1.29% 5 yearsWarrants issued forHeartland Bank $56 22,500 $25.00 $25.00 99% 1.29% 5 years F-28  In connection with the May Financing, in exchange for additional consideration in the form of participation in the May Convertible Notes offering,certain Purchasers received amended and restated warrants to purchase approximately 620,000 shares of Common Stock, which reduced the exercise price ofthe warrants issued to these Purchasers in each of the prior two Convertible Notes issuances from $2.50 to $0.10, 80,000 of which were subsequentlyexercised. Additionally, during the three months ended June 30, 2016, in exchange for several offers to immediately exercise a portion of each investor’soutstanding warrants issued between 2013 and 2014, the Company reduced the exercise price on warrants to purchase a total of 416,454 shares of CommonStock 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 issuance of anaggregate amount of 300,706 shares of Common Stock due to certain cashless exercises. The Company accounted for the reduction in the exercise price as aninducement expense and recognized $1.72 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 to date, 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 wasbased on the amount of each Lender’s respective participation in the initial Term Loan relative to the amount invested in the Series B private placement. Allof the amended warrants are immediately exercisable from the original issuance date, for a period of two years, subject to certain conditions. For a moredetailed description of the terms of the Credit and Guarantee Agreement and the warrant reprice see “Note 8—Loan Agreements—Credit and GuaranteeAgreement.” NOTE 13 – SHARE BASED AND OTHER COMPENSATION Share-Based 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 underthe 2016 Plan to 10.0 million. During the year ended December 31, 2016, the Company granted 120,000 shares of restricted Common Stock to certain nonemployee directors inconnection with each of their appointment anniversaries pursuant to each director's nonemployee director award agreement and 85,000 shares of restrictedCommon Stock as Board fees for the quarter ended December 31, 2015, paid in stock in lieu of cash. During the year ended December 31, 2016, the Companyalso issued (i) 10,000 restricted stock units and options to purchase 45,000 shares of Common Stock under the 2016 Plan to a newly appointed directorpursuant to his nonemployee director award and 32,052 shares of restricted common stock as compensation for consulting services. Additionally, during theyear ended December 31, 2016, the Company granted options to purchase a total of 5,683,500 shares of Common Stock to management and employees underthe 2016 Plan. During the year ended December 31, 2016, certain of the Company's employees, directors and consultants forfeited 26,483 restricted stock units and335,000 options to purchase Common Stock previously granted in connection with various terminations and forfeitures. As a result, as of December 31, 2016, the Company had 149,584 restricted stock units, 1,068,305 restricted shares, and 5,956,833 options topurchase shares of Common Stock outstanding to employees and directors. Options issued to employees vest in equal installments over specified timeperiods during the service period or upon achievement of certain performance based operating thresholds. The Company requires that employees and directors pay the tax on equity grants in order to issue the shares and there is currently no cashlessexercise option. As of December 31, 2016, 149,584 restricted stock units and 1,780,052 restricted shares have been granted, but have not been issued. F-29  Compensation Costs (in thousands) As of December 31, 2016 As of December 31, 2015 StockOptions RestrictedStock Total StockOptions RestrictedStock Total Stock-based compensation expensed $4,475 $2,398 $6,873 $2,191 $469 $2,660 Unamortized stock-based compensation costs $5,200 $1,249 $6,449 $2,091 $266 $2,357 Weighted average amortization period remaining* 1.68 1.45 2.18 1.05 * Only includes directors and employees which the options vest over time instead of performance criteria which the performance criteria have not been met asof December 31, 2016 and 2015. Restricted Stock Summary of non-cash compensation in Statement of Changes in Stockholders’ Equity: As of December 31, 2016 2015 (In thousands) Statement of Stockholder’s Equity: Common stock issued for directors’ fees $85 $215 Common stock issued for officer and Board compensation 120 - Stock based compensation for vesting of restricted stock - 469 Stock based compensation for issuance of stock options 4,475 2,191 Stock based compensation for issuance of restricted stock 2,398 - Common stock issued for professional services - 150 Fair value of warrants issued for professional services - 425 Total non-cash compensation in Statement of Changes in Stockholders’ Equity $7,078 $3,450 A summary of restricted stock grant activity pursuant to the 2016 Plan for the year ended December 31, 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 There was no restricted stock grant activity for the year ended December 31, 2015. A summary of restricted stock unit grant activity pursuant to the 2012 Plan for the years ended December 31, 2016 and 2015 is presented below.Share activities for the year ended December 31, 2015 have been adjusted for 1-for-10 reverse stock split on June 23, 2016. F-30  Number of Shares Weighted Average Grant Date Price Outstanding at January 1, 2015 163,067 $24.40 Granted 114,501 9.00 Vested and issued (77,835) 6.60 Forfeited (12,833) 22.70 Outstanding at December 31, 2015 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 As of December 31, 2016, the total unrecognized compensation costs related to 1,217,889 unvested shares of restricted stock was approximately$1.2 million, which is expected to be recognized over a weighted-average remaining services period of 0.8 year. As of December 31, 2015, the Company had151,900 shares vested but unissued and total unrecognized compensation cost related to the 34,999 unvested shares of restricted stock was approximately$266,000, which is expected to be recognized over a weighted-average remaining service period of 1.05 years. Stock Options A summary of stock options activity for the years ended December 31, 2016 and 2015 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, 2015 358,333 $21.60 138,333 4.24 Granted 480,000 $12.60 Exercised - Forfeited or cancelled (230,000) $(24.60) Outstanding at December 31, 2015 608,333 $14.60 296,666 4.10 Granted 5,683,500 2.14 Exercised - Forfeited or cancelled (335,000) (5.34) Outstanding at December 31, 2016 5,956,833 $2.04 2,208,757 1.68 During 2016, option to purchase 5,683,500 shares of the Company’s common stock were granted under the 2016 Plan. The weighted average fairvalues of these options of $1.38. The fair values were determined using the Black-Scholes-Merton option valuation method assuming no dividends, a risk-free interest rate of 1.08%, a weighted average expected life of 4.12 years and weighted-average volatility of 152% As of December 31, 2016, total unrecognized compensation costs relating to the outstanding options was $5.2 million, which is expected to berecognized over the remaining vesting period of approximately 3.68 years. The outstanding options have an intrinsic value of approximately $12.3 million at December 31, 2016. During the year ended December 31, 2016 and 2015, the Company issued options to purchase shares of Common Stock to certain officers anddirectors. The options are valued using a Black Scholes model and amortized over the life of the option. During the years ended December 31, 2016 and2015, the Company amortized $4.5 million and $2.19 million, respectively relating to options outstanding. F-31  NOTE 14 – SUPPLEMENTAL NON-CASH TRANSACTIONS The following table presents information about supplemental cash flows for the years ended December 31, 2016 and 2015 (in thousands); 2016 2015 Non-cash investing and financing activities excluded from the statement of cash flows: 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 Brushy’s common stock 7,111 - Common stock issued for Series B Preferred Stock and accrued dividends 3,230 - Warrants issued for fees associated with Series B Preferred Stock issuance 1,590 - Warrants issued for Series B Preferred Stock issuance and recorded as a deemed dividend 7,879 - Fair value of warrants issued as debt discount and financing costs 2,192 1,222 Disposition of oil and gas assets for elimination of accrued expense for drilling - 5,198 NOTE 15 – SUBSEQUENT EVENTS Credit Agreement Drawdown On February 7, 2017, pursuant to the terms of the 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 total availability for borrowing remaining under the Credit Agreement is$11.9 million. We intend to use the proceeds to fund its drilling and development program, for working capital and for general corporate purposes. As partial consideration, we also amended certain warrants issued in the June 2016 private placement held by the Lenders to purchase up to anaggregate amount of approximately 738,638 shares of common stock such that the exercise price per share was lowered from $2.50 to $0.01 on such warrantsThe number of warrants amended for each Lender was based on the amount of each Lender’s respective participation in the initial Term Loan relative to theamount invested in the June 2016 private placement. All of the amended warrants are immediately exercisable from the original issuance date, for a period oftwo years, subject to certain conditions. March 2017 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 approximately an additional 2.6 million. Each unit consists of one share of common stock and a warrant topurchase 0.50 shares of common stock (each, a “Unit”), at a price per unit of $3.85. Each warrant has an exercise price of $4.50 and may be subject toredemption by the Company, upon prior written notice, if the price of the Company’s common stock closes at or above $6.30 for twenty trading days during aconsecutive thirty trading day period. The closing of the Offering is subject to the satisfaction of customary closing conditions. We expect to use the net proceeds from the Offering to support our planned 2017 capital budget, and for general corporate purposes includingworking capital. The securities to be sold in the private placement have not been registered under the Securities Act or any state securities laws and may not beoffered or sold in the United States absent registration or an applicable exemption from registration. However, in conjunction with the closing of the March2017 Private Placement, we have also entered into a registration rights agreement whereby we agreed to use our reasonable best efforts to register, on behalfof the investors, the shares of common stock underlying the Units and the shares of common stock underlying the warrants no later than April 1, 2017. Our 2017 capital budget may require additional financing above the level of cash generated by our operations and proceeds from recent financing activities. We can provide no assurance that additional financing would be available to us on acceptable terms, if NOTE 16 – SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) The following table sets forth information for the years ended December 31, 2016 and 2015 with respect to changes in the Company's proved (i.e. proveddeveloped and undeveloped) reserves: F-32  Crude Oil(Bbls) Natural Gas(Mcf) December 31, 2014 899,727 4,237,241 Purchase of reserves - - Revisions of previous estimates (859,230) (4,063,500)Extensions, discoveries - - Sale of reserves - - Production (7,067) (32,291)December 31, 2015 33,430 141,450 Purchase of reserves 93,972 292,018 Revisions of previous estimates 455,202 3,506,794 Extensions, discoveries Sale of reserves Production (31,899) (68,756)December 31, 2016 550,705 3,871,506 Proved Developed Reserves, included above: Balance, December 31, 2014 50,185 197,146 Balance, December 31, 2015 33,430 141,450 Balance, December 31, 2016 550,705 3,871,506 Proved Undeveloped Reserves, included above: Balance, December 31, 2014 849,542 4,040,095 Balance, December 31, 2015 - - Balance, December 31, 2016 - - As of December 31, 2016 and December 31, 2015, the Company had estimated proved reserves of 550,705 and 33,430 barrels of oil, respectivelyand 3,871,506 and 141,450 thousand cubic feet (“MCF”) of natural gas, respectively. The Company’s reserves are comprised of 46% and 59% crude oil and54% and 41% natural gas on an energy equivalent basis, as of December 31, 2016 and December 31, 2015, respectively. The following values for the December 31, 2016 and December 31, 2015 oil and gas reserves are based on the 12 month arithmetic average first ofmonth price January through December 31; resulting in a natural gas price of $2.05 and $2.79 per MMBtu (NYMEX price), respectively, and crude oil priceof $37.30 and $42.59 per barrel (West Texas Intermediate price), respectively. All prices are then further adjusted for transportation, quality and basisdifferentials. The following summary sets forth the Company's future net cash flows relating to proved oil and gas reserves (in thousands): For the Year Ended December 31, 2016 2015 Future oil and gas sales $28,514 $1,819 Future production costs (15,939) (983)Future development costs (3,388) - Future income tax expense (1) - - Future net cash flows 9,187 836 10% annual discount (2,531) (228)Standardized measure of discounted future net cash flows $6,656 $608 F-33  The principal sources of change in the standardized measure of discounted future net cash flows are (in thousands): 2016 2015 Balance at beginning of period $608 $23,254 Sales of oil and gas, net (1,989) (146)Net change in prices and production costs (309) (26,115)Net change in future development costs 4,617 20,626 Extensions and discoveries - - Acquisition of reserves 7,919 - Sale / conveyance of reserves - - Revisions of previous quantity estimates 1,087 (19,336)Previously estimated development costs incurred (8,942) - Net change in income taxes - - Change in timing and other 3,630 - Accretion of discount 35 2,325 Balance at end of period $6,656 $608 (1)Calculations of the standardized measure of discounted future net cash flows include the effect of estimated future income tax expenses for all yearsreported. The Company expects that all of its Net Operating Loss’ (“NOL”) will be realized within future carry forward periods. All of the Company'soperations, and resulting NOLs, are attributable to its oil and gas assets. A variety of methodologies are used to determine the Company’s proved reserve estimates. The principal methodologies employed are reservoirsimulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Somecombination of these methods is used to determine reserve estimates in substantially all of our fields. F-34  Exhibit 10.28 EXECUTIVE EMPLOYMENT AGREEMENT This Executive Employment Agreement (“Agreement”) is entered into as of December 1, 2016 (“Effective Date”) by and between Lilis Energy, Inc.(the “Company”) and Seth Blackwell (“Executive”). Executive and the Company are each referred to individually as a “Party” and collectively as the“Parties.” NOW, THEREFORE, in consideration of the mutual covenants, representations, warranties and agreements contained herein, and for other good andvaluable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties agree as follows: 1. Employment. Executive’s employment with the Company is subject to the terms set forth herein. 2. Term. Subject to the remaining terms of this Section 2, this Agreement shall be for an initial term that begins on the Effective Date andcontinues in effect through December 1, 2017 (the “Initial Term”) and, unless terminated sooner as herein provided, shall continue on a year-to-year basisafter the Initial Term (each year, a “Renewal Term,” and each Renewal Term together with the Initial Term, the “Term”). If either Party elects not to renew thisAgreement for a Renewal Term, such Party must give a written Notice of Termination to the other Party at least 90 days before the expiration of the then-current Initial Term or Renewal Term, as applicable. In the event that one Party provides the other with a Notice of Termination pursuant to this Section 2, nofurther automatic extensions shall occur and this Agreement shall terminate at the end of the then-existing Initial Term or Renewal Term, as applicable, andsuch Termination shall not result in any entitlement to severance compensation pursuant to Section 6.2. Executive’s principal place of employment shall beat the main business offices of Company in San Antonio, Texas. 3. Position. During the Term, the Company shall employ Executive, and Executive shall serve as Executive Vice President of Land & BusinessDevelopment of the Company, with such duties and responsibilities that are customary in that position for public companies. Executive’s principal place ofemployment shall be at the main business offices of Company. 4. Scope of Services. During the Term, Executive shall devote substantially all of Executive’s business time, energy and best efforts to carry outExecutive’s responsibilities with respect to the business and affairs of the Company and its affiliates. In addition, the Parties acknowledge that Executive may(i) engage in and manage Executive’s passive personal investments, (ii) engage in charitable, educational and/or civic activities and (iii) engage in such otheractivities that the Parties mutually agree to; provided, however, that such activities shall be permitted so long as such activities do not conflict with thebusiness and affairs of the Company or interfere with the performance of Executive’s duties hereunder. 5. Compensation and Benefits. In each case during the Term: 5.1 Base Salary. The Company shall pay, or cause to be paid, to Executive a base salary (the “Base Salary”) as established by or pursuantto authority granted by the Board. Executive’s initial Base Salary shall be $225,000 per year. The Base Salary shall be reviewed annually by or pursuant toauthority granted by the Board in connection with its annual review of executive compensation to determine if such Base Salary should be increased (but notdecreased) for the following year in recognition of services to the Company. The Base Salary shall be payable at such intervals in conformity with theCompany’s prevailing practice as such practice shall be established or modified from time to time. 5.2 Cash Incentive Bonus. Executive shall receive a lump-sum cash payment if and to the extent that during the period between theEffective Date and the one-year anniversary of the Effective Date (the “Measurement Period”), any of the following conditions set forth in Section 5.2.1 aresatisfied, provided that, in addition, at least one of the conditions set forth in Section 5.2.2 is also satisfied (the “Incentive Bonus”), in each case asdetermined by the Board in its sole discretion, to be paid within 30 days after achievement of such conditions: 1  5.2.1 (a) Executive shall be granted a bonus equal to 50% of Base Salary in the event that, during the Measurement Period, theCompany has determined that its annualized gross production average for a consecutive 90-day period is equal to or exceeds 1,500 barrels of oil equivalent(“BOE”) per day; (b) without duplication of the amount described in the preceding clause (a), Executive shall be granted a bonus equal to 100%of Base Salary in the event that, during the Measurement Period, the Company has determined that its annualized gross production average for a consecutive90-day period is equal to or exceeds 2,000 BOE per day; (c) without duplication of the amounts described in the preceding clauses (a) and (b), Executive shall be granted a bonus equalto 150% of Base Salary in the event that, during the Measurement Period, the Company has determined that its annualized gross production average for aconsecutive 90-day period is equal to or exceeds 3,000 BOE per day; (d) without duplication of the amounts described in the preceding clauses (a), (b) and (c), Executive shall be granted a bonusequal to 200% of Base Salary in the event that, during the Measurement Period, the Company has determined that its annualized gross production average fora consecutive 90-day period is equal to or exceeds 4,000 BOE per day; (e) without duplication of the amounts described in the preceding clauses (a), (b), (c) and (d), Executive shall be granted abonus equal to 300% of Base Salary in the event that, during the Measurement Period, the Company has determined that its annualized gross productionaverage for a consecutive 90-day period is equal to or exceeds 5,000 BOE per day; and (f) without duplication of the amounts described in the preceding clauses (a), (b), (c), (d) and (e), Executive shall be granted abonus equal to 400% of Base Salary in the event that, during the Measurement Period, the Company has determined that its annualized gross productionaverage for a consecutive 90-day period is equal to or exceeds 6,000 BOE per day. 5.2.2 (a) The Company’s common stock maintains a 10-consecutive-day volume weighted average price of: (1) $2.30 per Share upon 1,500 BOE per day; (2) $3.00 per Share upon 2,000 BOE per day; (3) $4.50 per Share upon 3,000 BOE per day; (4) $6.00 per Share upon 4,000 BOE per day; (5) $7.50 per Share upon 5,000 BOE per day; or (6) $9.00 per Share upon 6,000 BOE per day. (b) The Company maintains an aggregate debt to earnings before interest, taxes, depreciation, depletion, amortization andexploration expenses (“EBITDAX”) ratio of 4.5 to 1. EBITDAX shall be calculated by multiplying the Company’s 90-day EBITDAX during the applicableperiod set forth in Section 5.2.1 by 4. 2  (c) The Company maintains cash on hand (or equivalents) and/or availability of 10 times the Incentive Bonus. 5.3 Annual Bonuses; Additional Compensation. Without limitation of Section 5.2, Executive shall be eligible to receive bonuses andawards of equity and non-equity compensation and to participate in annual and long-term compensation plans of the Company in accordance with any planor decision that the Board, or any committee or other person authorized by the Board, may in its sole discretion determine from time to time. The targetannual bonus for Executive as of the Effective Date shall be determined by the Board in its sole discretion. 5.4 Compensation in Event of Injury or Sickness. In the event Executive becomes injured or suffers a medically determinable physicalor mental illness, as determined by a physician acceptable to both the Partnership and Executive, Executive shall be entitled to receive continued BaseSalary as set forth in Section 5.1 for a period of six (6) months following the occurrence of such injury or sickness; provided, however, such Base Salary shallbe reduced by any short-term and/or long-term disability benefits that are received by Executive under such programs sponsored by the Company duringsuch six (6) month period. 5.5 Signing Bonus. In addition to the Base Salary, Incentive Bonus and Annual Bonuses in Sections 5.1, 5.2 and 5.3 above, as a materialinducement for Executive to enter into this Agreement, the Company shall pay to Executive the amount of $100,000.00 in readily available funds on orbefore December 15, 2016. 5.6 Welfare and Benefit Plans. (i) Executive shall be entitled to participate in all savings and retirement plans, practices, policies andprograms of the Company and (ii) Executive and Executive’s family, as the case may be, shall be eligible to participate in, and shall receive all benefitsunder, all welfare benefit plans, practices, policies and programs provided by the Company (including, to the extent provided, medical, prescription, dental,vision, disability, life, accidental death and travel accident insurance plans and programs) (all such plans, practices, policies and programs, the “Plans”), ineach case pursuant to all terms and conditions of the Plans. Except as provided herein, the Company shall not be required to establish or continue the Plansor take any action to cause Executive to be eligible for any Plans on a basis more favorable than that applicable to its other executive-level employeesgenerally. 5.7 Reimbursement. The Company shall reimburse Executive (or, in the Company’s sole discretion, shall pay directly), uponpresentation of vouchers and other supporting documentation as the Company may reasonably require, for reasonable out-of-pocket expenses incurred byExecutive relating to the business or affairs of the Company or the performance of Executive’s duties hereunder, including reasonable expenses with respectto mileage, entertainment, travel and similar items, dues for membership in professional organizations, and similar professional development expenses,provided that the incurring of such expenses shall have been approved in accordance with the Company’s regular reimbursement procedures and practicesin effect from time to time. The Company shall also provide Executive with suitable office space, including staff support, paid parking and necessaryequipment. 5.8 Vacation. In addition to statutory holidays, Executive shall be entitled to no less than 20 days of paid vacation each calendar yearduring the Term. Vacation shall accrue pursuant to the Company’s vacation accrual policy applicable to all employees of the Company, provided that nomore than 20 vacation days may be carried over from one calendar year to a subsequent calendar year. 5.9 Reservation of Rights. The Company reserves the right to modify, suspend or discontinue any and all of its employee benefit plans,practices, policies and programs at any time in its sole discretion without recourse by Executive so long as such changes are similarly applicable to executiveemployees at a similar level. 3  6. Payments upon Termination. 6.1 Accrued but Unpaid Salary and Bonus. In the event of a Termination for any reason during the Term, the Company shall pay toExecutive (or, in the event of Executive’s death, to Executive’s estate or named beneficiary) within 30 days of Termination: (a) any Base Salary, vacation payand expense reimbursements that are accrued but unpaid as of the date of Termination; and (b) (except upon a Termination by the Company for Cause) anyearned but unpaid bonus for any prior or current year. 6.2 Severance. (a) Upon an Involuntary Termination during the Term and either prior to a Change in Control or more than one year following aChange in Control, contingent upon Executive’s execution, delivery and non-revocation of a release in form and substance satisfactory to the Company andconsistent with the Company’s standard release agreement, which contains a full release of all claims against the Company and certain other provisions,including a reaffirmation of the covenants in Section 12 and Section 13 (the “Release Agreement”), Executive shall be entitled to (1) a lump sum severancepayment in an amount equal to 12 months of Base Salary in effect immediately prior to the date of Termination; and (2) a lump sum payment equal to 12months of COBRA premiums based on the terms of Company’s group health plan and Executive’s coverage under such plan as of the date of Termination(regardless of any COBRA election actually made by Executive or the actual COBRA coverage period under the Company’s group health plan). (b) Upon an Involuntary Termination during the Term and within one year following a Change in Control, contingent uponExecutive’s execution, delivery and non-revocation of the Release Agreement, Executive shall be entitled to (1) a lump sum severance payment in an amountequal to 24 months of Base Salary in effect immediately prior to the date of Termination and (2) a lump sum payment equal to 24 months of COBRApremiums based on the terms of Company’s group health plan and Executive’s coverage under such plan as of the date of Termination (regardless of anyCOBRA election actually made by Executive or the actual COBRA coverage period under the Company’s group health plan). (c) Upon a Termination due to Disability during the Term, contingent upon Executive’s execution, delivery and non-revocation of the Release Agreement, Executive shall be entitled to a lump sum payment equal to six months of COBRA premiums based on the terms of theCompany’s group health plan and Executive’s coverage under such plan as of the date of Termination (regardless of any COBRA election actually made byExecutive or the actual COBRA coverage period under the Company’s group health plan). (d) The Company’s obligations under this Section 6.2 are subject to the requirements and time periods set forth in thisSection 6.2 and in the Release Agreement. Prior to receiving the payments described in this Section 6.2, Executive shall execute the Release Agreement on orbefore the date 21 days (or such longer period to the extent required by law) after the date of Termination. If Executive fails to timely execute and remit theRelease Agreement, Executive waives any right to the payments provided under this Section 6.2. Payments under this Section 6.2 shall be made withinfifteen 15 days of Executive’s execution and delivery of the Release Agreement, provided that Executive does not revoke the Release Agreement. (e) Executive’s rights following a Termination under the terms of any Plan, whether tax-qualified or not, which are notspecifically addressed in this Agreement, shall be subject to the terms of such Plan, and this Agreement shall have no effect upon such terms except asspecifically provided herein. (f) Except as specifically provided under Section 6.1 and Section 6.2, the Company shall have no further obligations toExecutive under this Agreement following a Termination. Without limitation of the foregoing, Executive shall not be entitled to any severance benefitsunder this Agreement in the event of a Termination other than an Involuntary Termination (except as provided in Section 6.1). The foregoing shall not limitany of Executive’s rights with regard to any rights to indemnification, advancement or payment of legal fees and costs, and coverage under directors andofficers liability insurance. 4  (g) Notwithstanding anything in this Agreement to the contrary, the Company shall have the right to terminate all paymentsand benefits owing to Executive pursuant to Section 6.2 upon the Company’s discovery of any material breach by Executive of Executive’s obligationsunder the Release Agreement or Section 12 or Section 13. 7. Definitions. Capitalized terms used in this Agreement but not otherwise defined herein shall have the meaning hereby assigned to them asfollows: 7.1 “Cause” means a determination by the Board that Executive has: (a) in the performance of Executive’s duties with respect to the Company or any of its affiliates, engaged in reckless or willfulmisconduct or has violated the law, provided that no act or failure to act shall be deemed “willful” unless done, or omitted to be done, by Executive not ingood faith and without reasonable belief that Executive’s action or omission was in the best interest of the Company; (b) refused without proper legal reason to perform Executive’s duties and responsibilities to the Company or any of itsaffiliates, which continues after notice from the Company to perform such duties and responsibilities (for the purposes of this clause, the phrase “proper legalreason” shall include Executive’s delivery of a Notice of Termination for Good Reason where the assertion by Executive of Termination for Good Reason isfor an event that constitutes Good Reason under the terms of this Agreement); (c) willfully and materially breached any material provision of this Agreement; (d) committed an act of fraud, embezzlement or breach of a fiduciary duty to the Company or an affiliate of the Company(including the unauthorized disclosure of material confidential or proprietary information of the Company or an affiliate of the Company); (e) been convicted of (or pleaded no contest to) a felony (other than a crime involving the operation of a motor vehicle notinvolving a serious injury or death to an individual); or (f) entered into a cease and desist order with the U.S. Securities and Exchange Commission alleging violation of U.S. or foreignsecurities laws. Executive shall have 30 days from the date on which Executive receives the Company’s Notice of Termination for Cause under clause (a), (b) or (c)above to remedy any such occurrence otherwise constituting Cause under such clause. In connection with a determination of Cause, a majority of the Board shall make such determination at a meeting of the Board called and held forsuch purpose (after reasonable notice to Executive and an opportunity for Executive, together with counsel, to be heard before the Board). A Termination for Cause shall be deemed to include a determination by the Board following a Termination that circumstances existing prior to theTermination would have entitled the Company to have terminated Executive’s service for Cause. All rights Executive has or may have under this Agreement shall be suspended automatically during the pendency of any investigation by theBoard, or during any negotiations between the Board and Executive, regarding any actual or alleged act or omission by Executive of the type described inthis definition of Cause. 5  7.2 “Change in Control” has the meaning given to such term in the Lilis Energy, Inc. 2016 Omnibus Incentive Plan. 7.3 “Disability” means, if, during the Term, Executive is unable to perform substantially and continuously the duties assigned to himdue to a disability (as such term is defined or used for purposes of the Company’s long-term disability plan then in effect, or, if no such plan is in effect, byvirtue of ill health or other disability for more than 180 consecutive or non-consecutive days out of any consecutive 12-month period). 7.4 “Good Reason” means the occurrence of any of the following events without Executive’s consent: (a) a material diminution in Executive’s Base Salary; or (b) a material diminution in Executive’s authority, duties or responsibilities as an officer, or the Board fails to re-nominateExecutive for election to the Board if Executive is a Board member as of the Effective Date or becomes a Board member thereafter; (c) the relocation of Executive’s principal place of employment by more than 25 miles from the location of Executive’sprincipal place of employment as of the Effective Date; or (d) a material breach by the Company of a material provision of this Agreement. Notwithstanding the foregoing provisions of this Section 7.4 or any other provision in this Agreement to the contrary, any assertion by Executive of aTermination for Good Reason shall not be effective unless all of the following conditions are satisfied: (1) Executive provides written notice to the Companyof such condition within 45 days of Executive gaining knowledge of the initial existence of the condition, (2) the condition specified in the notice remainsuncured for 30 days after receipt of the notice by the Company and (3) the date of Termination occurs within 30 days after the expiration of the cure periodset forth in (2) immediately above. 7.5 “Involuntary Termination” means a Termination by the Company without Cause or by Executive for Good Reason. 7.6 “Notice of Termination” means a written notice delivered by either Party to the other Party indicating the specific Terminationprovision in this Agreement relied upon for Termination and the date of Termination, and that sets forth in reasonable detail the facts and circumstancesclaimed to provide a basis for Termination under the provision so indicated. 7.7 “Termination” means termination of Executive’s employment with the Company and all affiliates. 8. Removal from any Boards and Positions. Unless otherwise agreed to in writing by the Parties at the time of Termination, upon a Termination,Executive shall be deemed to resign (i) if a member, from the Board and the board of directors of any affiliate and any other board to which Executive hasbeen appointed or nominated by or on behalf of the Company or an affiliate, (ii) from each position with the Company and any affiliate, including as anofficer of the Company or an affiliate and (iii) as a fiduciary of any employee benefit plan of the Company and any affiliate. 9. Adjustments to Payments. 9.1 Notwithstanding anything in this Agreement to the contrary, in the event that any payment or distribution by the Company toExecutive or for Executive's benefit (whether paid or payable or distributed or distributable pursuant to the terms of this Agreement or otherwise) (the“Payments”) would be subject to the excise tax imposed by Section 4999 of the Internal Revenue Code of 1986 (the “Code”), or any interest or penalty isincurred by Executive with respect to such excise tax (such excise tax, together with any such interest and penalties, the “Excise Tax”), then the Paymentsshall be reduced (but not below zero) if and to the extent that such reduction would result in Executive retaining a larger amount, on an after-tax basis (takinginto account federal, state and local income taxes and the imposition of the Excise Tax), than if Executive received all of the Payments. The Company shallreduce or eliminate the Payments, by first reducing or eliminating the portion of the Payments that are not payable in cash and then by reducing oreliminating cash payments, in each case in reverse order beginning with payments or benefits that are to be paid the farthest in time from the determination. 6  9.2 All determinations required to be made under this Section 9, including whether and when an adjustment to any Payments is requiredand, if applicable, which Payments are to be so adjusted, shall be made by an independent accounting firm selected by the Company from among the fourlargest accounting firms in the United States or any nationally recognized financial planning and benefits consulting company (the “Accounting Firm”),which shall provide detailed supporting calculations to both Parties within 15 business days of the receipt of notice from Executive that there has been aPayment, or such earlier time as is requested by the Company. In the event that the Accounting Firm is serving as accountant or auditor for the individual,entity or group effecting the relevant change in control, Executive shall appoint another nationally recognized accounting firm to make the determinationsrequired hereunder (which accounting firm shall then be referred to as the Accounting Firm hereunder). All fees and expenses of the Accounting Firm shall beborne solely by the Company. If the Accounting Firm determines that no Excise Tax is payable by Executive, it shall furnish Executive with a writtenopinion that failure to report the Excise Tax on Executive's applicable federal income tax return would not result in the imposition of a negligence or similarpenalty. Any determination by the Accounting Firm shall be binding upon the Parties. 10. Clawback. Notwithstanding anything in this Agreement to the contrary, if any provision of this Agreement or any applicable statute, law,regulation or regulatory interpretation or other guidance legally requires the Company or any affiliate to seek or demand repayment or return of anypayments made to Executive for any reason, Executive shall repay to the Company the aggregate amount of any such payments, with such repayment tooccur no later than 30 days following Executive’s receipt of a written notice from the Company indicating that payments received by Executive are subjectto repayment or return under this Section 10. 11. Withholding. The Company may withhold from Executive’s compensation, under this Agreement or otherwise, all applicable amountsrequired by law. 12. Non-Competition; Non-Solicitation; Anti-Raiding. 12.1 Executive hereby covenants that during the period of Executive’s employment by the Company, and for a period of six monthsfollowing a Termination, Executive shall not, without the prior written consent of the Board, accept a position to perform duties similar to those performed byExecutive while at the Company, directly or indirectly (whether as proprietor, stockholder, director, partner, employee, agent, independent contractor,consultant, trustee or in any other capacity), with respect to any property, drilling program, oil or gas leasehold, project or field, in which the Companyparticipates, or has any investment or other business interest in, within five miles of the boundary of any existing Company leasehold in the United States inwhich the Company has conducted business at any time within the one-year period immediately preceding Termination (a “Competing Enterprise”);provided, however, that Executive shall not be deemed to be participating or engaging in a Competing Enterprise solely by virtue of Executive’s ownershipof not more than 4.9% of any class of stock or other securities which are publicly traded on a national securities exchange or in a recognized over-the-countermarket. 12.2 Executive may not avoid the purpose and intent of Section 12.1 by engaging in conduct within the geographically limited areafrom a remote location through means such as telecommunications, written correspondence, computer-generated or assisted communications or other similarmethods. 7  13. Confidential Information. 13.1 For the purposes of this Agreement, “Confidential Information” means all proprietary information, data, knowledge and know-howrelating, directly or indirectly, to the Company and its business, including: (a) business plans and strategies, prospect information, financial information,investment plans, marketing plans and strategies and financial plans and strategies; (b) confidential personnel or human resources data; (c) technical andbusiness information, whether patentable or not, which is of a confidential, trade secret or proprietary character; (d) the identity of customers; (e) existing orprospective oil or gas properties, investors, participation agreements, working, royalty or other interests; (f) contract terms; (g) bidding information andstrategies; (h) pricing methods or information; (i) computer software; (j) computer software methods and documentation; (k) hardware; (l) methods ofoperation; (m) procedures, forms and techniques used in servicing accounts or properties; (n) seismic, geophysical, petrophysical or geological data; (o) welllogs and other well data; and (p) any other documents, information or data that the Company requires to be maintained in confidence for the Company’sbusiness success or that constitutes material non-public information. The list set forth above is not intended by the Company to be a comprehensive list ofConfidential Information. All Confidential Information shall be treated as Confidential Information regardless of whether it pertains to the Company or itscustomers and regardless of whether it is stamped as “confidential.” Notwithstanding the foregoing, Confidential Information shall not include: (i)information that is or becomes generally available to the public other than as a result of a disclosure by Executive; (ii) information that was known toExecutive prior to the Effective Date; or (iii) information that is or becomes available to Executive from a third party that is not known by Executive to bebound by an agreement of confidentiality. 13.2 Executive acknowledges that the success of the Company depends in large part on the protection of the Confidential Information.Executive further acknowledges that in the course of Executive’s employment with the Company, Executive will become familiar with the Company’sConfidential Information. Executive recognizes and acknowledges that the Confidential Information is a valuable, special and unique asset of theCompany’s business, access to and knowledge of which are essential to the performance of Executive’s duties hereunder. Executive acknowledges that use ordisclosure of the Confidential Information outside the performance of Executive’s job duties for the Company would cause harm and/or damage to theCompany. 13.3 Both during and after the Term, Executive shall not, except in the ordinary course of Executive’s employment with the Company,disclose any Confidential Information to any person, firm, business, company, corporation, association or any other entity for any reason or purposewhatsoever. Executive shall not make use of any Confidential Information for Executive’s own purposes or for the benefit of any person, firm, business,company, corporation or any other entity (except the Company) under any circumstances during or after the Term. Executive shall consider and treat asconfidential all Confidential Information in any way relating to the Company’s business and affairs, whether created by Executive or otherwise coming intoExecutive’s possession before, during, or after the Term. Executive shall secure and protect the Confidential Information in a manner designed to prevent allaccess and uses thereof contrary to the terms of this Agreement. Executive shall use Executive’s best efforts to assist the Company in identifying andpreventing any use or disclosure of the Confidential Information contrary to this Agreement. 13.4 Executive represents and warrants that, upon Termination (whether during or after the Term), and without any request by theCompany, Executive shall return to Company any and all property, documents and files (including all recorded media, such as papers, computer disks orother data storage devices, copies, photographs, maps, transparencies and microfiche) that contain Confidential Information or relate in any way to theCompany or its business. To the extent Executive possesses any files, data or information relating in any way to the Company or its business on any personalcomputer, Executive shall delete such files, data or information (and shall retain no copies in any form). Executive also shall return any Company tools,equipment, calling cards, credit cards, access cards or keys, any keys to any filing cabinets or vehicles and all other Company property in any form prior toTermination (whether during or after the Term). 8  14. Equitable Remedies. The services to be rendered by Executive and the Confidential Information entrusted to Executive as a result ofExecutive’s employment by the Company are of a unique and special character, and, notwithstanding anything in this Agreement to the contrary, any breachby Executive of this Agreement, including a breach of Section 12 or Section 13, will cause the Company immediate and irreparable injury and damage, forwhich monetary relief would be inadequate or difficult to quantify. The Company shall be entitled to, in addition to all other remedies available to it,injunctive relief, specific performance or any other equitable relief to prevent a breach and to secure the enforcement of the provisions of this Agreement. Theprovisions of Section 12 and Section 13 are separate from and independent of the remainder of this Agreement and these provisions are specificallyenforceable by the Company notwithstanding any claim made by Executive against the Company. Injunctive relief may be granted immediately upon thecommencement of any such action, and the Company need not post a bond to obtain temporary or permanent injunctive relief. 15. Business Opportunities. Executive shall promptly disclose to the Company all business ideas, prospects, proposals and other opportunitiespertaining to any aspect of the Company’s business that are originated by any third parties and brought to the attention of Executive after the Effective Dateand before Termination. 16. Representations and Warranties. Executive hereby represents and warrants to the Company, and acknowledges, as follows. 16.1 The success of the Company’s business depends in large part on the protection of the Confidential Information and trade secrets. 16.2 Executive’s access to the Confidential Information, coupled with the personal relationships and goodwill between the Companyand its customers, would enable Executive to compete unfairly against the Company. 16.3 Executive has full power, authority and capacity to enter into this Agreement and to perform Executive’s obligations hereunder. 16.4 This Agreement has been voluntarily executed by Executive and constitutes a valid and binding agreement of Executive and theCompany. 16.5 Executive has read this Agreement and has had the opportunity to have this Agreement reviewed by Executive’s legal counsel. 16.6 Given the nature of the business in which the Company is engaged, the restrictions in Section 12 and Section 13, including theirgeographic scope and duration, are reasonable and necessary to protect the legitimate business interests of the Company. 16.7 Executive’s continued employment with the Company is sufficient consideration for this Agreement. 16.8 Executive is among the Company’s executive personnel, management personnel or officers and employees who constituteprofessional staff to executive and management personnel. 16.9 This Agreement is intended to protect the Company’s trade secrets and Confidential Information. 16.10 To the best of Executive’s knowledge, Executive’s employment with the Company will not (a) conflict with or result in a breachof, (b) constitute a default under, (c) result in the violation of, (d) give any third party the right to terminate or to accelerate any obligation under, or (e)require any authorization, consent, approval, execution or other action by or notice to any court or other governmental body under, the provisions of anyother agreement or instrument to which Executive is a party. 9  16.11 Executive has not previously and shall not in the future disclose to the Company any proprietary information, trade secrets orother confidential information belonging to any previous employer. 16.12 Executive shall notify business partners and future employers of Executive’s obligations under this Agreement. 17. Waivers and Amendments. The respective rights and obligations of the Parties under this Agreement may be waived (either generally or in aparticular instance, either retroactively or prospectively and either for a specified period of time or indefinitely) or amended only with the written consent of aduly authorized representative of the Parties. The waiver by either Party of a breach of any provision of this Agreement by the other Party shall not operate orbe construed as a waiver of any subsequent breach by such other Party. The failure of either Party to insist upon strict performance of any of the terms orconditions of this Agreement shall not constitute a waiver of any of such Party’s rights hereunder. 18. Successors and Assigns. The provisions hereof shall inure to the benefit of, and be binding upon and assignable to, successors of theCompany by way of merger, consolidation or sale. Executive may not assign or delegate to any third person Executive’s obligations under this Agreement.The rights and benefits of Executive under this Agreement are personal to Executive (or, in the event of Executive’s death or Disability, Executive’s personalrepresentative, heirs or beneficiaries), and no such right or benefit shall be subject to voluntary or involuntary alienation, assignment or transfer. 19. Entire Agreement. This Agreement constitutes the full and entire understanding and agreement of the Parties with regard to the subjectshereof and supersedes and cancels in its entirety all other or prior or contemporaneous agreements, whether oral or written, with respect thereto, including anyprior employment agreements between Executive and the Company in their entirety. 20. Notices. Any notices, consents or other communications required to be sent or given hereunder by either of the Parties shall in every case bein writing and shall be deemed properly served if (i) delivered personally, (ii) sent by registered or certified mail, in all such cases with first class postageprepaid, return receipt requested, or (iii) delivered by a nationally recognized overnight courier service to the Parties at the following addresses: if to theCompany, to its principal headquarters; and if to Executive, to Executive’s current address listed in the Company’s records. 21. Governing Law; Consent to Jurisdiction; Consent to Venue; Service of Process. This Agreement shall be construed and interpreted inaccordance with the internal laws of the State of Texas without regard to principles of conflicts of law thereof, or principles of conflicts of laws of any otherjurisdiction that could cause the application of the laws of any jurisdiction other than the State of Texas. For purposes of resolving any dispute that arisesdirectly or indirectly from the relationship of the Parties evidenced by this Agreement, the Parties hereby submit to and consent to the exclusive jurisdictionof the State of Texas and agree that any related litigation shall be conducted solely in the courts of Harris County, Texas or the federal courts for the UnitedStates for the Southern District of Texas, where this Agreement is made and/or to be performed, and no other courts. Each Party may be served with process inany manner permitted under State of Texas law, or by United States registered or certified mail, return receipt requested. 22. Waiver of Jury Trial. EACH OF THE PARTIES HEREBY VOLUNTARILY AND IRREVOCABLY WAIVES ANY RIGHT IT MAY HAVE TOA TRIAL BY JURY IN ANY ACTION OR OTHER PROCEEDING BROUGHT IN CONNECTION WITH THIS AGREEMENT OR ANY OF THETRANSACTIONS CONTEMPLATED HEREBY. 10  23. Code Section 409A. It is intended that this Agreement comply with Code Section 409A (“Section 409A”), to the extent applicable. ThisAgreement shall be administered in a manner consistent with this intent, and any provision that would cause this Agreement to fail to satisfy Section 409Ashall have no force or effect until amended to comply with Section 409A. Notwithstanding anything in this Agreement to the contrary, in the event anypayment or benefit hereunder is determined to constitute nonqualified deferred compensation subject to Section 409A, then to the extent necessary tocomply with Section 409A, such payment or benefit shall not be made, provided or commenced until six months after Executive’s separation from service.Lump sum payments shall be made, without interest, as soon as administratively practicable following the six-month delay. Any installments otherwise dueduring the six-month delay shall be paid in a lump sum, without interest, as soon as administratively practicable following the six-month delay, and theremaining installments shall be paid in accordance with the original schedule. For purposes of Section 409A, the right to a series of installment paymentsshall be treated as a right to a series of separate payments. Each separate payment in the series of separate payments shall be analyzed separately for purposesof determining whether such payment is subject to, or exempt from compliance with, the requirements of Section 409A. Notwithstanding anything in thisAgreement to the contrary, to the extent required in order to avoid accelerated taxation and/or additional taxes under Section 409A, amounts reimbursable toExecutive under this Agreement shall be paid to Executive on or before the last day of the year following the year in which the expense was incurred and theamount of expenses eligible for reimbursement (and in-kind benefits provided to Executive) during any one year may not effect amounts reimbursable orprovided in any subsequent year. The Company makes no representations or warranties that the payments provided under this Agreement comply with, or areexempt from, Section 409A, and in no event shall the Company be liable for any portion of any taxes, penalties, interest or other expenses that may beincurred by Executive on account of non-compliance with Section 409A. 24. Severability. In case any provision of this Agreement shall be invalid, illegal or unenforceable, the validity, legality and enforceability of theremaining provisions of this Agreement shall not in any way be affected or impaired thereby. In the event any provision is held invalid, illegal orunenforceable, such provision shall be limited or revised by a court of competent jurisdiction so as to give effect to the provision to the fullest extentpermitted by applicable law. If any of the covenants in Section 12 are held to be unreasonable, arbitrary or against public policy, such covenants shall beconsidered divisible with respect to scope, time and geographic area, and in such lesser scope, time and geographic area, shall be effective, binding andenforceable against Executive to the greatest extent possible. 25. Construction. In this Agreement, unless otherwise stated, the following uses apply: (i) references to a statute or law refer to the statute or lawand any amendments and any successor statutes or laws, and to all valid and binding governmental regulations, court decisions and other regulatory andjudicial authority issued or rendered thereunder, as amended, or their successors, as in effect at the relevant time; (ii) in computing periods from a specifieddate to a later specified date, the words “from” and “commencing on” (and the like) mean “from and including,” and the words “to,” “until” and “ending on”(and the like) mean “to and including”; (iii) indications of time of day shall be based upon the time applicable to the location of the principal headquarters ofthe Company; (iv) the words “include,” “includes” and “including” (and the like) mean “include, without limitation,” “includes, without limitation” and“including, without limitation” (and the like), respectively; (v) all references to articles and sections are to articles and sections in this Agreement; (vi) allwords used shall be construed to be of such gender or number as the circumstances and context require; (vii) the captions and headings of articles andsections have been inserted solely for convenience of reference and shall not be considered a part of this Agreement, nor shall any of them affect the meaningor interpretation of this Agreement or any of its provisions; (viii) any reference to an agreement, plan, policy, form, document or set of documents, and therights and obligations of the parties under any such agreement, plan, policy, form, document or set of documents, shall mean such agreement, plan, policy,form, document or set of documents as amended from time to time, and any and all modifications, extensions, renewals, substitutions or replacements thereof;and (ix) all accounting terms not specifically defined shall be construed in accordance with generally accepted accounting principles. 11  26. Survival. The provisions of Section 12 and Section 13 shall survive the termination of this Agreement. 27. Counterparts. This Agreement may be executed in any number of counterparts, each of which shall be deemed an original, and all of whichtogether shall constitute one and the same Agreement. IN WITNESS WHEREOF, the Parties hereto have executed this Agreement on the date first above specified. COMPANYEXECUTIVE Sign Name: /s/ Abraham Mirman Sign Name: /s/ Seth Blackwell Print Name: Abraham Mirman Print Name: Seth Blackwell Title: Chief Executive Officer 12  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 Delaware  Exhibit 23.1 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 andFile No. 333-214822) of our report dated March 3, 2017, with respect to our audits of the consolidated financial statements of Lilis Energy, Inc. andSubsidiaries as of December 31, 2016 and 2015 and for the years ended December 31, 2016 and 2015, which report is included in this Annual Report onForm 10-K of Lilis Energy, Inc. for the year ended December 31, 2016. /s/ Marcum LLP Marcum LLPNew York, NYMarch 3, 2017  Exhibit 23.2 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 in theAnnual Report on Form 10-K of Lilis Energy, Inc. for the year ended December 31, 2016 (the “Annual Report”). We hereby further consent to the inclusion inthe Annual Report of estimates of oil and gas reserves contained in our report dated January 12, 2017, and to the inclusion of our report as an exhibit to theAnnual Report and in all current and future registration statements of the Company that incorporate by reference such Annual Report. /s/ Cawley, Gillespie & Associates, Inc. Cawley, Gillespie & Associates, Inc. Texas Registered Engineering Firm F-693 March 3, 2017  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, Abraham Mirman, 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 thisreport; 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, toensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within thoseentities, 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 forexternal purposes in accordance with generally accepted accounting principles; c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recentfiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materiallyaffect, 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 controlover financial reporting. By:/s/Abraham Mirman Abraham Mirman Chief Executive Officer March 3, 2017  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 thisreport; 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, toensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within thoseentities, 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 forexternal purposes in accordance with generally accepted accounting principles; c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recentfiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materiallyaffect, 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 controlover financial reporting. By:/s/ Joseph C. Daches Joseph C. Daches Executive Vice President and Chief Financial Officer March 3, 2017  Exhibit 32.1 OFFICER'S CERTIFICATIONPURSUANT TOSECTION 906 OF THE SARBANES-OXLEY ACT OF 2002(18 U.S.C 1350) The undersigned, Abraham Mirman, the Chief Executive Officer of Lilis Energy, Inc., (the "Corporation"), in connection with the Corporation's Yearly Reporton Form 10-K for the year ended December 31, 2016, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), does herebyrepresent, 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/ Abraham Mirman Abraham Mirman Chief Executive Officer March 3, 2017  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"), in connection withthe Corporation's Yearly Report on Form 10-K for the year ended December 31, 2016, as filed with the Securities and Exchange Commission on the datehereof (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 ofhis 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 3, 2017  Exhibit 99.1 CAWLEY, GILLESPIE & ASSOCIATES, INC.petroleum consultants 13640 BRIARWICK DRIVE, SUITE 100306 WEST SEVENTH STREET, SUITE 3021000 LOUISIANA STREET, SUITE 625AUSTIN, TEXAS 78729-1107FORT WORTH, TEXAS 76102-4987HOUSTON, TEXAS 77002-5008512-249-7000817- 336-2461713-651-9944 www.cgaus.com January 12, 2017 Lilis Energy, Inc.216 16th Street, Suite 1350Denver, Colorado 80202 Re:Evaluation Summary Lilis Energy, Inc. Interests Total Proved Reserves As of December 31, 2016 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 12, 2017 for Lilis Energy, Inc. (“LEI”) for the purpose of submitting our estimates of provedreserves and forecasts of economics attributable to the subject interests. We have evaluated 100% of LEI reserves, which are made up of oil and gas propertiesin various fields throughout the United States. This evaluation utilized an effective date of December 31, 2016, was prepared using constant prices and costs,and conforms to Item 1202(a)(8) of Regulation S-K and other rules of the Securities and Exchange Commission (SEC). The results of this evaluation arepresented in the accompanying tabulations, with a composite summary of the values presented below: Proved Proved Developed Developed Proved Total Producing Non-Producing Developed Proved Net Reserves Oil - Mbbl 260.1 290.6 550.7 550.7 Gas - MMcf 2,030.1 1,841.4 3,871.5 3,871.5 NGL - Mbbl 3.2 0.0 3.2 3.2 Revenue Oil - M$ 9,611.9 10,931.5 20,543.4 20,543.4 Gas - M$ 4,756.3 3,174.8 7,931.1 7,931.1 NGL - M$ 39.0 0.0 39.0 39.0 Severance Taxes - M$ 725.9 742.2 1,468.2 1,468.2 Ad Valorem Taxes - M$ 466.9 352.7 819.5 819.5 Operating Expenses - M$ 5,112.7 3,485.1 8,597.8 8,597.8 Other Deductions - M$ 2,197.8 2,855.5 5,053.3 5,053.3 Investments - M$ 0.0 3,388.4 3,388.4 3,388.4 Net Cash Flows - M$ 5,903.8 3,282.5 9,186.3 9,186.3 Discounted @ 10% (Present Worth) - M$ 4,650.8 2,004.2 6,655.0 6,655.0  Future revenue is prior to deducting state production taxes and ad valorem taxes. Future net cash flow is after deducting these taxes, future capitalcosts and operating expenses, but before consideration of federal income taxes. In accordance with SEC guidelines, the future net cash flow has beendiscounted at an annual rate of ten percent to determine its “present worth”. The present worth is shown to indicate the effect of time on the value of moneyand 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 expressedin barrels (42 U.S. gallons). Gas volumes are expressed 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 been attributed to interest inacreage beyond the location for which undeveloped reserves have been estimated. The Proved Developed category is the summation of the ProvedDeveloped Producing and Proved Developed Non-Producing estimates. PresentationThis report is divided into three main sections: Summary (Total Proved and Proved Developed), Proved Developed Producing (“PDP”) and ProvedDeveloped Non-Producing (“PDNP”). Within each section are Tables I and Summary Plots. Tables II and Individual Figures and Tables are also included inthe PDP and PDNP sections. The Tables I present composite reserve estimates and economic forecasts for the particular reserve category or property grouping.The Summary Plots are composite 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 income and discounted cashflow for the individual properties that make up the corresponding Table I. Individual Figures and Tables present reserve estimates, economic forecasts andrate-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, 2016 were $42.75/bbl and $2.463/MMBTU, respectively. As specified by the SEC, acompany 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 the12-month period prior to the end of the reporting period. The base oil price is based upon WTI-Cushing spot prices (Bloomberg) from January - December2016 and the base gas price is based upon Henry Hub spot prices (Bloomberg) from January - December 2016. The base prices shown above were adjusted for differentials on a per-property basis, which may include local basis differentials, transportation, gasshrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. Natural gas liquid (NGL) prices were applied as a percentage ofWTI. After these adjustments, the net realized prices for the SEC price case over the life of the proved properties was estimated to be $37.304 per barrel for oil,$2.049 per MCF for gas and $12.161 per barrel for NGLs. All economic factors 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 reviewed by us for accuracy and completenesswhere available. In some cases, data was accepted as provided. Lease operating expenses were either determined at the area or individual well level usingaverages calculated from historical lease operating statements. All economic parameters, including lease operating expenses and investments, were heldconstant (not escalated) throughout the life of these properties.  SEC Conformance and RegulationsThe reserve classifications and the economic considerations used herein conform to the criteria of the SEC as defined in pages 3 and 4 of theAppendix. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect exceptas noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics havenot been considered. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recoveryof reserves. Reserve Estimation MethodsThe methods employed in estimating reserves are described in page 2 of the Appendix. Reserves for proved developed producing wells wereestimated using production performance methods. Certain new producing properties with little production history were forecast using a combination ofproduction performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy. Non-producing reserve estimates were forecast using a combination of volumetric and analogy methods. These methods provide a relatively highdegree of accuracy for predicting proved developed non-producing reserves for LEI properties. The assumptions, data, methods and procedures used hereinare appropriate 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. To some extent informationfrom public records has been used to check and/or supplement these data. The basic engineering and geological data were subject to third party reservationsand qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data. All estimatesrepresent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production rates, commodity pricesand 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 and their related facilitieshave not been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties hasnot been investigated nor considered. The cost of plugging and the salvage value of equipment at abandonment have not been included. Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers andgeologists that have provided petroleum consulting services to the oil and gas industry for over 50 years. This evaluation was supervised by W. ToddBrooker, Senior Vice President at Cawley, Gillespie & Associates, Inc. and a State of Texas Licensed Professional Engineer (License #83462). We do not ownan interest in the properties or Lilis Energy, Inc. and are not employed on a contingent basis. We have used all methods and procedures that we considernecessary under the circumstances to prepare this report. Our work-papers and related data utilized in the preparation of these estimates are available in ouroffice. Yours very truly, CAWLEY, GILLESPIE & ASSOCIATES, INC. Texas Registered Engineering Firm F-693 W. Todd Brooker, P. E. Senior Vice President  Professional Qualifications of Primary Technical Person The evaluation summarized by this report was conducted by a proficient team of geologists and reservoir engineers who integrate geological, geophysical,engineering and economic data to produce high quality reserve estimates and economic forecasts. This report was supervised by Todd Brooker, Senior VicePresident 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 been an employee of CG&Asince 1992. His responsibilities include reserve and economic evaluations, fair market valuations, field studies, pipeline resource studies andacquisition/divestiture analysis. His reserve reports are routinely used for public company SEC disclosures. His experience includes significant projects inboth 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 Petroleum Engineering, and is aregistered Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers. Based on his educational background, professional training and more than 20 years of experience, Mr. Brooker and CG&A continue to deliver professional,ethical and reliable engineering and geological services to the petroleum industry. CAWLEY, GILLESPIE & ASSOCIATES, INC. Texas Registered Engineering Firm F-693  .2 APPENDIX Methods 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. Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data available and thecharacteristics of the reservoirs. Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the quality, quantity and typesof information available on individual properties. Operators are generally required by regulatory authorities to file monthly production reports and may berequired to measure and report periodically such data as well pressures, gas-oil ratios, well tests, etc. As a general rule, an operator has complete discretion inobtaining and/or making available geological and engineering data. The resulting lack of uniformity in data renders impossible the application of identicalmethods to all properties, and may result in significant differences in the accuracy 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 theperformance to date will continue to control and that historical trends can be extrapolated to predict future performance. The only information required isproduction history. Capacity production can usually be 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, in some cases, be analyzed from graphs of producing rate relationships of the variousproduction components. Reserve estimates obtained by this method are generally considered to have a relatively high degree of accuracy with the degree ofaccuracy 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 reservoirvolume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzingchanges in pressure with respect to production relationships. This method requires reliable pressure and temperature data, production data, fluid analyses andknowledge of the nature of the reservoir. The material balance method is applicable to all reservoirs, but the time and expense required for its use isdependent on the nature of the reservoir and its fluids. Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected forcompressibility versus cumulative production, requiring only data that are usually available. Estimates for other reservoir types require extensive data andinvolve 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 thecomplexity of the reservoir and the 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 are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. Thevolumetric method is most applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods. These aremost commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons in-place that can be recovered is not an integral partof the volumetric calculations but is an estimate inferred by other methods and a knowledge of the nature of the reservoir. Reserve estimates obtained by thismethod are generally considered to have a low degree of accuracy; but the degree of accuracy can be relatively high where rock quality and subsurfacecontrol 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 includesconsideration of theoretical performance. The analogy method is a common approach used for “resource plays,” where an abundance of wells with similarproduction profiles facilitates the reliable estimation of future reserves with a relatively high degree of accuracy. The analogy method may also be applicablewhere the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve estimates obtained in this mannerare 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 continuingchange as additional information becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors astime passes and new information is obtained about well and reservoir performance.  2 APPENDIX Reserve 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 adherence to 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 andengineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and underexisting economic conditions, operating methods, and government regulations— prior to the time at which contracts providing the right to operate expire,unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Theproject to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonabletime. "(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 undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producibleoil or gas on the basis of available geoscience and 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 awell penetration unless 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 associatedgas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data andreliable technology establish the higher contact with reasonable certainty. "(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluidinjection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorablethan in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technologyestablishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved fordevelopment 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 shallbe the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic averageof the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations basedupon 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 minorcompared to the cost of a new well; and “(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means notinvolving a well. "(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered fromnew wells on undrilled 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 ofproduction when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greaterdistances. “(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they arescheduled to be drilled within 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 injectionor other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or ananalogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.  "(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which,together with proved reserves, 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 estimatedproved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equalor exceed the proved plus probable reserves estimates. “(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available dataare less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves maybe assigned to areas that are structurally higher 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 hydrocarbonsin place than assumed for 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 provedplus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimatelyrecovered will equal or exceed the proved plus probable 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 availabledata are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and verticallimits of commercial production from the reservoir by a defined project. “(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than therecovery quantities assumed for probable reserves. “(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical andcommercial interpretations 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 sameaccumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and thathave 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 structurally higher or lower than the proved area if these areas are in communication with the provedreservoir. “(vi) Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and thepotential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if thehigher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certaintycriterion may be assigned as probable and possible oil or gas based 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 inoil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S–K." This is relevant in that Instruction 2 toparagraph (a)(2) states: “The registrant is permitted, 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 ofa given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation thatthere will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market,and all permits and financing required to implement the project. “Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirsare penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by anon-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e.,potentially recoverable resources from undiscovered accumulations).” 

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