Lilis Energy
Annual Report 2015

Plain-text annual report

UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549 FORM 10-K ☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2015 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.) 216 16th Street, Suite 1350, Denver, CO 80202(Address of principal executive offices, including zip code) Registrant’s telephone number including area code: (303) 893-9000 Securities registered under Section 12(b) of the Act: Common Stock, $0.0001 par value The Nasdaq Capital MarketTitle of class Name of exchange on which registered Securities registered under Section 12(g) of the Act: None Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒ 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 ☒ 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 ☒ 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 ☒ 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 company☒ Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ The aggregate market value of voting and non-voting common equity held by non-affiliates as of June 30, 2015 was $11,917,000. As of March 30, 2016, 29,166,590 shares of the registrant’s Common Stock were issued and outstanding.  FORM 10-K ANNUAL REPORTFISCAL YEAR ENDED DECEMBER 31, 2015LILIS ENERGY, INC. PagePART I Items 1 and 2. Business and Properties6Item 1A. Risk Factors19Item 1B. Unresolved Staff Comments36Item 3. Legal Proceedings36 PART II Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities37Item 6.Selected Financial Data37Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations38Item 7A.Quantitative and Qualitative Disclosures About Market Risk49Item 8. Financial Statements and Supplementary Data49Item 9.Changes in and disagreements with Accountants on Accounting and Financial Disclosure49Item 9A.Controls and Procedures49Item 9B.Other Information50 PART III Item 10.Directors, Executive Officers and Corporate Governance51Item 11.Executive Compensation57Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 65Item 13.Certain Relationships and Related Transactions, and Director Independence69Item 14.Principal Accountant Fees and Services73 PART IV Item 15.Exhibits and Financial Statement Schedules74  FORWARD-LOOKING STATEMENTS This Annual Report on Form 10-K contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Allstatements other than statements of historical fact are “forward-looking statements” for purposes of federal and state securities laws, including, but not limitedto, any projections of earnings, revenue or other financial items; any statements of the plans, strategies and objectives of management for future operations;any statements concerning future production, reserves or other resource development opportunities; any projected well performance or economics, orpotential joint ventures or strategic partnerships; any statements regarding future economic conditions or performance; any statements regarding futurecapital-raising activities; any statements of belief; and any statements of assumptions underlying any of the foregoing. Forward-looking statements may include the words “may,” “should,” “could,” “estimate,” “intend,” “plan,” “project,” “continue,” “believe,” “expect” or“anticipate” or other similar words. These forward-looking statements present our estimates and assumptions only as of the date of this 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 to change and inherent risks and uncertainties. The factors impacting these risks and uncertainties include, but are not limited to, theRisk Factors set forth in this Annual Report on Form 10-K in Part I, “Item 1A. Risk Factors” and the following factors: ●we may not realize the expected benefits of our merger with Brushy Resources, Inc.(“Brushy”) quickly or at all; ●the closing conditions with respect to our merger with Brushy may not be satisfied; ●it may be more difficult or costly to integrate our business and operations with Brushy’s, it may take longer than anticipated, or it may haveunanticipated adverse results relating to our existing business or the combined company’s business; ●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 make itmore 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; ●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; ●our history of losses; ●inability to address our negative working capital position in a timely manner; ●the inability of management to effectively implement our strategies and business plans; ●potential default under our secured obligations, material debt agreements or agreements with our investors; ●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; 1  ●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; ●availability of funds under our credit agreement; ●increases in interest rates or our cost of borrowing; ●deterioration in general or regional (especially Rocky Mountain) economic conditions; ●the strength and financial resources of our competitors; ●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 acquire or maintain mineral leases at a favorable economic value that will allow us to expand our development efforts; ●inability to successfully develop our large inventory of undeveloped acreage we currently hold on a timely basis; ●constraints, interruptions or other issues affecting the Denver-Julesburg Basin, including with respect to transportation, marketing, processing,curtailment of production, natural disasters, and adverse weather conditions; ●technique 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; ●unanticipated recovery or production problems, including cratering, explosions, blow-outs, fires and uncontrollable flows of oil, natural gas orwell fluids; ●environmental liabilities; ●operating hazards and uninsured risks; ●data protection and cyber-security threats; ●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; ●changes in generally accepted accounting principles in the United States (“GAAP”),or in the legal, regulatory and legislative environments inthe markets in which we operate; and ●other factors, many of which are beyond our control. Many of these factors are beyond our ability to control or predict. These factors are not intended to represent a complete list of the general or specific factorsthat 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-looking statement,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 the SEC’swebsite (www.sec.gov). 2  GLOSSARY In this report, the following abbreviation and terms are used: Bbl. Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude, condensate or natural gas liquids. Bcf. Billion cubic feet of natural gas. BOE. Barrels of crude oil equivalent, determined using the .ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids. BOE/d. BOE per day. BTU or British Thermal Unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit. Completion. Installation of permanent equipment for production of natural gas or oil, or in the case of a dry hole, the reporting to the appropriate authoritythat the well has been abandoned. 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; 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 in a field previously found to be productive of natural gas or oil in anotherreservoir. 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 the Company owns a working interest, reported at the 100% or 8/8ths level. Forexample, the number of gross wells is the total number of wells in which the Company owns 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. Thousand barrels of crude oil or other liquid hydrocarbons. Mboe. Thousand barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids. Mcf. Thousand cubic feet of natural gas. 3  Mcfe. 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. Million British Thermal Units. MMcf. Million cubic feet of natural gas. Net acres; net wells. A “net acre” or “net well” is deemed to exist when the sum of fractional ownership working interests in gross acres or wells equals one.The number of net acres or wells is the sum of the fractional working interests owned in gross acres or wells expressed as whole numbers and fractions ofwhole 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 of3/4. Overriding royalty interest owners have no financial or other obligation or responsibility for developing and operating the property. The only expensesborne by the overriding royalty owner are a share of the production or severance taxes and sometimes costs incurred to make the oil or gas salable. Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape 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 reserves. Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certaintyto be 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 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 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. 4  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 Lilis Energy on a comparative basis to other companies and from period to period. 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. (“we,” “us,” “our,” “Lilis Energy,” “Lilis,” or the “Company”) is an upstream independent oil and gas company engaged in the acquisition,drilling and production of oil and natural gas properties and prospects. We were incorporated in August of 2007 in the State of Nevada as UniversalHoldings, Inc. In October 2009, we changed our name to Recovery Energy, Inc. and in December 2013, we changed our name to Lilis Energy, Inc. Our current operating activities are focused on the Denver-Julesburg Basin (“DJ Basin”) in Colorado, Wyoming and Nebraska. Overview of Our Business and Strategy We have acquired and developed a producing base of oil and natural gas proved reserves, as well as a portfolio of exploration and other undeveloped assetswith conventional and non-conventional reservoir opportunities, with an emphasis on those with multiple producing horizons, in particular the Muddy “J”conventional reservoirs and the Niobrara shale and Codell resource plays. We believe these assets offer the possibility of repeatable year-over-year successand significant and cost-effective production and reserve growth. Our acquisition, development and exploration pursuits are principally directed at oil andnatural gas properties in North America. As of December 31, 2015 we owned interests in 8 economically producing wells and 16,000 net leasehold acres, ofwhich 8,000 net acres are classified as undeveloped acreage and all of which are located in Colorado, Wyoming and Nebraska within the DJ Basin. We areprimarily focused on acquiring companies and production throughout North America and developing our North and South Wattenberg Field assets, whichinclude attractive unconventional reservoir drilling opportunities in mature development areas with low risk Niobrara and Codell formation productivepotential. Our goal is to create value by acquiring producing assets and developing our remaining inventory of low and controlled-risk conventional andunconventional properties, while maintaining a low cost structure. To achieve our goal, our business strategy includes the following elements: Capital raising. The business of oil and natural gas property acquisition, exploration and development is highly capital intensive and the level of operationsattainable by oil and natural gas companies is directly linked to and limited by the amount of available capital. Therefore, it is critical that we raise theadditional capital required to finance the exploration and development of our current oil and natural gas prospects and the acquisition of additionalproperties and companies. We plan to seek additional capital through the sale of our securities, through potential refinancing activities, debt and projectfinancing, joint venture agreements with industry partners, and through sale of assets. Our ability to obtain additional capital may be subject to therepayment of our existing obligations. Acquiring additional assets and companies throughout North America. We target acquisitions in North America, which meet certain current and futureproduction thresholds. We anticipate the acquisitions will be funded with funds borrowed under new debt instruments or the issuance of new equity. Pursuing the initial development of our Greater Wattenberg Field unconventional assets. We plan to drill several horizontal wells on our South WattenbergField property if we can obtain the financing to do so. Drilling activities will target the well-established Niobrara and Codell formations. Extending the development of certain conventional prospects within our inventory of other DJ Basin properties. Subject to the securing of additionalcapital, we anticipate drilling and developing our DJ Basin assets where initial exploration has yielded positive results. Retaining operational control and significant working interest. In our principal development targets, we typically seek to maintain operational control ofour development and drilling activities. As operator, we retain more control over the timing, selection and process of drilling prospects and completiondesign, which enhances our ability to maximize our return on invested capital and gives us greater control over the timing, allocation and amounts of capitalexpenditures. However, due to our recent liquidity difficulties, we are not the operator on a significant amount of our current drilling activity on wells inwhich we own a working interest. 6  Leasing of prospective acreage. We seek to identify drilling opportunities on properties that have not yet been leased. Subject to securing additionalcapital, we may take the initiative to lease prospective acreage and we may sell all or any portion of the leased acreage to other companies that want toparticipate in the drilling and development of the prospect acreage. Consistently evaluating acreage. Currently, our inventory of developed and undeveloped acreage includes approximately 18,000 gross (16,000 net) acres, ofwhich 10,000 gross (8,000 net) that are held by production, approximately, 2,000, 5,000 and 1,000 net acres that expire in the years 2016, 2017, andthereafter, respectively. Approximately 88% of our inventory of undeveloped acreage provides for extension of lease terms from two to five years, at ouroption, by payment of varying, but typically nominal, extension amounts. In 2015, we evaluated our leases and allowed 63% of our leaseholds to expire dueto capital constraints or the determination that present and future carrying and drilling costs were uneconomic. We continue to evaluate the 2016 and 2017lease expirations to determine if production on this acreage would be economic and as such, a focus for future development. If determined to be a focus forfuture development, we plan to re-lease if available. If not a focus, we plan to let the acreage expire. We will continue to pursue additional properties, acquireother properties throughout North America, or drill wells on our core properties to hold the property by production if financing is available to us and theproperties are economic. Hedging. From time to time, we may use commodity price hedging instruments to reduce our exposure to oil and natural gas price fluctuations and to helpensure that we have adequate cash flow to fund our debt service costs and capital programs. As such, we expect to enter into futures contracts, collars andbasis swap agreements, as well as fixed price physical delivery contracts. We intend to use hedging primarily to manage price risks and returns on certainacquisitions and drilling programs. Our policy is to consider hedging an appropriate portion of our production at commodity prices we deem attractive. In thefuture we may also be required by our lenders to hedge a portion of production as part of any financing. Outsourcing. We intend to continue to use the services of independent consultants and contractors to provide various professional services, including land,legal, environmental, technical, investor relations and tax services. We believe that by limiting our management and employee costs, we may be able tobetter control lifting costs and retain general and administrative expense flexibility. Pending Merger with Brushy Resources, Inc. On December 29, 2015, we announced entering into an Agreement and Plan of Merger (the “Merger Agreement”) with Brushy Resources, Inc. (“Brushy”),whereby we will issue approximately 4.550916 shares of our Common Stock for each outstanding share of Brushy common stock in a merger in whichBrushy will be a direct wholly-owned subsidiary of ours, which we refer to as the “Merger.” The location and predominant nature of Brushy’s oil and gas properties is consistent with our strategy to focus our efforts on oil and gas properties in similarareas, and the complementary nature of our two companies’ respective asset bases is expected to permit our combined company to compete more effectivelywith other exploration and production companies. In addition, we expect that the combined entity will result in a larger company with a greater marketcapitalization, which we in turn expect to provide us with more liquidity in our Common Stock and better access to capital markets. The combination with Brushy would provide us with a significant presence in the Permian Basin in southeast New Mexico and west Texas, which we do notcurrently have a presence in, including in the Crittendon Field, as well as the ability to participate and jointly operate, along with a related party of Brushy,in the Giddings Field. The Crittendon Field is approximately 2,759 net acres and contains approximately 16 gross (10.4 net) oil and natural gas wells, withestimated proved reserves of approximately 1,432 MBOE. Consummation of the Merger is subject to the satisfaction of various closing conditions, including the registration and listing of the shares of our CommonStock that will be issued in the merger transaction, the approval of Brushy’s senior lender, and the approval of the Merger by the holders of a majority of theshares of our Common Stock and Brushy’s common stock entitled to vote on the transaction. We may not be able to satisfy all of these closing conditions, inwhich case the Merger may not be completed. 7  The foregoing discussion of the Merger does not purport to be complete and is qualified in its entirety by reference to the full text of the Merger Agreementand our other filings with the Securities and Exchange Commission (“SEC”). For additional details regarding the terms and conditions of the Merger, you canrefer to our filings with the SEC, which can be accessed at www.sec.gov. Additional information regarding the Merger, including risks associated with theMerger, will be contained in a joint proxy statement/prospectus to be filed by us and Brushy. 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, 2015, we owned interests in approximately 16,000 net leasehold acres, of which 8,000 net acres are classified as undeveloped acreageand all of which are located in Colorado, Wyoming and Nebraska within the DJ Basin. Our primary targets within the DJ Basin are the conventional Dakotaand Muddy “J” formations, and the developing unconventional Niobrara shale play. Additional horizons include the Codell, Greenhorn, the Permian Basinand other potential resource formations. During the year ended December 31, 2015, we made minimal capital expenditures on our oil and gas properties due to capital constraints. In addition, thelower commodity prices and lack of capital to develop our undeveloped oil and gas properties caused us to recognize an impairment expense of $24.48million. No impairment expense was recognized during the year ended December 31, 2014. Reserves The table below presents summary information with respect to the estimates of our proved oil and gas reserves for the year ended December 31, 2015. Weengaged Forrest A Garb & Associates, Inc. (“Forrest Garb”) and Ralph E. Davis to audit internal engineering estimates for 100% of our proved reserves atyear-end 2015 and 2014, respectively. The prices used in the calculation of proved reserve estimates as of December 31, 2015, were $42.59 per Bbl and$2.79 per MCF; as of December 31, 2014, were $81.71 per Bbl and $5.34 per MCF and as of December 31, 2013, were $89.57 per Bbl and $4.74 per MCF foroil and natural gas, respectively. The prices were adjusted for basis differentials, pipeline adjustments, and BTU content. We emphasize that reserve estimates are inherently imprecise and that estimates of all new discoveries and undeveloped locations are more imprecise thanestimates of established producing oil and gas properties. Accordingly, these estimates are expected to change as new information becomes available. ThePV-10 values shown in the following table are not intended to represent the current market value of the estimated proved oil and gas reserves owned by us. Neither prices nor costs have been escalated (or reduced). The following table should be read along with the section entitled “Risk Factors—Risks Related toOur Company”. The actual quantities and present values of our proved oil and natural gas reserves may be less than we have estimated. 8  Summary of Oil and Gas Reserves as of Fiscal-Year End As of December 31, 2015 2014 2013 Reserve data: Proved developed Oil (MBbl) 33 50 171 Gas (MMcfe) 141 197 313 Total (MBOE)(1) 57 83 223 Proved undeveloped Oil (MBbl) - 850 672 Gas (MMcfe) - 4,040 2,251 Total (MBOE)(1) - 1,523 1,047 Total Proved Oil (MBbl) 33 900 843 Gas (MMcfe) 141 4,237 2,564 Total (MBOE)(1) 57 1,606 1,270 Proved developed reserves % 100% 5% 18%Proved undeveloped reserves % - 95% 82% Reserve value data (in thousands): Proved developed PV-10 $608 2,340 $7,675 Proved undeveloped PV-10 $- 20,914 $15,667 Total proved PV-10 (2) $608 23,254 $23,342 Standardized measure of discounted future cash flows $608 23,254 $23,342 Reserve life (years) 26.2 39.25 33.25 (1)BOE is determined using the ratio of six MCF of natural gas to one Bbl of crude oil, condensate or natural gas.(2)As we currently do not expect to pay income taxes in the near future, there is no difference between the PV-10 value and the standardized measure ofdiscounted future net cash flows. Please see the definitions of standardized measure of discounted future net cash flows and PV-10 value in the“Glossary.” Changes in Proved Undeveloped Reserves During the year ended December 31, 2015, we recognized an impairment expense of $24.48 million due to the lower commodity prices and lack of capital todevelop our undeveloped oil and gas properties. As such, we currently have no proved undeveloped reserves. 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 reserve quantities andvalues in compliance with the regulations of the SEC. Responsibility for compliance in reserve bookings is delegated to our Chief Financial Officer withassistance from our senior geologist consultant and a senior reserve engineering consultant. Technical reviews are performed throughout the year by our senior reserve engineering consultant and our geologist and other consultants who evaluate allavailable geological and engineering data, under the guidance of the Chief Financial Officer. This data, in conjunction with economic data and ownershipinformation, is used in making a determination of estimated proved reserve quantities. The 2015 reserve process was overseen by Kent Lina, our seniorreserve engineering consultant. Mr. Lina was previously employed by us from October 2010 through December 2012, and prior to that was employed byDelta Petroleum Corporation from March 2002 to September 2010 in various operations and reservoir engineering capacities culminating as the Senior VicePresident of Corporate Engineering. Mr. Lina received a Bachelor of Science degree in Civil Engineering from University of Missouri at Rolla in 1981. Mr.Lina currently serves various industry clients as a senior reserve engineering consultant. Third-party Reserves Study An independent third-party reserve study as of December 31, 2015 was performed by Forrest Garb using its own engineering assumptions and other economicdata provided by us. All of our total calculated proved reserve PV-10 value was prepared by Forrest Garb. Forrest Garb is an independent petroleumengineering consulting firm that has been providing petroleum engineering consulting services for over 28 years. The individual at Forrest Garb primarilyresponsible for overseeing our reserve audit is Stacy M. Light, Senior Vice President of Petroleum Engineering, who received a Bachelor of Science degree inPetroleum Engineering from the Texas A&M and is a registered Professional Engineer in the States of Texas. She is also a member of the Society ofPetroleum Engineers. 9  The Forrest Garb report dated April 13, 2016, 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 prescribed by theSEC and Financial Accounting Standards Board (“FASB”) guidelines. Reserve calculations involve the estimate of future net recoverable reserves of oil andgas and the timing and amount of future net cash flows to be received therefrom. Such estimates are not precise and are based on assumptions regarding avariety of factors, many of which are variable and uncertain. Proved reserves were estimated in accordance with guidelines established by the SEC and theFASB, which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalationsexcept by contractual arrangements. For the year ended December 31, 2015, commodity prices over the prior 12-month period and year end costs were usedin 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 principalaccounting officer and the Audit Committee of our Board of Directors. Our Chief Financial Officer is responsible for reviewing and verifying that theestimate of proved reserves is reasonable, complete, and accurate. The Audit Committee of our Board of Directors reviews the final reserves estimate inconjunction with Forrest Garb’s audit letter. Production The following table summarizes the average volumes and realized prices, excluding the effects of our economic hedges, of oil and gas produced fromproperties in which we held an interest during the periods indicated, and production cost per BOE: For the Year EndedDecember 31, 2015 2014 2013 Product Oil (Bbl.) 7,067 33,508 51,705 Oil (Bbls)-average price (1) $41.36 $77.05 $83.40 Natural Gas (MCFE)-volume 32,291 77,954 64,845 Natural Gas (MCFE)-average price (2) $2.39 $4.68 $5.25 Barrels of oil equivalent (BOE) 12,449 46,500 62,512 Average daily net production (BOE) 34 127 171 Average Price per BOE (1) $29.67 $63.36 $74.43 (1)Does not include the realized price effects of hedges(2)Includes proceeds from the sale of NGL's Oil and gas production costs, production taxes, depreciation, depletion, and amortization Production costs per BOE 15.70 20.52 19.48 Production taxes per BOE 2.24 5.80 4,21 Depreciation, depletion, and amortization per BOE 46.93 28.76 38.21 Total operating costs per BOE (1) $64.87 $55.08 $61.90 Gross margin per BOE (1) $(35.20) $8.28 $12.53 Gross margin percentage 119% 13% 17% (1)Does not include the loss on conveyance 10  Productive Wells As of December 31, 2015, we had working interests in 6 gross (1.27 net) productive oil wells, and 2 gross (0.14 net) productive gas wells. Productive wellsare either wells producing in commercial quantities or wells capable of commercial production although 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, 2015, we owned 8 producing wells in Wyoming, Nebraska and Colorado within the DJ Basin, as well as approximately 18,000 gross(16,000 net) acres, of which 10,000 gross (8,000 net) acres were classified as undeveloped acreage. Our primary assets included acreage located in Laramieand 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, 2015: Undeveloped Developed Gross Net Gross Net DJ Basin 10,000 8,000 8,000 8,000 Total 10,000 8,000 8,000 8,000 Currently, our inventory of developed and undeveloped acreage includes approximately 18,000 gross (16,000 net) acres, of which 10,000 gross (8,000 net)that are held by production, approximately, 2,000, 5,000 and 1,000 net acres that expire in the years 2016, 2017, and thereafter, respectively. Approximately88% of our inventory of undeveloped acreage provides for extension of lease terms from two to five years, at our option, by payment of varying, but typicallynominal, extension amounts. In 2015, we evaluated our leases and allowed 63% of our leaseholds to expire due to capital constraints or the determinationthat present and future carrying and drilling costs were uneconomic. We continue to evaluate the 2016 and 2017 lease expirations to determine if productionon this acreage would be economic and as such is a focus for future development. If determined to be a focus for future development, we plan to re-lease ifavailable. If not a focus, we plan to let the acreage expire. We will continue to pursue additional properties, acquire other properties throughout NorthAmerica, or drill wells on our core properties to hold the property by production if financing is available to us and the properties are economic. Drilling Activity The following table describes the development and exploratory wells we drilled from 2013 through 2015: For the Year Ended December 31, 2015 2014 2013 Gross Net Gross Net Gross Net Development: Productive wells - - - - 2 1 Dry wells - - - - - - - - - - 2 1 Exploratory: Productive wells - - - - - - Dry wells - - - - - - Total development and exploratory - - - - 2 1 The number of wells drilled refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated. 11  Title to Properties Substantially all of our leasehold interests are held pursuant to leases from third parties. The majority of our producing properties are subject to mortgagessecuring indebtedness under both our Credit Agreement, entered into on January 8, 2015 (the “Credit Agreement”) with Heartland Bank (“Heartland”), asadministrative agent and the lenders party thereto, and our 8% Senior Secured Convertible Debentures (“Debentures”), which we believe do not materiallyinterfere 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, by prevailingprices for crude oil and natural gas. We sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts. Themarket price for oil and natural gas is dictated by supply and demand, and we cannot accurately predict or control the price we may receive for our oil andnatural gas. Our revenues, cash flows, profitability and future rate of growth will depend substantially upon prevailing prices for oil and natural gas. Prices may alsoaffect the amount of cash flow available for capital expenditures and other cash requirements and our ability to borrow money or raise additionalcapital. Lower prices may also adversely affect the value of our reserves and make it uneconomical for us to commence or continue production levels ofnatural gas and crude oil. Historically, the prices received for oil and natural gas have fluctuated widely. Among the factors that can cause these fluctuationsare: ●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 our operationsare 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 and natural 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, 2015, we had no hedging agreements in place. 12  Major Customers Our major customers include, Shell Trading (US), PDC Energy and Noble Energy. These customers accounted for approximately 42%, 26% and 21% of ourrevenue for the year ended December 31, 2015 and approximately 63%, 14% and 9% of our revenue for the year ended December 31, 2014, respectively. However, we do not believe that the loss of any single customer would materially affect our business because there are numerous other purchasers of ourproduction. Seasonality Generally, but not always, the demand and price levels for natural gas increase during colder winter months and decrease during warmer summer months. Tolessen seasonal demand fluctuations, pipelines, utilities, local distribution companies, and industrial users utilize natural gas storage facilities and forwardpurchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity has placed increaseddemand on storage volumes. Demand for crude oil and heating oil is also generally higher in the winter and the summer driving season, although oil pricesare 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 our leaseholdposition provides a solid foundation for an economically robust exploration program and our future growth. Our success and growth also depends on ourgeological, geophysical, and engineering expertise, design and planning, and our financial resources. We believe the location of our acreage, our technicalexpertise, available technologies, our financial resources and expertise, and the experience and knowledge of our management enables us to competeeffectively in our core operating areas. However, we face intense competition from a substantial number of major and independent oil and gas companies,which have larger technical staffs and greater financial and operational resources than we do. Many of these companies not only engage in the acquisition,exploration, development, and production of oil and natural gas reserves, but also have refining operations, market refined products, own drilling rigs, andgenerate electricity. 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 oiland gas industry, the need to attract and retain talented people has grown at a time when the number of talented people available is constrained. We are notinsulated from this resource constraint, and we must compete effectively in this market in order to be successful. 13  Government Regulations General. Our operations covering the exploration, production and sale of oil and natural gas are subject to various types of federal, state and local laws andregulations. The failure to comply with these laws and regulations can result in substantial penalties. These laws and regulations materially impact ouroperations and can affect our profitability. However, we do not believe that these laws and regulations affect us in a manner significantly different than ourcompetitors. Matters regulated include permits for drilling operations, drilling and abandonment bonds, reports concerning operations, the spacing of wellsand unitization and pooling of properties, restoration of surface areas, plugging and abandonment of wells, requirements for the operation of wells,production and processing facilities, land use, subsurface injection, air emissions, and taxation of production, etc. At various times, regulatory agencies haveimposed price controls and limitations on production. In order to conserve supplies of oil and natural gas, these agencies have restricted the rates of flow ofoil and natural gas wells below actual production capacity, generally prohibit the venting or flaring of natural gas and impose certain requirements regardingproduction. Federal, state and local laws regulate production, handling, storage, transportation and disposal of oil and natural gas, by-products from oil andnatural gas and other substances and materials produced or used in connection with oil and natural gas operations. While we believe we will be able tosubstantially comply with all applicable laws and regulations via our strict attention to regulatory compliance, the requirements of such laws and regulationsare frequently changed. We cannot predict the ultimate cost of compliance with these requirements or their effect on our actual operations. Federal Income Tax. Federal income tax laws significantly affect our operations. The principal provisions that affect us are those that permit us, subject tocertain limitations, to deduct as incurred, rather than to capitalize and amortize/depreciate, our domestic “intangible drilling and development costs” and toclaim depletion on a portion of our domestic oil and natural gas properties based on 15% of our oil and natural gas gross income from such properties (up toan aggregate of 1,000 barrels per day of domestic crude oil and/or equivalent units of domestic natural gas). 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, restrictthe types, quantities, and concentration of various substances that can be released into the environment in connection with drilling and production activities,govern the handling and disposal of waste material, and limit or prohibit drilling and exploitation activities on certain lands lying within wilderness,wetlands, and other protected areas, including areas containing threatened or endangered animal species. 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.” 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 theOil and 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, or producedin our operations. Some of this information must be provided to our employees, state and local governmental authorities, and local citizens. We are alsosubject 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 require us toincur costs to remedy discharges. Natural gas, oil or other pollutants, including salt water brine, may be discharged in many ways, including from a well ordrilling 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. 14  A variety of federal and state laws and regulations govern the environmental aspects of natural gas and oil production, transportation and processing. Theselaws and regulations may impose liability in the event of discharges, including for accidental discharges, failure to notify the proper authorities of adischarge, and other noncompliance. Compliance with such laws and regulations may increase the cost of oil and gas exploration, development andproduction; although we do not anticipate that compliance will have a material adverse effect on our capital expenditures or earnings. Failure to complywith the requirements of the applicable laws and regulations could subject us to substantial civil and/or criminal penalties and to the temporary or permanentcurtailment or cessation of all or a portion of our operations. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “superfund law,” imposes liability,regardless of fault or the legality of the original conduct, on some classes of persons that are considered to have contributed to the release of a “hazardoussubstance” into the environment. These persons include the owner or operator of a disposal site or sites where the release occurred and companies thattransport, dispose, or arrange for disposal of the hazardous substance(s) released. Persons who are or were responsible for releases of hazardous substancesunder CERCLA may be jointly and severally liable for the costs of cleaning up the hazardous substances and for damages to natural resources. It is notuncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardoussubstances released into the environment. We could be subject to liability under CERCLA, including for jointly owned drilling and production activitiesthat generate relatively small amounts of liquid and solid waste that may be subject to classification as hazardous substances under CERCLA. The Resource Conservation and Recovery Act of 1976, as amended (“RCRA”) is the principal federal statute governing the treatment, storage and disposal ofsolid and hazardous wastes. RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a“generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility. At present, RCRAincludes an exemption that allows certain oil and natural gas exploration and production waste to be classified as nonhazardous waste. A similar exemptionis contained in many of the state counterparts to RCRA. As a result, we are not required to comply with a substantial portion of RCRA’s hazardous wasterequirements. At various times in the past, proposals have been made to amend RCRA to rescind the exemption that excludes oil and natural gas explorationand production wastes from regulation as hazardous waste. For example, in 2010 a petition was filed by the Natural Resources Defense Council with theEnvironmental Protection Agency (“EPA”) requesting that the agency reassess its prior determination that certain exploration and production wastes are notsubject to the RCRA hazardous waste requirements. EPA has not yet acted on the petition and it remains pending. Repeal or modification of the exemptionby administrative, 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. The Oil Pollution Act of 1990 (“OPA”), and regulations thereunder impose a variety of regulations on “responsible parties” related to the prevention of oilspills and liability for damages resulting from such spills in United States waters. The OPA assigns liability to each responsible party for oil removal costsand a variety of public and private damages, including natural resource damages. While liability limits apply in some circumstances, a party cannot takeadvantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of federal safety, construction oroperating regulations. Few defenses exist to the liability imposed by OPA. In addition, to the extent we acquire offshore leases and those operations affectstate waters, we may be subject to additional state and local clean-up requirements or incur liability under state and local laws. OPA also imposes ongoingrequirements on responsible parties, including proof of financial responsibility to cover at least some costs in a potential spill. We cannot predict whether thefinancial responsibility requirements under the OPA amendments will adversely restrict our proposed operations or impose substantial additional annualcosts to us or otherwise materially adversely affect us. The impact, however, should not be any more adverse to us than it will be to other similarly situatedowners or operators. The Endangered Species Act restricts activities that may affect federally identified endangered and threatened species or their habitats through theimplementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas. Additionally, significant federal decisions, such as theissuance of federal permits or authorizations for certain oil and gas exploration and production activities may be subject to the National EnvironmentalPolicy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major federal agency actions having the potential tosignificantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potentialdirect, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may bemade available for public review and comment. This process has the potential to delay oil and gas development projects. 15  The federal Clean Water Act (the “Clean Water Act”) imposes restrictions and controls on the discharge of produced waters and other oil and natural gaswastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters and to discharge fill and pollutants into regulatedwaters and wetlands. Uncertainty regarding regulatory jurisdiction over wetlands and other regulated waters of the United States has complicated, and willcontinue to complicate and increase the cost of, obtaining such permits or other approvals. Certain state regulations and the general permits issued under theFederal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings andcertain other substances related to the crude oil and natural gas industry into certain coastal and offshore waters. Further, the EPA, has adopted regulationsrequiring certain crude oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated withthe treatment of wastewater or developing and implementing storm water pollution prevention plans. Spill Prevention, Control, and Countermeasurerequirements of the Clean Water Act require appropriate secondary containment loadout controls, piping controls, berms and other measures to help preventthe contamination of navigable waters in the event of a petroleum hydrocarbon spill, rupture or leak. The EPA and U.S. Army Corps of Engineers released aConnectivity Report in September 2013, which determined that virtually all tributary streams, wetlands, open water in floodplains and riparian areas areconnected. This report supported the drafting of proposed rules providing updated standards for what will be considered jurisdictional waters of the UnitedStates. Those rules were finalized on May 27, 2015. Then, on October 9, 2015, in presiding over a challenge to the rules, the U.S. Court of Appeals for theSixth Circuit stayed them, nationwide. The stay remains in place while the Sixth Circuit assesses its jurisdiction to adjudicate the challenge and, if itdetermines that it has such jurisdiction, the merits of the challenge itself. The Clean Water Act and comparable state statutes provide for civil, criminal andadministrative penalties for unauthorized discharges of crude oil and other pollutants and impose liability on parties responsible for those discharges for thecosts of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. We believe that ouroperations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution. The Safe Drinking Water Act of 1974, as amended, establishes a regulatory framework for the underground injection of a variety of wastes, including bringproduced 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. The federal Clean Air Act (the “Clean Air Act”) and comparable state and local air pollution laws adopted to fulfill its mandate provide a framework fornational, state and local efforts to protect air quality. Our operations utilize equipment that emits air pollutants which may be subject to federal and state airpollution control laws. These laws generally require utilization of air emissions control equipment to achieve prescribed emissions limitations and ambientair quality standards, as well as operating permits for existing equipment and construction permits for new and modified equipment. We believe that we arein compliance in all material respects with the requirements of applicable federal and state air pollution control laws. Over the next several years, we may berequired to incur capital expenditures for air pollution control equipment or other air emissions-related issues. The EPA promulgated significant New SourcePerformance Standards (“NSPS OOOO”) in 2012, as amended in 2013 and 2014, which have added administrative and operational costs. On September 18,2015, the EPA published proposed regulations that would 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 gas well sites and compressor stations, wouldbe 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.” 16  Colorado adopted NSPS OOOO in 2014. In addition, Colorado adopted new air regulations for the oil and gas industry effective April 14, 2014, that imposecontrol and other requirements more stringent than NSPS OOOO. These new Colorado oil and natural gas air rules will likely increase our administrative andoperational costs. On October 1, 2015, under the federal 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 increase regulatory burdens in the form of more stringent emission controls, emissionoffset requirements, and increased permitting delays and costs. Along these lines, on September 18, 2015, the EPA proposed 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).Those guidelines would lead to direct regulation of VOC emissions and have the incidental effect of reducing methane emissions. The regulations would takethe form of reasonably available control technology requirements. There are numerous state laws and regulations in the states in which we operate which relate to the environmental aspects of our business. These state lawsand regulations generally relate to requirements to remediate spills of deleterious substances associated with oil and gas activities, the conduct of salt waterdisposal operations, and the methods of plugging and abandonment of oil and gas wells which have been unproductive. Numerous state laws and regulationsalso relate to air and water quality. In 2014, Colorado Governor Hickenlooper created the Task Force on State and Local Regulation of Oil and Gas Operations (“Task Force”) to providerecommendations regarding the state and local regulation of oil and gas operations. The Task Force provided its final recommendations on February 27,2015, which include recommendations for future Colorado rulemakings or legislation to address, among others, local government collaboration with oil andgas operators, operator registration requirements with local governments and submission of operational information for incorporation into localcomprehensive plans, and creation of an oil and gas information clearinghouse. We cannot predict the ultimate outcome of the Task Force’srecommendations. Additionally, the Colorado Oil and Gas Conservation Act (“COGCA”) was amended in 2014 to increase the potential sanctions for violating the COGCA orits implementing regulations, orders, or permits. These amendments increase the maximum penalty per violation per day from $1,000 to $15,000; eliminate a$10,000 maximum penalty for violations that do not result in significant waste of oil and gas resources, damage to correlative rights, or adverse impact topublic health, safety, or welfare; require the Colorado Oil and Gas Conservation Commission (“COGCC”) to assess a penalty for each day there is evidence ofa violation; and authorize the COGCC to prohibit the issuance of new permits and suspend certificates of clearance for egregious violations resulting fromgross negligence or knowing and willful misconduct. In 2015, the COGCC, consistent with the amendments to the COGCA, amended its regulationsgoverning enforcement and penalties. We cannot predict how such regulatory amendments will ultimately affect the penalties assessed by the COGCC infuture enforcement cases involving us. We do not believe that our environmental risks will be materially different from those of comparable companies in the oil and gas industry. We believe ourpresent activities substantially comply, in all material respects, with existing environmental laws and regulations. Nevertheless, we cannot assure you thatenvironmental laws will not result in a curtailment of production or material increase in the cost of production, development or exploration or otherwiseadversely affect our 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. 17  Federal Leases. For those operations on federal oil and gas leases, such operations must comply with numerous regulatory restrictions, including variousnon-discrimination statutes, and certain of such operations must be conducted pursuant to certain on-site security regulations and other permits issued byvarious federal agencies. In addition, on federal lands in the United States, the Office of Natural Resources Revenue (“ONRR”) prescribes or severely limitsthe types of costs that are deductible transportation costs for purposes of royalty valuation of production sold off the lease. In particular, ONRR prohibitsdeduction of costs associated with marketer fees, cash out and other pipeline imbalance penalties, or long-term storage fees. Further, the ONRR has beenengaged in a process of promulgating new rules and procedures for determining the value of crude oil produced from federal lands for purposes of calculatingroyalties owed to the government. The natural gas and crude oil industry as a whole has resisted the proposed rules under an assumption that royalty burdenswill 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 Bureau of Land Management (“BLM”). Theseleases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. In addition to permitsrequired from other regulatory agencies, lessees must obtain a permit from the BLM before drilling and comply with regulations governing, among otherthings, engineering and construction specifications for production facilities, safety procedures, the valuation of production and payment of royalties, theremoval of facilities, and the posting of bonds to ensure that lessee obligations are met. Under certain circumstances, the BLM may require our operations onfederal leases to be suspended 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 review prior toleasing oil and natural gas resources, increased public engagement in the development of master leasing and development plans prior to leasing areas whereintensive new oil and gas development is anticipated, and a comprehensive parcel review process. These changes have increased the amount of time andregulatory costs necessary to obtain oil and gas leases administered by the BLM. In addition, the BLM, on March 20, 2015, issued its final regulations forhydraulic fracturing on federal and tribal lands. The new regulations require, among other things, disclosure of chemicals, annulus pressure monitoring, flowback and produced water management and storage, and more stringent well integrity measures associated with hydraulic fracturing operations on public land.The new regulations become effective on June 24, 2015. BLM has also announced its intention to conduct a separate rulemaking to address venting andflaring 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 waste ofnatural 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, 2015, we had four full-time employees and no part-time employees. For the foreseeable future, we intend to only add additionalpersonnel as our operational requirements grow. In the interim, we plan to continue to leverage the use of independent consultants and contractors to providevarious professional services, including land, legal, engineering, geology, environmental and tax services. We believe that by limiting our management andemployee costs, we are able to better control total costs and retain flexibility in terms of project management. Available Information Our executive offices are located at 216 16th Street, Suite 1350, Denver, Colorado 80202, and our telephone number is (303) 893-9000. Our web site iswww.lilisenergy.com. Additional information that may be obtained through our web site does not constitute part of this Annual Report on Form 10-K. OurAnnual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports are accessible free of chargeat our website. The SEC also maintains an internet site that contains reports, proxy and information statements and other information regarding our filings atwww.sec.gov. 18  ITEM 1A. RISK FACTORS Investing in our shares involves significant risks, including the potential loss of all or part of your investment. These risks could materially affect ourbusiness, financial condition and results of operations and cause a decline in the market price of our shares. You should carefully consider all of the risksdescribed in this Annual Report on Form 10-K, in addition to the other information contained in this Annual Report on Form 10-K, before you make aninvestment in our shares. In addition to other matters identified or described by us from time to time in filings with the SEC, there are several importantfactors that could cause our future results to differ materially from historical results or trends, results anticipated or planned by us, or results that arereflected from time to time in any forward-looking statement. Some of these important factors, but not necessarily all important factors, include thefollowing: Risks Related to the Merger with Brushy Our ability to complete the Merger with Brushy, is subject to various closing conditions, including the approval by our stockholders, and as a result, theclosing of the merger may be delayed or not be completed, which could adversely affect our business operations and stock prices. In order for the merger to be completed, our stockholders must approve and adopt the Merger Agreement and related transaction proposals, which requires theaffirmative vote of the holders of at least a majority of the issued and outstanding shares of our Common Stock. The Merger Agreement also contains otherclosing conditions, which are described in the Merger Agreement. We can provide no assurance that the various closing conditions will be satisfied orwaived. The meeting at which our stockholders will vote on the transactions contemplated by the Merger Agreement may take place before all such conditions havebeen satisfied or waived. As a result, if stockholder approval of the transactions contemplated by the Merger Agreement is obtained at such meeting, we maymake a decision after the meeting to waive a condition or approve certain actions required to satisfy a necessary condition without seeking furtherstockholder approval. Such actions could have an adverse effect on the combined company. If we are unable to complete the Merger, we would be subject to a number of risks, including the following: ●we would not realize the anticipated benefits of the Merger, including, among other things, increased operating efficiencies;●the attention of our management may have been diverted to the Merger rather than to our own operations and the pursuit of other opportunitiesthat could have been beneficial to us;●the potential loss of key personnel during the pendency of the Merger as employees may experience uncertainty about their future roles with thecombined company;●certain costs relating to the Merger, including certain financial advisory, legal and accounting fees and expenses, must be paid even if the Mergeris not closed;●we will have been subject to certain restrictions on the conduct of our business, which may prevent us from making certain acquisitions ordispositions or pursuing certain business opportunities while the Merger is pending; and●the trading price of our Common Stock may decline to the extent that the current market prices reflect a market assumption that the Merger will becompleted. If the Merger is not completed on or before May 30, 2016, either we or Brushy may terminate the Merger Agreement, unless the failure to complete theMerger by that date is due to the failure of the party seeking to terminate the Merger Agreement to fulfill any material obligations under the MergerAgreement or a material breach of the Merger Agreement by such party. We are also required to pay Brushy a termination fee of $1.2 million if we terminatethe Merger under certain circumstances specified in the Merger Agreement. 19  The occurrence of any of these events individually or in combination could have a material adverse effect on our results of operations or the trading price ourCommon Stock. The pendency of the Merger could adversely affect us. We have agreed in the Merger Agreement to refrain from taking certain actions with respect to our business and financial affairs during the pendency of theMerger, which restrictions could be in place for an extended period of time if completion of the Merger is delayed and could adversely our financialcondition, results of operations or cash flows. We will incur significant transaction, merger-related and restructuring costs in connection with the Merger. We expect to incur costs associated with combining the operations of the two companies, as well as transaction fees and other costs related to the Merger. Thecombined company also will incur restructuring and integration costs in connection with the Merger. We are still in the early stages of assessing themagnitude of these costs and additional unanticipated costs may be incurred in the integration of our and Brushy’s businesses. The costs related torestructuring will be expensed as a cost of the ongoing results of operations of either us or Brushy or the combined company. Although we expect that theelimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the businesses, may offset incremental transaction,Merger-related and restructuring costs over time, any net benefit may not be achieved in the near term, or at all. Many of these costs will be borne by us evenif the Merger is not completed. Risks Related to Our Company 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 we may forfeitour 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 revenue afterfield level operating expenses is required to be paid to our lenders as debt service. If we are unable to access additional capital in significant amounts asneeded, we may not be able to develop any of our current or future prospects and properties, may have to forfeit our interest in certain prospects and may nototherwise be able to develop our business. In such an event, we may not be able to continue to operate our business and our common stock and preferredstock may not have any value. Our independent registered public accounting firm has expressed doubt about our ability to continue as a going concern. Our independent registered public accounting firm included an explanatory paragraph in its report on our financial statements included in this AnnualReport on Form 10-K for the fiscal year ended December 31, 2015, describing the existence of substantial doubt about our ability to continue as a goingconcern. Our ability to continue as a going concern is an issue raised as a result of our history of operating losses, along with the recent decrease incommodity prices. Further, we have incurred and expect to continue to incur significant costs in pursuit of our acquisition plans. At December 31, 2015, wehad a negative working capital balance and a cash balance of approximately $15.7 million and $110,000, respectively. Our ability to continue as a goingconcern is subject to our ability to obtain appropriate financing from sources other than our operations. We are currently looking for additional capital,potential Merger candidates, or funding sources which may offer improved opportunities to obtain capital to continue our current operations, further developour properties, acquire oil and gas properties and to cure any current liabilities deficiencies and any potential defaults in connection with our CreditAgreement with Heartland. We are also evaluating asset divestiture opportunities to provide capital to reduce our indebtedness. 20  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. As of March 30, 2016, our total outstanding debt under our Debentures and 12.0% unsecured subordinated convertible notes (“Convertible Notes”), was$6.85 million and $4.25 million, respectively. We currently have a three-year senior secured term loan with an outstanding aggregate principal amount of$2.75 million. We also have a $2.0 million mandatory redeemable preferred stock currently valued at $1.17 million. Our degree of leverage could haveimportant consequences, including the following: ●it may limit our ability to obtain additional debt or equity financing for working capital, capital expenditures, further exploration, debt servicerequirements, acquisitions and general corporate or other purposes; ●a substantial portion of our cash flows from operations will be dedicated to the payment of principal and interest on our indebtedness and will notbe 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; ●as we have pledged most of our oil and natural gas properties and the related equipment, inventory, accounts and proceeds as collateral for theborrowings under our credit facility, they may not be pledged as collateral for other borrowings and would be at risk in the event of a defaultthereunder; ●it may limit our ability to adjust to changing market conditions and place us at a competitive disadvantage compared to our competitors that haveless debt; ●we are vulnerable in the present downturn in general economic conditions and in our business, and we will likely 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 term loan 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 and acquireproperties to the extent desired. A higher level of indebtedness and/or preferred stock increases the risk that we may default on our obligations. Our ability tomeet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, natural gas and oilprices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. Factors thatwill 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 of ourassets, the number of shares of capital stock we have authorized, unissued and unreserved and our performance at the time we need capital. 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 we receive forour 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. 21  Volatile oil and natural gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market foroil and natural gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for andproject 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 gasthat we sell. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Inaddition, we may need to record asset carrying value write-downs if prices fall. A significant decline in the prices of natural gas or oil could adversely affectour financial position, financial results, cash flows, access to capital and ability to grow. We have historically incurred losses and may not achieve future profitability. We have historically incurred losses from operations during our history in the oil and natural gas business. We had a cumulative deficit of approximately$180.9 million and $147.8 million as of December 31, 2015 and 2014, respectively. Many of our properties are in the exploration stage, and to date we haveestablished a limited volume of proved reserves on our properties. Our ability to be profitable in the future will depend on successfully addressing our near-term capital need to refinance our term loan indebtedness and fund our 2016 capital budget, and implementing our acquisition, exploration, developmentand production activities, all of which are subject to many risks beyond our control. Even if we become profitable on an annual basis, our profitability maynot be sustainable or increase on a periodic basis. We have limited management and staff and will be dependent upon partnering arrangements. We had four employees as of March 30, 2016. We leverage the services of independent consultants and contractors to perform various professional services,including engineering, oil and gas well planning and supervision, and land, legal, environmental and tax services. We also pursue alliances with partners inthe areas of geological and geophysical services and prospect generation, evaluation and prospect leasing. Our dependence on third-party consultants andservice 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 and stock pricecould be materially adversely affected. The loss of any of our executive officers could adversely affect us. We are dependent on the experience of our executive officers to guide the implementation of our operational objectives and growth strategy. The loss of theservices of any of these individuals could have a negative impact on our operations and our ability to implement our strategy. Our executive employmentcontracts include long term incentives to retain key personnel but retention of personnel is not guaranteed. 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. A controlsystem, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are beingmet. In addition, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls are evaluated relative totheir costs. Because of the inherent limitations in all control systems, no evaluation of our controls can provide absolute assurance that all control issues andinstances 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 any design maynot succeed in achieving its intended goals under all potential future conditions. Over time, a control may become inadequate because of changes inconditions, or the degree of compliance with its policies or procedures may deteriorate. Because of inherent limitations in a cost-effective control system,misstatements due to error or fraud may occur without detection. 22  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, we are requiredto furnish a report by our management to include in our Annual Report on Form 10-K regarding the effectiveness of our internal control over financialreporting. The report includes, among other things, an assessment of the effectiveness of our internal control over financial reporting as of the end of ourfiscal year, including a statement as to whether or not our internal control over financial reporting is effective. This assessment must include disclosure of anymaterial weaknesses in our internal control over financial reporting identified by management. As of December 31, 2015, management has concluded that our internal control over financial reporting was not effective. We may discover additional areasof our internal control over financial reporting which may require improvement. If we are unable to assert that our internal control over financial reporting iseffective now or in any future period, or if our auditors are unable to express an opinion on the effectiveness of our internal controls, we could lose investorconfidence in the accuracy and completeness of our financial 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 are capitalized into asingle cost center referred to as a full cost pool. These costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling wells, completing productive wells, or plugging and abandoning non-productive wells, costs related to expired leases,or leases underlying producing and non-producing wells, and overhead charges directly related to acquisition and exploration activities. Under the full costmethod of accounting, capitalized oil and natural gas property that comprise the full cost pool, less accumulated depletion and net of deferred income taxes,may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves. Thisceiling test is performed at least quarterly. Should the capitalized costs of the full cost pool exceed this ceiling, we would recognize impairment expense. During the year ended December 31, 2015, we recognized an impairment expense of $24.48 million due to the lower commodity prices and lack of capital todevelop our undeveloped oil and gas properties. As such, we currently have no proved undeveloped reserves. Future write-downs could occur for numerousreasons, including, but not limited to continued reductions in oil and gas prices that lower the estimate of future net revenues from proved oil and natural gasreserves, revisions to reserve estimates, or from the addition of non-productive capitalized costs to the full cost pool that do not result in correspondingincrease in oil and gas reserves. Impairments of plugging and abandonment of wells in progress are other areas where costs may be capitalized into the fullcost pool, without any corresponding increase in reserve values; as such, these situations could result in future additional impairment expenses. If commodity prices stay at current early 2016 levels or decline further, we will 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 will 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. 23  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 contracts thateconomically 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 were torise substantially over the price established by the contract. In addition, such transactions may expose us to the risk of financial loss in certain circumstances,including instances in which: ●there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received; ●our production and/or sales of oil or natural gas are less than expected; ●payments owed under derivative hedging contracts come due prior to receipt of the hedged month’s production revenue; or ●the other party to the hedging contract defaults on its contract obligations. Hedging transactions we may enter into may not adequately protect us from declines in the prices of oil and natural gas. In addition, the counterparties underour derivatives contracts may fail to fulfill their contractual obligations to us. As of December 31, 2015, we had no hedging agreements in place. 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 management resources. Thefailure to continue to upgrade our technical, administrative, operating and financial staff and control systems or the occurrences of unexpected expansiondifficulties, including the failure to recruit and retain experienced managers, geologists, engineers and other professionals in the oil and gas industry couldhave a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan. The actual quantities and present value of our proved reserves may be lower than we have estimated. In addition, the present value of future net cash flowfrom our proved reserves will not necessarily be the same as the current market value of our estimated proved oil and natural gas reserves. This Annual Report on Form 10-K contains estimates of our proved oil and natural gas reserves and the estimated future net revenues from these reserves. Thereserve estimate included in this Annual Report on Form 10-K was prepared by our current reserve engineer consultant, reviewed by our Chief FinancialOfficer and prepared by Forrest Garb. The process of estimating oil and natural gas reserves is complex and requires significant decisions and assumptions inthe evaluation of available geological, geophysical, engineering, cost basis, commodity pricing and economic data for each reservoir. Accordingly, theseestimates are inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development and operating expenses, quantities ofrecoverable oil and natural gas reserves, capital expenditures, infrastructure, taxes and availability of funds most likely will vary from these estimates andvary over time. Such variations may be significant and could materially affect the estimated quantities and present value of our proved reserves. In addition,we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, results of secondary and tertiaryrecovery applications, prevailing oil and natural gas prices and other factors, many of which are beyond our control. You should also not assume that theinitial rates of production of our wells are representative of future overall production from other wells or over the life of the wells, or that early resultssuggesting lack of reservoir continuity will prove to be accurate. You should not assume that the present value of future net cash flow referred to in this Annual Report on Form 10-K is the current market value of ourestimated oil and natural gas reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves aregenerally based on the un-weighted average of the closing prices during the first day of each of the year preceding the end of the fiscal year. Actual futureprices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Any change in global markets consumption by oilor natural gas purchasers or in governmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and theexpenses from the development and production of our oil and natural gas properties will affect the timing of actual future net cash flows from proved reservesand their present value. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows forreporting purposes, is not necessarily the most appropriate discount factor nor does it necessarily reflect discount factors used in the marketplace to assessasset values for the purchase and sale of oil and natural gas. 24  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 we choose topursue an acquisition, we will perform a review of the target properties; however, these reviews are inherently incomplete as they are based on the quality,availability and interpretation of the reviewed data, the acumen and the assumptions of the evaluation personnel. Generally, it is not feasible to review indepth every individual property, well, facility and/or file involved in each acquisition. Even a detailed review of records and properties may not necessarilyreveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies andpotential. We may not perform an inspection on every well, and environmental problems, such as groundwater contamination, are not necessarily observableeven when an inspection is undertaken. Even when problems are identified, we may not be able to obtain effective contractual protection against all or partof those problems, and we may assume environmental and other risks and liabilities in connection with the acquired properties. All of our producing properties and operations are located in the DJ Basin region, making us vulnerable to risks associated with operating in one majorgeographic area. All of our estimated proved reserves at December 31, 2015, and all of our 2015 and 2014 sales were generated in the DJ Basin in southeastern Wyoming,northeastern Colorado and southwestern Nebraska. Although the area is a well-established oilfield infrastructure, as a result, we may be disproportionatelyexposed to the impact of delays or interruptions of production from these wells caused by transportation capacity constraints, curtailment of production,availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closuresfor scheduled maintenance or interruption of transportation of oil or natural gas produced from the wells in this area. In addition, the effect of fluctuations onsupply and demand may become more pronounced within specific geographic oil and gas producing areas such as the DJ Basin, which may cause theseconditions to occur with greater frequency or magnify the effect of these conditions. Due to the concentrated nature of our portfolio of properties, a numberof our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than theymight have 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. 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, rail service,and processing facilities in addition to competing oil and gas production available to third-party purchasers. We deliver crude oil and natural gas producedfrom these areas through trucking, gathering systems and pipelines, some of which we do not own. The lack of availability of capacity on third-party systemsand facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plansfor properties. Although we have some contractual control over the transportation of our production through firm transportation arrangements, third-partysystems and facilities may be temporarily unavailable due to market conditions or mechanical reliability or other reasons, including adverse weatherconditions or work-loads. Activist or other efforts may delay or halt the construction of additional pipelines or facilities. Third-party systems and facilitiesmay 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 affecting theseinfrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities, could delay production, thereby harmingour business and, in turn, our results of operations, cash flows, and financial condition. 25  Our ability to produce crude oil and natural gas economically and in commercial quantities could be impaired if we are unable to acquire adequatesupplies of water for our drilling and completion operations. Drilling and completion activities require the use of water. For example, the hydraulic fracturing process requires the use and disposal of significantquantities of water. In certain areas, there may be insufficient local aquifer capacity to provide a source of water for drilling activities. Water must be obtainedfrom other sources and transported to the drilling site. Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in ouroperations, could adversely impact our operations in certain areas. 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 are locatedoutside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTI or other major market pricing. 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 reservoir characteristicssubsurface and surface pressures and other factors. Thus, our future oil and gas reserves and production and, therefore, our cash flow and revenue are highlydependent on our success in efficiently obtaining additional reserves. We may not be able to develop, find or acquire reserves to replace our current andfuture production at costs or other terms acceptable to us, or at all, in which case our business, financial condition and results of operations would bematerially 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 ourselves 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 fracture stimulate the planned number of stages, being able to run tools the entire length ofthe wellbore during completion operations, proper design and engineering vs. reservoir parameters, and successfully cleaning out the wellbore aftercompletion of the final fracture stimulation stage. Our experience with horizontal well applications utilizing the latest drilling and completion techniques specifically in the Niobrara and/or Codell formationsis limited; however, we contract local experts in the area to design, plan and conduct our drilling and completion operations. Ultimately, the success of thesedrilling and completion techniques can only be developed over time as more wells are drilled and production profiles are established over a sufficiently longtime period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations,access to gathering systems and limited takeaway capacity or otherwise, and/or natural gas and oil prices decline, the return on our investment in these areasmay not be as attractive as we anticipate and we could incur material write-downs of undeveloped properties and the value of our undeveloped acreage coulddecline in the future. 26  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. During theseperiods, the costs of and demand for rigs, equipment and supplies may increase substantially and their availability may be limited. In addition, the demandfor, and wage rates of, qualified personnel, including drilling rig crews, may rise as the number of rigs in service increases. The higher prices of oil and gasduring 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. If we are unable to comply with the significant restrictions and covenants in our Credit Agreement and our Forbearance Agreement, there could be adefault under the terms of either agreement, which could result in an acceleration of payment of borrowings and would impact our ability to maintain ourcurrent operations. Pursuant to our Credit Agreement, we are subject to both non-financial and financial covenants. Our Credit Agreement contains a number of non-financialcovenants imposing significant restrictions on us, including the maximum monthly payment requirement, restrictions on our repurchase of, and payment ofdividends on, our capital stock and limitations on our ability to incur additional indebtedness, make investments, engage in transactions with affiliates, sellassets and create liens on our assets. These restrictions may affect our ability to operate our business, to take advantage of potential business opportunities asthey arise and, in turn, may materially and adversely affect our business, financial conditions and results of operations. The financial covenants, include maintaining a debt to EBITDAX ratio. EBITDAX is defined in the Credit Agreement as earnings before the pre-tax netincome for such period plus (without duplication and only to the extent deducted in determining such net income), interest expense for such period,depreciation and amortization expense, extraordinary or non-recurring items reducing net income for such period, and other non-cash expenses for suchperiod less gains on sales of assets and other non-cash income for such period included in the determination of net income plus (without duplication and onlyto the extent deducted in determining such net income) exploration, drilling and completion expenses or costs (EBITDAX). Specifically, the ratio requiresthat we maintain at all times, as determined on June 30 of each year, a ratio of (i) the aggregate amount of all debt, to (ii) EBITDAX of not less than 4.5:1,3.5:1 and 2.5:1 for the periods ending June 30, 2015, 2016, and 2017 and thereafter, respectively. We are also required to maintain, as determined on June 30of each year beginning June 30, 2015, a debt coverage ratio of not less than 1.0 to 1.0. Covenant restrictions may prevent us from taking actions that we believe would be in the best interest of our business, may require us to sell assets or takeother actions to reduce indebtedness to meet our covenants, and may make it difficult for us to successfully execute our business strategy or effectivelycompete with companies that are not similarly restricted. As a result of the current price environment and our depleting asset base, we were not able and it is possible that we will continue to be unable to meet thedebt to EBITDAX and the debt coverage ratios required in the future periods, including June 30, 2016. Furthermore, a default under the Credit Agreement,constitutes an event of default pursuant to the Debentures which could result in an acceleration of the Company’s obligations at the Debenture holders’election. We received a waiver for the June 30, 2015 period and currently have a Forbearance Agreement with Heartland. The Forbearance Agreement restrictsHeartland from exercising any of its remedies until April 30, 2016 and is subject to certain conditions, including a requirement for us to make a monthlyinterest payment to Heartland. On April 1, 2016, we failed to make the required interest payment to Heartland for the month of March. As a result, Heartlandhas the right to declare an event of default under the Forbearance Agreement, terminate the remaining commitment and accelerate payment of all principaland interest outstanding. We have not yet received a notice of default and are currently in discussions with Heartland with respect to the missed interestpayment. However, we cannot assure you that these discussions will be successful or that in the event Heartland declares an event of default, whether withrespect to the missed interest payment or a breach of any other covenant, that we will be granted a further forbearance, waiver, extension or amendment.Moreover, our Debentures also contain certain cross-default provisions with certain other debt instruments. Therefore, a default under the Credit Agreement,constitutes an event of default pursuant to the Debentures which may result in an acceleration of our obligations at the holders’ election. 27  We could be required to pay liquidated damages to some of our investors due to our failure to maintain the effectiveness of a prior registration statement. We could accrue liquidated damages under registration rights agreements covering a significant amount of shares of Common Stock if our investors declare adefault, due to our failure to maintain the effectiveness of a prior registration statement as required in the agreements. In such case, we could be required topay monthly liquidated damages. If we do not make a monthly payment within seven days after the date payable, we are required to pay interest at an annualrate of 18% on the unpaid amount. If our investors declare a default under the registration rights agreement and accrue liquidated damages, we could berequired to either raise additional outside funds through financing or curtail operations. 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 therisks 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 leaks, ruptures or discharges of toxic gases, brine or well fluids into the environment(including groundwater contamination). These events may result in substantial losses to us 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 not carrybusiness 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 from mechanicalfailures, contract terms, pipeline and processing plant interruptions, market conditions, operator priorities, and weather conditions, etc. and weatherconditions. These curtailments can last from a few days to many months, any of which could have an adverse effect on our 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 or cancellation ofcustomer orders, impeding processing of transactions and reporting financial results, resulting in the unintentional disclosure of customer, employee or ourinformation, or damage to our reputation. There can be no assurance that a system failure or data security breach will not have a material adverse effect on ourfinancial condition, results of operations or cash flows. 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 of producingproperties 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 costs; ●regulatory constraints and plans; and ●potential environmental and other liabilities. 28  The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties. Our reviewwill not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies andpotential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable evenwhen an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protectionagainst all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “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. 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 geological information, to beindications of commercial oil or natural gas. Our prospects are in various stages of evaluation, ranging from a prospect that is ready to be drilled to a prospectthat will require substantial additional technical assessment, data acquisition and/or seismic data processing and interpretation. There is no definitivemethod to predict in advance of drilling and testing and wider-scale development whether any particular prospect will yield oil or natural gas in sufficientquantities to be economically viable. The use of reservoir, geologic and seismic data and other technologies and the study of producing fields in the samearea will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be presentin commercial quantities. The analysis we perform using data from other wells, more fully explored prospects or producing fields may not be useful inpredicting the characteristics and potential reserves associated with our drilling prospects. Risks Relating to the Oil and Gas Industry 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 oil andnatural 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 ●knowledgeable personnel to conduct all phases of oil and natural gas operations. 29  We must compete for such resources with both major oil and natural gas companies and independent operators. Virtually all of these competitors havefinancial 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 a number of adverse consequences, including: ●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; ●inability to attract capital; ●a general slowdown in our operations and decline in revenue; and ●decline in market price of our common shares. 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, regulatoryagencies and other governmental entities. As a result, we may face significant opposition to, or increased regulation of, our operations that may make itdifficult or impossible to obtain permits and other needed authorizations to drill, complete or operate, result in operational delays, or otherwise make oil andgas exploration more costly or difficult than in other countries. 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 public healthand 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 has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existingprovisions of the Clean Air Act. The EPA recently adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, one of whichrequires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain largestationary sources. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sourcesin the United States on an annual basis, including petroleum refineries, as well as certain onshore oil and natural gas production facilities. Also, on September 18, 2015, EPA published proposed regulations that would build on the NSPS OOOO standards by directly regulating methane and VOCemissions from various types of new and modified oil and gas sources. Some of those sources are already regulated under NSPS OOOO, while others, likehydraulically fractured oil wells, pneumatic pumps, and certain equipment and components at gas well sites and compressor stations, would be covered forthe first time. On March 10, 2016, moreover, the EPA announced that it is moving towards issuing performance standards for methane emissions fromexisting oil and gas sources. The agency said that it will “begin with a formal process (i.e., an Information Collection Request) to require companiesoperating existing oil and gas sources to provide information to assist in the development of comprehensive regulations to reduce methane emissions.” 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. EPA likewise said that, in the future, it will “further revise the PSD and Title V regulations ina separate rulemaking to fully implement” the Utility Air Regulatory Group judgment. The judgment does not prevent states from considering and adoptingstate-only major source permitting requirements based solely on GHG emission levels. 30  In addition, the U.S. Congress has from time to time considered adopting legislation to reduce GHG emissions and almost one-half of the states have alreadytaken legal measures to reduce GHG emissions, primarily through the planned development of GHG emission inventories and/or regional GHG cap and tradeprograms. Most of these GHG cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels,such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced eachyear in an effort to achieve the overall GHG emission reduction goal. The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase andoperate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation orregulatory 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 has asserted federalregulatory authority over certain hydraulic fracturing activities involving diesel fuel under the federal Safe Drinking Water Act (“SDWA”). In addition,legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of thechemicals used in the hydraulic fracturing process. Under the proposed legislation, this information would be available to the public via the internet, whichcould make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals usedin the fracturing process could adversely affect groundwater. As discussed above, the BLM, on March 20, 2015, issued its final regulations for hydraulicfracturing on federal and tribal lands. The new regulations require, among other things, disclosure of chemicals, annulus pressure monitoring, flow back andproduced water management and storage, and more stringent well integrity measures associated with hydraulic fracturing operations on public land. The newregulations become effective on June 24, 2015. In addition, on April 7, 2015, EPA proposed a rule under the Clean Water Act that would prohibit thedischarge of oil and gas wastewaters to publicly-owned treatment works. The EPA intends to propose regulations in 2015 under the federal Clean Water Act to develop standards for wastewater discharges from hydraulic fracturingand other natural gas production activities. At the state level, some states have adopted, and other states are considering adopting legal requirements thatcould impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. Some counties in Colorado,for instance, have amended their land use regulations to impose new requirements on oil and gas development, while other local governments have enteredmemoranda of agreement with oil and gas producers to accomplish the same objective. Beyond that, in 2012, Longmont, Colorado prohibited the use ofhydraulic fracturing. The oil and gas industry filed a lawsuit challenging that ban in court. The industry prevailed on summary judgment against Longmontand the environmental intervenors. That decision is currently on appeal. In November 2013, four other Colorado cities and counties passed voter initiativeseither placing a moratorium on hydraulic fracturing or banning new oil and gas development. These initiatives too are the subject of pending legal challengeor appeal. 31  While these state and local land use initiatives cover areas with little recent or ongoing oil and gas development, they could lead opponents of hydraulicfracturing to push for statewide referendums, especially in Colorado. If new or more stringent federal, state, or local legal restrictions relating to the hydraulicfracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experiencedelays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices and a committee of theU.S. House of Representatives has conducted an investigation of hydraulic fracturing practices. Furthermore, a number of federal agencies are analyzing, orhave been requested to review, environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmentaleffects 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, saidthat shale development has not led to “widespread, systemic” problems with groundwater. The final version of the study is pending. These ongoing studies,depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA orother regulatory mechanisms. The EPA has also issued an advance notice of proposed rulemaking and initiated a public participation process under the Toxic Substances Control Act toseek comment on the information that should be reported or disclosed for hydraulic fracturing chemical substances and mixtures and the mechanisms forobtaining this information. Additionally, on January 7, 2015, several national environmental advocacy groups filed a lawsuit requesting that the EPA add theoil and gas extraction industry to the list of industries required to report releases of certain “toxic chemicals” under the Emergency Planning and CommunityRight-to-Know Act’s Toxics Release Inventory (“TRI”) program. On October 22, 2015, the EPA took action on the Environmental Integrity Project’s October24, 2012 petition to impose TRI reporting requirements on various oil and gas facilities. The EPA granted the petition in part, by proposing to add naturalgas processing facilities to the scope of the TRI program, but rejected the rest of the petition. On December 15, 2015, in light of that decision, theenvironmental advocacy groups that had commenced the lawsuit opted to voluntarily dismiss it. We are subject to numerous laws and regulations that can adversely affect the cost, manner or feasibility of doing business. Our operations are subject to extensive federal, state and local laws and regulations relating to the exploration, production and sale of oil and natural gas, andoperating safety. Future laws or regulations, any adverse change in the interpretation of existing laws and regulations or our failure to comply with existinglegal requirements may result in substantial penalties and harm to our business, results of operations and financial condition. We may be required to makelarge 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. 32  Our operations could be significantly delayed or curtailed and our cost of operations could significantly increase as a result of regulatory requirements orrestrictions. It is also possible that a portion of our oil and gas properties could be subject to eminent domain proceedings or other government takings forwhich we may not be adequately compensated. See “Business and Properties—Government Regulations” for a more detailed description of regulatory lawscovering 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 materials into theenvironment or otherwise relating to environmental protection. These laws and regulations: ●require the acquisition of a permit before drilling or facility mobilization and commissioning, or injection or disposal commences; ●restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and productionand processing activities, including new environmental regulations governing the withdrawal, storage and use of surface water or groundwaternecessary 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. Changes in environmental laws and regulations occur frequently and any changes that result in more stringent or costly waste handling, storage, transport,disposal or cleanup requirements could require us to make significant expenditures to reach and maintain compliance and may otherwise have a materialadverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Under these environmental lawsand regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless ofwhether we were responsible for the release or contamination or if our operations met previous standards in the industry at the time they were performed. Ourpermits require that we report any incidents that cause or could cause environmental damages. See “Business and Properties—Government Regulations” for amore detailed description of the environmental laws covering our business. Risks Relating to Our Common Stock There is a limited public market for our shares and an active trading market or a specific share price may notbe established or maintained. Our Common Stock currently trades on the Nasdaq Capital Market (“Nasdaq”), generally in small volumes each day. The value of our Common Stock couldbe 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. 33  In a volatile market, you may experience wide fluctuations in the market price of our Common Stock. These fluctuations may have an extremely negativeeffect on the market price of our Common Stock and may prevent you from obtaining a market price equal to your purchase price when you attempt to sellour 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 tohold 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 Common Stock as consideration. Failure to comply with Nasdaq continued listing requirements, even after the proposed Stock Split, could adversely affect the liquidity of our CommonStock. We do not currently satisfy the minimum bid price requirement for continued listing on Nasdaq, as set forth in Nasdaq Listing Rule 5450(a)(1). In order toregain compliance, the minimum bid price per share of our Common Stock would needed to have been at least $1.00 for a minimum of ten consecutivebusiness days prior to March 21, 2016. On January 21, 2016, we presented its case for an extension at a hearing before the Nasdaq Hearings panel (the“Panel”) in connection with the above as well as its failure to comply with the requirement of Nasdaq Listing Rule 5450(b)(1)(A), relating to the minimumstockholder’s equity requirements and requested a transfer to the Nasdaq Capital Market. On February 9, 2016, we were notified that the Panel haddetermined to grant our request to transfer the listing of our Common Stock from the Nasdaq Global Market to the Nasdaq Capital Market, effective February11, 2016. Our continued listing on the Nasdaq Capital Market is subject to certain conditions, including our compliance with the applicable $2.5 millionstockholders’ equity requirement and our continued compliance with all other applicable requirements for continued listing on that market by no later thanMay 23, 2016. If we fail to regain compliance during this grace period, or the Panel does not grant us a further extension, our Common Stock will be delisted. Delistingcould adversely affect the liquidity of our Common Stock. We have notified Nasdaq of our intention to cure the minimum bid price deficiency during thegrace period by effecting a reverse stock split (the “Stock Split”) in connection with the proposed Merger to regain compliance. However, the Stock Split, ifapproved by our stockholders, may not sufficiently increase our stock price and have the desired effect of maintaining compliance with Nasdaq ListingRules. The liquidity of our Common Stock may even be harmed by the Stock Split due to the reduced number of shares that would be outstanding after theStock Split, particularly if the stock price does not increase as a result of the action. For more information on the proposed merger with Brushy see “Businessand Properties—Pending Merger with Brushy Resources, Inc.”, and the notes to our financial statements. If Nasdaq determines not to continue our listing, trading of our Common Stock most likely occur in the over-the-counter market on an electronic bulletinboard established for unlisted securities such as the OTC Bulletin Board or OTC Markets Group Inc. (formerly known as Pink OTC Markets Inc.). Suchtrading this could have significant material adverse consequences on us, including: ●we would be in violation of a closing condition and may be considered to be in breach of the Merger Agreement; ●reduced liquidity with respect to our shares; ●a determination that our Common Stock is a “penny stock” which will require brokers trading in Lilis shares to adhere to more stringent rules,possibly resulting in a reduced level of trading activity in the secondary trading market for our shares; ●a limited amount of news and analyst coverage for us resulting in potential difficulty to dispose of, or obtain accurate quotations for the price ofour Common Stock; and ●a decreased ability to issue additional securities or obtain additional financing in the future. 34  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 more disclosuresby broker-dealers and satisfaction of other administrative requirements. As a result, broker-dealers may be less willing to execute transactions in securitiessubject 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 market value ofour stock. Sales of a substantial number of shares of our Common Stock, or the perception that such sales might occur, could have an adverse effect on the price ofour Common Stock. As of December 31, 2015, six investors each hold more than 5% beneficial ownership of our Common Stock, and together, hold beneficial ownership ofapproximately 77.63% of our Common Stock. Thus, any sales by our large investors of a substantial number of shares of our Common Stock into the publicmarket, or the perception that such sales might occur, could have an adverse effect on the price of our Common Stock. We may issue shares of preferred stock with greater rights than our Common Stock. Our articles of incorporation authorize our board of directors to issue one or more series of preferred stock and set the terms of the preferred stock withoutseeking any further approval from our stockholders. Any preferred stock that is issued may rank ahead of our Common Stock, in terms of dividends,liquidation rights and voting rights. We currently have 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. For example, inconnection with the Merger and related transactions: (i) the conversion of our Debentures at a conversion price of $0.50 would result in an the issuance of13,692,930 shares of our Common Stock, (ii) the conversion of our Series A Preferred Stock at a conversion price of $0.50 would result in the issuance of15,000,000 shares of our Common Stock, (iii) the conversion of the Convertible Notes at a conversion price of $0.50 and exercise of the warrants at anexercise price of $0.25 would result in the issuance of 25,000,000 million shares of our Common Stock, each pursuant to the receipt of requisite stockholderapproval. To the extent outstanding restricted stock units, warrants or options to purchase our Common Stock under our employee and director stock optionplans are exercised, the price vesting triggers under the performance shares granted to our executive officers are satisfied, or additional shares of restrictedstock are issued to our employees, holders of our Common Stock will experience dilution. Furthermore, if we sell additional equity or convertible debtsecurities, such sales could result in further dilution to our existing stockholders and cause the price of our outstanding securities to decline. We do not expect to pay dividends on our Common Stock. We have never paid dividends with respect to our Common Stock, and we do not expect to pay any dividends, in cash or otherwise, in the foreseeable future.We intend to retain any earnings for use in our business. In addition, our Credit 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 stockholders 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 may adverselyaffect the trading price of our shares. The trading market for our shares will rely in part on the research and reports that securities analysts publish about usand our business. If one or more of the analysts who cover our company downgrades our shares, the trading price of our shares may decline. If one or more ofthese 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. 35  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. In the opinion of management, our liability, if any, inthese pending actions would not have a material adverse effect on our financial position. Our general and administrative expenses would include amountsincurred to resolve claims made against us. Parker v. Tracinda Corp., Denver District Court, Case No. 2011CV561. In November 2012, we filed a motion to intervene in garnishment proceedingsinvolving Roger Parker, our former Chief Executive Officer and Chairman. The Defendant, Tracinda Corp. (“Tracinda”), served us various writs ofgarnishment to enforce a judgment against Mr. Parker seeking, among other things, shares of unvested restricted stock. We asserted rights to lawful set-offsand deductions in connection with certain tax consequences, which may be material to us. The underlying judgment against Mr. Parker was appealed to theColorado Court of Appeals and, by Order dated October 17, 2013, that Court reversed the trial court with respect to Mr. Parker’s claims of waiver, estoppeland mitigation of damages and remanded with instruction to enter judgment for Mr. Parker. The Court of Appeals also ordered the trial court to conductfurther proceedings to determine the amount of damages to award Mr. Parker on his breach of contract claim. The trial court conducted a later hearing andfound in its Findings of Fact, Conclusions of Law and Order dated January 9, 2015, in favor of Mr. Parker on his claim for breach of contract, awarding him$6,981,302.60. Tracinda’s Motion for Amendment of the Court’s January 9 Findings and Conclusions was the subject of an Order dated April 10, 2015, inwhich the Court set off the award in favor of Mr. Parker against the award in favor of Tracinda, resulting in judgment in favor of Tracinda and against Mr.Parker in the amount of $625,572.10. On April 16, 2015, Tracinda filed a Notice of Appeal in the Colorado Court of Appeals, appealing both the January 9Order and the April 10 Order. On May 18, 2015, Parker filed a Notice of Cross-Appeal in the Colorado Court of Appeals, cross-appealing both the January 9Order and the April 10 Order. The record is in the process of being certified. The filing of the record will trigger the parties’ briefing schedule. In re Roger A. Parker: Tracinda Corp. v. Recovery Energy, Inc. and Roger A. Parker, United States Bankruptcy Court for the District of Colorado, Case No.13-10897-EEB. On June 10, 2013, Tracinda filed a complaint (Adversary No. 13-011301 EEB) against us and Roger Parker in connection with the personalbankruptcy proceedings of Roger Parker, alleging that we improperly failed to remit to Tracinda certain property in connection with a writ of garnishmentissued by the Denver District Court (discussed above). We filed an answer to this complaint on July 10, 2013. A trial date has not been set and, by Order datedFebruary 2, 2015, the Bankruptcy Court ordered that the Adversary Proceeding be held in abeyance pending final resolution of the state-court action(2011CV561). We are unable to predict the timing and outcome of this matter. Lilis Energy, Inc. v. Great Western Operating Company LLC, Eighth Judicial District Court for Clark County, Nevada, Case No. A-15-714879-B. On March 6,2015, we filed a lawsuit against Great Western Operating Company, LLC (the “Operator”). The dispute related to our interest in certain producing wells andthe Operator’s assertion that our interest was reduced and/or eliminated as a result of a default or a farm-out agreement. Underlying the dispute is the jointoperating agreement (“JOA”) which provides the parties with various rights and obligations. In its complaint, we sought monetary damages and declaratoryrelief on claims of breach of contract, breach of the implied covenant of good faith and fair dealing, tortious breach of the implied covenant of good faith andfair dealing, unjust enrichment, conversion and declaratory judgment related to the JOA. The Operator filed a motion to dismiss on May 26, 2015 and weresponded by filing an opposition motion on June 12, 2015. On July 7, 2015, as previously reported, we entered into a Settlement Agreement (the “Settlement Agreement”) with the Operator. Due to our inability tosecure financing pursuant to the Credit Agreement or another funding source, payment was not remanded to the Operator and the dispute remained unsettled. During the year ended December 31, 2015, we were put in non-consent status. As such, the previously capitalized and accrued costs of approximately $5.20million relating to these wells were eliminated as being placed in non-consent status relieved us of such liabilities. We have retained the right to participatein future drilling on this acreage block. We believe there is no other litigation pending that could have, individually or in the aggregate, a material adverse effect on our results of operations orfinancial condition. Item 4.MINE SAFETY DISCLOSURES Not applicable. 36  PART II Item 5.MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITYSECURITIES Recent Market Prices On November 2, 2011 our Common Stock began trading on the Nasdaq Global Market under the symbol “RECV.” Between September 25, 2009 andNovember 1, 2011 our stock traded on the OTC Bulletin Board under the symbol “RECV.OB.” On December 1, 2013, in connection with our name changesour Common Stock began trading on the Nasdaq Global Market under the symbol “LLEX.” On February 11, 2016, our Common Stock was transferred andbegan trading, at the request of the Company, to the Nasdaq Capital Market. The following table shows the high and low reported sales prices of our Common Stock for the periods indicated. High Low 2015 Fourth Quarter $0.70 0.07 Third Quarter $3.15 0.48 Second Quarter $1.90 0.74 First Quarter $1.26 0.60 2014 Fourth Quarter $2.20 $0.62 Third Quarter $2.48 $1.02 Second Quarter $3.30 $1.73 First Quarter $3.58 $2.06 On March 30, 2016, there were 89 owners of record of our Common 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 current businessplan is to retain any future earnings to finance the expansion and development of our business. Any future determination to pay cash dividends will be at thediscretion of our Board of Directors, and will be dependent upon our financial condition, results of operations, capital requirements and other factors as ourboard may deem relevant at that time. In addition, we are currently restricted from declaring any dividends pursuant to the terms of our preferred stock andour instruments evidencing indebtedness. 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, 2015. Item 6.SELECTED FINANCIAL DATA Not applicable. 37  Item 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion should be read in conjunction with our financial statements included in Part IV of this Annual Report on Form 10-K. Thisdiscussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated inthese forward-looking statements as a result of various factors including those set forth under Part I “Item 1A. Risk Factors.” General We are an upstream independent oil and gas company engaged in the acquisition, drilling and production of oil and natural gas properties and prospects. Our current operating activities are focused on the DJ Basin in Colorado, Wyoming and Nebraska. We have acquired and developed a producing base of oiland natural gas proved reserves, as well as a portfolio of exploration and other undeveloped assets with conventional and non-conventional reservoiropportunities, with an emphasis on those with multiple producing horizons, in particular the Muddy “J” conventional reservoirs and the Niobrara shale andCodell resource plays. We believe these assets offer the possibility of repeatable year-over-year success and significant and cost-effective production andreserve growth. Our acquisition, development and exploration pursuits are principally directed at oil and natural gas properties in North America. As of December 31, 2015 we owned interests in 8 economically producing wells and 16,000 net leasehold acres, of which 8,000 net acres are classified asundeveloped acreage and all of which are located in Colorado, Wyoming and Nebraska within the DJ Basin. We are primarily focused on acquiringcompanies and production throughout North America and developing our North and South Wattenberg Field assets, which include attractive unconventionalreservoir drilling opportunities in mature development areas with low risk Niobrara and Codell formation productive potential. 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 our success.The 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 causing 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. Upon entering into the Credit Agreement, we believed we had secured adequate access to capital generally, and specifically, to fund the drilling anddevelopment of our proved undeveloped reserves. Due to the lack of liquidity that had been expected, but unavailable to us pursuant to the CreditAgreement, we recorded a full impairment of our proved undeveloped and unproved properties during the year ended December 31, 2015. Our financial statements for the years ended December 31, 2015 have been prepared on a going concern basis. We have incurred net operating losses for thepast five years. This history of operating losses, along with the recent decrease in commodity prices, may adversely affect our ability to access capital we needto continue operations. These factors raise substantial doubt about our ability to continue as a going concern. The accompanying financial statements do notinclude any adjustments relating to the recoverability and classification of recorded asset amounts, or amounts of liabilities, that might result from thisuncertainty. We will need to raise additional funds to finance continuing operations. However, we may not be successful in doing so. Without sufficient additionalfinancing, it would be unlikely for us to continue as a going concern. Our ability to continue as a going concern is dependent upon our ability to successfullyaccomplish our business plan and eventually secure other sources of financing and attain profitable operations. 38  Results of Operations Year ended December 31, 2015 compared to the year ended December 31, 2014 The following table compares operating data for the fiscal year ended December 31, 2015 to December 31, 2014: Year EndedDecember 31, 2015 2014 Revenue: Oil sales $292,332 $2,581,689 Gas sales 77,068 364,732 Operating fees 26,664 182,773 Realized gain (loss) on commodity price derivatives - 11,143 Total revenue 396,064 3,140,337 Costs and expenses: Production costs 195,435 954,347 Production taxes 27,917 269,823 General and administrative 7,929,628 10,325,842 Depreciation, depletion and amortization 584,203 1,337,662 Impairment of evaluated oil and gas properties 24,478,378 - Total costs and expenses 33,215,561 12,887,675 Loss from operations before conveyance (32,819,497) (9,747,338)Loss on conveyance of oil and gas properties - (2,269,760)Loss from operations (32,819,497) (12,017,098) Other income (expenses): Other income 3,160 32,444 Inducement expense - (6,661,275)Change in fair value of convertible debentures conversion derivative liability 1,243,931 (5,526,945)Change in fair value of warrant liability 394,383 571,228 Change in fair value of conditionally redeemable 6% Preferred stock 513,585 - Interest expense (1,696,899) (4,837,025)Net Loss $(32,361,337) $(28,438,671) 39  Total Revenue On September 2, 2014, we entered into a final settlement agreement (the “Final Settlement Agreement”) to convey our interest in 31,725 evaluated andunevaluated net acres located in the DJ Basin and the associated oil and natural gas (“Hexagon Collateral”), to our former primary lender, Hexagon, LLC(“Hexagon”), in exchange for extinguishment of all outstanding debt and accrued interest obligations owed to Hexagon in an aggregate amount ofapproximately $15.1 million. The conveyance assigned all assets and liabilities associated with the property, which includes PDP and PUD reserves,plugging and abandonment, and other assets and liabilities associated with the property. Pursuant to the Final Settlement Agreement, we also issued toHexagon $2.0 million in 6% Conditionally Redeemable Preferred Stock valued at $1.69 million and considered as temporary equity for reporting purposes. Total revenue was $396,000 for the year ended December 31, 2015, compared to $3.14 million for the year ended December 31, 2014, a decrease of $2.7million, or 87%. The decrease in revenue was primarily due to the reduction in oil and gas revenue associated with 32,000 acres and 17 operated wells weconveyed to Hexagon pursuant to the Final Settlement Agreement and the reduction in commodity prices during the year. During the year ended December 31, 2015 and 2014, production amounts were 12,449 and 46,500 BOE, respectively, a decrease of 34,051 BOE, or 73%. Inaddition to the conveyance, production declined due to certain operated wells shut in for workovers and non-payments to vendors. The following table shows a comparison of production volumes and average prices: For the Year EndedDecember 31, 2015 2014 Product Oil (Bbl.) 7,067 33,508 Oil (Bbls)-average price (1) $41.36 $77.05 Natural Gas (MCFE)-volume 32,291 77,954 Natural Gas (MCFE)-average price (2) $2.39 $4.68 Barrels of oil equivalent (BOE) 12,449 46,500 Average daily net production (BOE) 34 127 Average Price per BOE (1) $29.67 $63.36 (1)Does not include the realized price effects of hedges.(2)Includes proceeds from the sale of NGL’s. Oil and gas production costs, production taxes, depreciation, depletion, and amortization Production costs per BOE 15.70 20.52 Production taxes per BOE 2.24 5.80 Depreciation, depletion, and amortization per BOE 46.93 28.76 Total operating costs per BOE (1) $64.87 $55.08 Gross margin per BOE (1) $(35.20) $8.28 Gross margin percentage (119)% 13% (1)Does not include the loss on conveyance. Commodity Price Derivative Activities Changes in the market price of oil can significantly affect our profitability and cash flow. In the past we have entered into various commodity derivativeinstruments to mitigate the risk associated with downward fluctuations in oil prices. These derivative instruments consisted exclusively of swaps. Theduration and size of our various derivative instruments varies, and depends on our view of market conditions, available contract prices and our operatingstrategy. As of December 31, 2015, we did not maintain any active commodity swaps. During 2014, we held one commodity swap which matured on January 31, 2014.Commodity price derivative realized a gain of $11,000 during the year ended December 31, 2014. 40  Production Costs Production costs were $195,000 for the year ended December 31, 2015, compared to $954,000 for the year ended December 31, 2014, a decrease of $759,000,or 80%. The decrease was due to the conveyance of 32,000 acres and 17 operated wells to Hexagon discussed above and certain operated wells shut in duringthe year. Production costs per BOE decreased to $15.70 for the year ended December 31, 2015 from $20.52 in 2014, a decrease of $4.80 per BOE, or 23%,primarily the result of reduced service costs realized in lower commodity environment. Production Taxes Production taxes were $28,000 for the year ended December 31, 2015, compared to $270,000 for the year ended December 31, 2014, a decrease of $242,000,or 90%. Currently, ad valorem, severance and conservation taxes range from 1% to 13% based on the state and county from which production isderived. Production taxes per BOE decreased to $2.24 during the year ended December 31, 2015 from $5.80 in 2014, a decrease of $3.56 or 61%. General and Administrative Expenses General and administrative expenses were $7.93 million during the year ended December 31, 2015, compared to $10.33 million during the year endedDecember 31, 2014, a decrease of $2.40 million, or 23%. Included in general and administrative expenses for the year ended December 31, 2015 were $3.45million of stock-based compensation expense compared to $3.43 million of stock-based compensation expenses during the year ended December 31,2014. The decrease in general and administrative expenses was largely attributed to a $1.0 million lump sum payment paid to Abraham “Avi” Mirman in2014 as a one-time bonus related to achievement of capital raising milestones and a decrease in professional fees incurred in 2014 relating to multiplefinancings and a conveyance of properties to Hexagon offset by increased compensation relating to additional employees along with higher contract servicesin 2015. Depreciation, Depletion, and Amortization Depreciation, depletion, and amortization were $584,000 during the year ended December 31, 2015, compared to $1.34 million during the year endedDecember 31, 2014, a decrease of $754,000, or 56%. Decrease in depreciation, depletion, and amortization was the result of the conveyance of properties toHexagon, lowering the depletion pool and a decrease in production amounts in 2015 from 2014. Impairment of Evaluated Oil and Gas Properties Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceedan 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 cost ofunproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are notsubject to amortization. Should capitalized costs exceed this ceiling, an impairment expense is recognized. During the year ended December 31, 2015, the lower commodity prices and lack of capital to develop its undeveloped oil and gas properties caused us torecognize an impairment expense of $24.48 million. We did not recognize any impairment expense during 2014. Inducement Expense In January 2014, we incurred an inducement expense of $6.66 million. We entered into an initial conversion agreement with all of the holders of ourDebentures (“Initial Conversion Agreement”). Under the terms of the Initial Conversion Agreement, $9.0 million of the approximately $15.6 million inDebentures then outstanding were converted into our Common Stock at a price of $2.00 per share. As an inducement, we issued warrants to purchase oneshare of our Common Stock, at an exercise price equal to $2.50 per share (“Initial Conversion Warrants”), to the converting Debenture holders, for each shareof our Common Stock issued upon conversion of the Debentures. We used the Lattice model to value the Initial Conversion Warrants, utilizing a volatility of65%, and a life of 3 years, which resulted in a fair value of $6.66 million for the Initial Conversion Warrants. 41  Loss on Conveyance of Oil and Gas Properties On September 2, 2014, we entered into the Final Settlement Agreement to settle all amounts payable by us pursuant to the then existing credit agreementswith Hexagon (described above). The transaction was accounted for under the full cost method of accounting for oil and natural gas operations. Under the fullcost method, sales or abandonments of oil and natural gas properties, whether or not being amortized, are accounted for as adjustments of capitalized costs,with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil andgas attributable to the cost center. The transfer to Hexagon represented greater than 25% of our proved reserves of oil and gas attributable to the full cost pooland thus we incurred a loss on the conveyance. Following this methodology, the following table represents an allocation of the transaction. Payment of debt and accrued interest payable $15,063,289 Add: disposition of asset retirement obligations 973,132 Total disposition of liabilities $16,036,421 Proved oil and natural gas properties $32,574,603 Accumulated depletion (22,148,686)Unproved oil and natural gas properties 6,194,162 Redeemable Preferred Stock at fair value 1,686,102 Total conveyance of assets and preferred stock 18,306,181 Loss on conveyance $(2,269,760) Interest Expense For the years ended December 31, 2015 and 2014, we incurred interest expense of approximately $1.70 million and $4.84 million, respectively, of whichapproximately $131,000 and $2.43 million is classified as non-cash interest expense in 2015 and 2014, respectively. The details of the non-cash interestexpense for the year ended December 31, 2015 were the amortization of the deferred financing costs of $125,000, and accrued interest to convertibledebenture of $7,000. The details of the non-cash interest expense for the year ended December 31, 2014 are as follows: (i) Hexagon non-payment penalty of$1 million, (ii) amortization of the deferred financing costs of $235,000, (iii) accretion of the Debentures payable discount of $849,000, (iv) Common Stockissued for interest of $1.19 million, (v) accrued interest to convertible debenture of $7,000, and (vi) amortization of forbearance fees of $250,000. Change in Bristol Warrant Liability On September 2, 2014 we entered into a Consulting Agreement with Bristol Capital, LLC (“Bristol”), pursuant to which we issued to Bristol a warrant topurchase up to 1,000,000 shares of our Common Stock at an exercise price of $2.00 per share (or, in the alternative, 1,000,000 options, but in no case both).The agreement has a price protection feature that will automatically reduce the exercise price if we enter into another consulting agreement pursuant to whichwarrants are issued with a lower exercise price. The change in fair value of this warrant provision was $350,000 and $571,000 for the years ended December31, 2015 and 2014, respectively. Change in Credit Agreement Warrant Liability On January 8, 2015, we entered into the Credit Agreement. In connection with the Credit Agreement, we issued to Heartland a warrant to purchase up to225,000 shares of our Common Stock at an exercise price of $2.50 with the initial advance, which contains an anti-dilution feature that will automaticallyreduce the exercise price if we enter into another agreement pursuant to which warrants are issued with a lower exercise price. The change in fair valuevaluation from issuance was $12,000 for the year ended December 31, 2015. 42  Change in Derivative Liability of Debentures For the years ended December 31, 2015 and 2014, we incurred a change in the fair value of the derivative liability related to the Debentures of approximately$1.24 million and $(5.53) million respectively. During the year ended December 31, 2014, we reduced the conversion price from $4.25 to $2.00, consistentwith the exercise price of the warrants issued in our private placement in January 2014. The conversion resulted in a reduction of the convertible debentureliability by $5.69 million and an increase in additional paid in capital. Liquidity and Capital Resources Information about our year-end financial position is presented in the following table (in thousands): Year endedDecember 31, 2015 2014 Financial Position Summary Cash and cash equivalents $110 $510 Working capital (deficit) $(15,695) $(6,560)Balance outstanding on convertible debentures, convertible notes payable and term loan $11,317 $6,840 Stockholders’ equity $(14,344) $14,067 As discussed above, our financial statements for the years ended December 31, 2015 have been prepared on a going concern basis. As of December 31, 2015,we had a negative working capital balance and a cash balance of approximately $15.7 million and $110,000, respectively. As of March 30, 2016, our cashbalance was approximately $50,000. We have historically financed our operations through the sale of debt and equity securities and borrowings under creditfacilities with financial institutions. The following is a description of our indebtedness: Debentures As of December 31, 2015, we had $6.85 million aggregate principal amount outstanding under our Debentures. On December 29, 2015, we entered into an agreement with the holders of our Debentures, which provides for the full automatic conversion of Debentures intoshares of our Common Stock at a price of $0.50 per share, upon the receipt of requisite stockholder approval and the consummation of the Merger. If theDebentures are converted on these terms, it would result in the issuance of 13,692,930 shares of our Common Stock and the elimination of $8.08 million inshort-term debt obligations including accrued but unpaid interest which would be forfeited and cancelled upon conversion pursuant to the terms of theagreement. Credit Agreement On January 8, 2015, we entered into the Credit Agreement with Heartland. The Credit Agreement provides for a three-year senior secured term loan in aninitial aggregate principal amount of $3,000,000 (“Term Loan”), which principal amount may be increased to a maximum principal amount of $50,000,000pursuant to an accordion advance provision in the Credit Agreement subject to certain conditions, including the discretion of the lender. Funds borrowedunder the Credit Agreement may be used to (i) purchase oil and gas assets, (ii) fund certain lender-approved development projects, (iii) fund a debt servicereserve account, (iv) pay all costs and expenses arising in connection with the negotiation and execution of the Credit Agreement, and (v) fund our generalworking capital needs. 43  The Term Loan bears interest at a rate calculated based upon our leverage ratio and the “prime rate” then in effect. We also paid a nonrefundable commitmentfee in the amount of $75,000, and agreed to issue to the lenders warrants to purchase 75,000 shares of our Common Stock for every $1 million funded. Aninitial warrant to purchase up to 225,000 shares of our Common Stock at $2.50 per share was issued at the closing. As of January 8, 2015, we valued thewarrants at $56,000, which was accounted for as debt discount and amortized over the life of the debt. We accreted $18,000 of debt discount for the yearended December 31, 2015. The Credit Agreement contains certain customary representations and warranties and affirmative and negative covenants. The Credit Agreement also containsfinancial covenants with respect to our (i) debt to EBITDAX ratio and (ii) debt coverage ratio. In addition, in certain situations, the Credit Agreement requiresmandatory prepayments of the Term Loan, including in the event of certain non-ordinary course asset sales, the incurrence of certain debt, and our receipt ofproceeds in connection with insurance claims. In addition, Heartland has a first priority security interest in all of our assets. As of June 30, 2015 and September 30, 2015, we were not in compliance with the financial covenant in the Credit Agreement that relates to the total debt toEBITDAX ratio. EBITDAX is defined in the Credit Agreement as earnings before the pre-tax net income for such period plus (without duplication and only tothe extent deducted in determining such net income), interest expense for such period, depreciation and amortization expense, extraordinary or non-recurringitems reducing net income for such period, and other non-cash expenses for such period less gains on sales of assets and other non-cash income for suchperiod included in the determination of net income plus (without duplication and only to the extent deducted in determining such net income) exploration,drilling and completion expenses or costs (EBITDAX). Specifically, the ratio requires that we maintain at all times, as determined on June 30 of each year, aratio of (i) the aggregate amount of all debt, to (ii) EBITDAX of not less than 4.5:1, 3.5:1 and 2.5:1 for the periods ending June 30, 2015, 2016, and 2017 andthereafter, respectively. We are also required to maintain, as determined on June 30 of each year beginning June 30, 2015, a debt coverage ratio of not lessthan 1.0 to 1.0. We received a waiver from Heartland for this covenant violation, which will not be measured again until June 30, 2016. On December 29, 2015, after a default on an interest payment and in connection with the merger transactions, we entered into the Forbearance Agreementwith Heartland. The Forbearance Agreement restricts Heartland from exercising any of its remedies until April 30, 2016 and is subject to certain conditions,including a requirement for us to make a monthly interest payment to Heartland. On April 1, 2016, we failed to make the required interest payment toHeartland for the month of March. As a result, Heartland has the right to declare an event of default under the Forbearance Agreement, terminate theremaining commitment and accelerate payment of all principal and interest outstanding. We have not yet received a notice of default and are currently indiscussions with Heartland with respect to the missed interest payment. However, we cannot assure you that these discussions will be successful or that in theevent Heartland declares an event of default, whether with respect to the missed interest payment or a breach of any other covenant, that we will be granted afurther forbearance, waiver, extension or amendment. Moreover, our Debentures also contain certain cross-default provisions with certain other debtinstruments. Therefore, a default under the Credit Agreement, constitutes an event of default pursuant to the Debentures which may result in an accelerationof our obligations at the holders’ election. We do not expect to receive any additional capital pursuant to the existing Credit Agreement. We are in the process of evaluating alternatives to address ourdefault under the Forbearance Agreement, including seeking other capital and funding sources. If we are unable to raise significant capital or otherwiserenegotiate the terms of the Forbearance Agreement with Heartland, we will be in default under the Credit Agreement in which case Heartland could exerciseany remedies available to it, including initiating foreclosure procedures on all of our assets. Convertible Notes From December 29, 2015 to January 5, 2016, we entered into 12% Convertible Subordinated Note Purchase Agreements with various lending parties, whichwe refer to as the Purchasers, for the issuance of an aggregate principal amount of $3.75 million Convertible Notes, which includes the $750,002 of short-termnotes exchanged for Convertible Notes by us and warrants to purchase up to an aggregate of approximately 15,000,000 shares of our Common Stock at anexercise price of $0.25 per share. The proceeds from this financing were used to pay a $2 million refundable deposit in connection with the Merger, to fundapproximately $1.3 million of interest payments to our lenders and for our working capital and accounts payables. The Convertible Notes bear interest at a rate of 12% per annum, payable at maturity on June 30, 2016. The Convertible Notes and accrued but unpaid interestthereon are convertible in whole or in part from time to time at the option of the holders thereof into shares of our Common Stock at a conversion price of$0.50. The Convertible Notes may be prepaid in whole or in part (but with payment of accrued interest to the date of prepayment) at any time at a premium of103% for the first 120 days and a premium of 105% thereafter, so long as no senior debt is outstanding. The Convertible Notes contain customary events ofdefault, which, if uncured, entitle each noteholder to accelerate the due date of the unpaid principal amount of, and all accrued and unpaid interest, subject tocertain subordination provisions. Additionally, on March 18, 2016, we issued an additional aggregate principal amount of $500,000 of Convertible Notes, which have the terms andconditions as the Convertible Notes with the exception of the maturity date, which is April 1, 2017. The proceeds from these Convertible Notes were used tomake advances to Brushy for payment of operating expenses pending completion of the Merger. If the Merger is not completed, these amounts are subject torepayment by Brushy. Our financial statements for the years ended December 31, 2015 have been prepared on a going concern basis. We have incurred net operating losses for thepast five years. This history of operating losses, along with the recent decrease in commodity prices, may adversely affect our ability to access capital we needto continue operations. These factors raise substantial doubt about our ability to continue as a going concern. The accompanying financial statements do notinclude any adjustments relating to the recoverability and classification of recorded asset amounts, or amounts of liabilities, that might result from thisuncertainty. We will need to raise additional funds to finance continuing operations. However, we may not be successful in doing so. Without sufficient additionalfinancing, it would be unlikely for us to continue as a going concern. Our ability to continue as a going concern is dependent upon our ability to successfullyaccomplish our business plan and eventually secure other sources of financing and attain profitable operations. 44  Development and Production During the year ended December 31, 2015, we transferred $847,000 from wells-in progress to developed oil and natural gas properties. This includedapproximately $491,000 from a well currently producing in Northern Wattenberg and approximately $356,000 of cost incurred for projects that we no longerplan to pursue. During the year ended December 31, 2015, we entered into five joint operating agreements to participate as a non-operator in the drilling of five horizontalwells. We have an average of 2.78% working interest in each of these wells which are being drilled by reliable companies. However, due to capitalconstraints, we expect that we will be put into non-consent status on each of these wells unless other arrangements can be made.Additionally, as of March 30, 2016, we were producing approximately 20 BOE a day from eight economically producing wells. Due to a decline incommodity prices, the cash generated from our production activity is not sufficient to pay our operating costs and we do not have sufficient cash to continueoperations in the ordinary course. Proposed Merger with Brushy Resources, Inc. On December 29, 2015, we entered into the Merger Agreement, which is described in more detail under “Business and Properties—Pending Merger withBrushy Resources, Inc.” Among other conditions to the Merger, we are required to repay our Term Loan in full, convert the $6.85 million outstanding underour Debentures into our Common Stock at $0.50 and convert $7.5 million of our outstanding Series A Preferred Stock into our Common Stock at $0.50. Inaddition, Brushy will have to repay, refinance or negotiate alternative terms with its senior lender prior to completing the Merger. We have agreed to use ourbest efforts to assist Brushy with this process by possibly purchasing all or a portion of Brushy’s outstanding senior debt. We believe that if the Merger is successfully completed, we will substantially increase our producing properties resulting in significantly greater cash flowwhile eliminating or refinancing our existing indebtedness. We will however be required to obtain significant additional capital to pay outstanding debtobligations, pay professional fees related to the Merger, pay outstanding payables in the ordinary course and to fund the combined company’s workingcapital requirements. While we expect to raise additional capital to fund all of these obligations, the current volatility in the commodity markets has made itdifficult for oil and gas exploration companies, including ours, to access debt or equity financing or obtain borrowings from financial lenders. If we are unable to complete the Merger or otherwise obtain significant capital, we will likely not be able to continue our current operations and would haveto consider other alternatives to preserve value for our stockholders. These alternatives could include engaging in discussions to acquire other producingproperties, selling or disposing of some or all of our assets or a liquidation of our business. 45  Cash Flows Cash used in operating activities during the year ended December 31, 2015 was $3.81 million. Cash used in operating activities combined with the $1.85million used in investing activities offset by the $5.25 million provided by financing activities, resulted in a decrease in cash of $400,000 during the year. The following table compares cash flow items during the year ended December 31, 2015 to December 31, 2014 (in thousands): Year endedDecember 31, 2015 2014 Cash provided by (used in): Operating activities $(3,805) $(7,306)Investing activities (1,848) (507)Financing activities 5,254 8,157 Net change in cash $(400) $344 During the year ended December 31, 2015, net cash used in operating activities was $3.81 million, compared to $7.31 million during the year endedDecember 31, 2014, a decrease of cash used in operating activities of $3.5 million, or 49%. The primary changes in operating cash during the year endedDecember 31, 2015 was from a reduction of oil and gas revenues and our inability to raise additional capital to fund and pay for our operations. Additionally,we added a new Chief Financial Officer and General Counsel increasing salaries by $470,000, paid $343,000 for the due diligence of a potential acquisitionwhich was not completed, $250,000 for additional investment banking firms, $650,000 in additional legal fees and approximately $670,000 of otherprofessional fees for acquisitions and additional support during the year. During the year ended December 31, 2015, net cash used in investing activities was $1.85 million, compared to net cash used in investing activity of$507,000 during the year ended December 31, 2014, an increase of cash used in investing activities of $1.3 million, or 264%. On December 30, 2015, wepaid $1.75 million towards the required $2.0 million deposit relating to the proposed merger with Brushy described above. During 2014, we invested$496,000 of cost associated with acquisition of undeveloped leaseholds and development of assets throughout Wattenberg. During the year ended December 31, 2015, net cash provided by financing activities was $5.3 million, compared to net cash provided by financing activitiesof $8.16 million during the year ended December 31, 2014, an increase of $2.9 million, or 36%. In 2015, we received $5.95 million in debt proceeds, $3.0million in Term Loan proceeds from Heartland and $2.95 million in convertible bridge note funding relating to the proposed merger with Brushy. In 2014,we received cash proceeds of $12.0 million from two private placements offset by the repayment of debt of $3.7 million and dividend payments of $162,000. 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 GAAP requires our management to make assumptions and estimates that affectthe reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities at the date of our financialstatements and the reported amounts of revenues and expenses during the reporting period. The following is a summary of the significant accountingpolicies and related estimates that affect our financial disclosures. Critical accounting policies are defined as those significant accounting policies that are most critical to an understanding of a company’s financial conditionand results of operation. We consider an accounting estimate or judgment to be critical if (i) it requires assumptions to be made that were uncertain at the timethe estimate was made, and (ii) changes in the estimate or different estimates that could have been selected could have a material impact on our results ofoperations or financial condition. 46  Recently Issued Accounting Pronouncements Various accounting standards updates are issued, most of which represented technical corrections to the accounting literature or were applicable to specificindustries, are not expected to have a material impact on our condensed financial position and, results of operations. Use of Estimates The financial statements included herein were prepared from our records in accordance with GAAP, and reflect all normal recurring adjustments which are, inthe opinion of management, necessary to provide a fair statement of the results of operations and financial position for the interim periods. The preparationof the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gasreserves, assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenuesand expenses during the reporting period. We evaluate our estimates on an on-going basis and base our estimates on historical experience and on variousother assumptions we believe to be reasonable under the circumstances. Although actual results may differ from these estimates under different assumptionsor conditions, we believe that our estimates are reasonable. The preparation of financial statements in conformity with GAAP requires us to make a number of estimates and assumptions relating to the reported amountsof assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues andexpenses during the reporting period. Actual results could differ significantly from those estimates. Management evaluates estimates and assumptions on anongoing basis using historical experience and other factors, including the current economic and commodity price environment. Our most significant financial estimates are associated with our estimated proved oil and gas reserves, assessments of impairment imbedded in the carryingvalue of undeveloped acreage and proven properties, as well as the valuation of our Common Stock, options and warrants, and estimated derivativeliabilities. 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 to theacquisition 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 gasreserve estimates as of December 31, 2015, using the average, first-day-of-the-month price during the 12-month period ended December 31, 2015. Estimating accumulations of gas and oil is complex and is not exact because of the numerous uncertainties inherent in the process. The process relies oninterpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. Theprocess also requires certain economic assumptions, some of which are mandated by the SEC, such as gas and oil prices, drilling and operating expenses,capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of the quality and quantity of available data; theinterpretation of that data; the accuracy of various mandated economic assumptions; and the judgment of the persons preparing the estimate. 47  We believe estimated reserve quantities and the related estimates of future net cash flows are among the most important estimates made by an exploration andproduction company such as ours because they affect the perceived value of our company, are used in comparative financial analysis ratios, and are used asthe basis for the most significant accounting estimates in our financial statements, including the quarterly calculation of depletion, depreciation andimpairment of our proved oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas, and naturalgas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs underexisting economic and operating conditions. We determine anticipated future cash inflows and future production and development costs by applyingbenchmark prices and costs, including transportation, quality and basis differentials, in effect at the end of each quarter to the estimated quantities of oil andnatural gas remaining to be produced as of the end of that quarter. We reduce expected cash flows to present value using a discount rate that depends uponthe purpose for which the reserve estimates will be used. For example, the standardized measure calculation requires us to apply a 10% discountrate. Although reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than those ofestablished proved producing oil and natural gas properties, we make considerable effort to estimate our reserves, including through the use of independentreserves engineering consultants. We expect that quarterly reserve estimates will change in the future as additional information becomes available or as oiland natural gas prices and operating and capital costs change. We evaluate and estimate our oil and natural gas reserves as of December 31 and quarterlythroughout the year. For purposes of depletion, depreciation, and impairment, we adjust reserve quantities at all quarterly periods for the estimated impact ofacquisitions and dispositions. Changes in depletion, depreciation or impairment calculations caused by changes in reserve quantities or net cash flows arerecorded in the period in which the reserves or net cash flow estimate changes. Oil and Natural Gas Properties—Full Cost Method of Accounting We use the full cost method of accounting whereby all costs related to the acquisition and development of oil and natural gas properties are capitalized into asingle cost center referred to as a full cost pool. These costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition and exploration activities. Capitalized costs, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimatedgross proved reserves as determined by independent petroleum engineers. For this purpose, we convert our petroleum products and reserves to a common unitof measure. Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. This undeveloped acreage is assessed quarterly toascertain whether impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or theamount 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 would alter therate of depletion by more than 25%. Royalties paid, net of any tax credits received, are netted against oil and natural gas sales. In applying the full cost method, we perform a ceiling test on properties that restricts the capitalized costs, less accumulated depletion, from exceeding anamount equal to the estimated undiscounted value of future net revenues from proved oil and natural gas reserves, as determined by independent petroleumengineers. The estimated future revenues are based on sales prices achievable under existing contracts and posted average reference prices in effect at the endof the applicable period, and current costs, and after deducting estimated future general and administrative expenses, production related expenses, financingcosts, future site restoration costs and income taxes. Under the full cost method of accounting, capitalized oil and natural gas property costs, lessaccumulated depletion and net of deferred income taxes, may not exceed an amount equal to the present value, discounted at 10%, of estimated future netrevenues from proved oil and natural gas reserves, plus the cost, or estimated fair value if lower, of unproved properties. Should capitalized costs exceed thisceiling, we would recognize impairment. Revenue Recognition We derive revenue primarily from the sale of produced natural gas and crude oil. We report revenue as the gross amount received before taking into accountproduction taxes and transportation costs, which are reported as separate expenses and are included in oil and gas production expense in the accompanyingconsolidated statements of operations. Revenue is recorded in the month our production is delivered to the purchaser, but payment is generally receivedbetween 30 and 90 days after the date of production. No revenue is recognized unless it is determined that title to the product has transferred to thepurchaser. At the end of each month, we eliminate the amount of production delivered to the purchaser and the price we will receive. We use our knowledgeof our properties, its historical performance, NYMEX and local spot market prices, quality and transportation differentials, and other factors as the basis forthese estimates. 48  Share Based Compensation We account for share-based compensation by estimating the fair value of share-based payment awards made to employees and directors, including stockoptions, restricted stock units, restricted stock, and employee stock purchases related to employee stock purchase plans, on the date of grant using an option-pricing model. The value of the portion of the award that is ultimately expected to vest is recognized as an expense ratably over the requisite serviceperiods. Derivative Instruments Periodically in the past, we have entered into swaps to reduce the effect of price changes on a portion of our future oil production. We reflect the fair marketvalue of our derivative instruments on our balance sheet. Our estimates of fair value are determined by obtaining independent market quotes as well asutilizing a valuation model that is based upon underlying forward curve data and risk free interest rates. Changes in commodity prices will result insubstantially similar changes in the fair value of our commodity derivative agreements. We do not apply hedge accounting to any of our derivativecontracts, therefore we recognize mark-to-market gains and losses in earnings currently. Item 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Not applicable. Item 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Our financial statements appear immediately after the signature page of this Annual Report on Form 10-K. See “Index to Financial Statements” included inthis Annual Report on Form 10-K. Item 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE On November 7, 2014, we were notified by our independent registered public accounting firm, Hein & Associates LLP (“Hein”) that it did not wish to standfor re-election. On November 25, 2014, we engaged Marcum LLP (“Marcum”) as our independent registered public accounting firm, which was approved byour Board of Directors and on December 10, 2015, the Board of Directors approved Marcum to continue as the Company’s independent registered publicaccounting firm. The reports of Hein for our consolidated financial statements as of and for the fiscal year ended December 31, 2013 did not contain anadverse opinion or disclaimer of opinion and were not qualified or modified as to uncertainty, audit scope, or accounting principles. During the fiscal yearended December 31, 2013 and up until its date of resignation, there were no disagreements between us and Hein on any matter of accounting principles orpractices, financial statement disclosures, or auditing scope or procedures, which disagreements, if not resolved to the satisfaction of Hein would have causedthem to make reference thereto in their reports on our financial statements for such years. For more information on the change in accountants, please see ourCurrent Reports on Form 8-K filed with the SEC on November 13, 2014 and December 2, 2014. Item 9A.CONTROLS AND PROCEDURES Evaluation of Disclosure Controls and Procedures Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controlsand procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (“Exchange Act”)) as of theend of the period covered by this Annual Report on Form 10-K. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer haveconcluded that, as of the end of the period covered by this Annual Report on Form 10-K, our disclosure controls and procedures were not effective to ensurethat information required to be disclosed in reports filed under the Exchange Act is recorded, processed, summarized and reported within the required timeperiods and is accumulated and communicated to our management, including our Chief Executive Officer, as appropriate to allow timely decisions regardingrequired disclosure. 49  Management’s Report on Internal Control over Financial Reporting Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability offinancial reporting and the preparation of financial statements in accordance with GAAP. Because of its inherent limitations, internal control over financialreporting may not prevent or detect misstatements. Also, projection of any evaluation of effectiveness to future periods is subject to the risk that controls maybecome inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. As of December 31, 2015, we assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control overfinancial reporting conducted based on the Internal Control—Integrated Framework issued by COSO (2013) and SEC guidance on conducting suchassessments. In connection with management’s assessment of our internal control over financial reporting, we concluded that, as of December 31, 2015, ourinternal controls and procedures were not effective to detect the inappropriate application of GAAP as more fully described below. The matters involving internal controls and procedures that our management considered to be material weaknesses under the standards of the PublicCompany Accounting Oversight Board were: (1) while we have implemented written policies and procedures for accounting and financial reporting withrespect to the requirements and application of GAAP and SEC disclosure requirements, due to limited resources, we have not conducted a formal assessmentof whether the policies that have been implemented address the specific risks of misstatement; accordingly, we could not conclude whether the controlactivities are designed effectively nor whether they operate effectively, and (2) we do not have a fully effective mechanism for monitoring the system ofinternal controls. A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatementof the annual or interim financial statements will not be prevented or detected. Management believes that the material weaknesses set forth above did nothave a material adverse effect on our financial results for the year ended December 31, 2015. We are committed to improving our financial organization. Our control weaknesses are largely a function of not having sufficient staff. As resources becomeavailable, we plan to augment our staff so that we can devote more effort to addressing our control deficiencies. Additionally, as financial resources becomeavailable, we have been engaging third-party consultants to assist with control activities. We will continue to monitor and evaluate the effectiveness of our internal control over financial reporting on an ongoing basis and are committed to takingfurther action by implementing additional enhancements or improvements, or deploying additional human resources as may be deemed necessary. Changes in Internal Control over Financial Reporting There were no changes in our internal control over financial reporting during our most recent fiscal quarter that materially affected, or were reasonably likelyto materially affect, our internal control over financial reporting. Item 9B. OTHER INFORMATION None. 50  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 30, 2016: Name Age PositionAbraham “Avi” Mirman 46 Chief Executive Officer, DirectorRonald D. Ormand 57 Chairman of the Board of DirectorsNuno Brandolini 62 DirectorR. Glenn Dawson 59 DirectorGeneral Merrill McPeak 79 DirectorKevin K. Nanke 51 Executive Vice President and Chief Financial OfficerAriella Fuchs 34 General Counsel and Secretary Abraham Mirman: Chief Executive Officer, Director. Mr. Mirman joined our Board of Directors (the “Board” or the “Board of Directors”) on September 12,2014. He currently serves as our Chief Executive Officer and has held that position since April 21, 2014. Prior to being appointed to his current position ofChief Executive Officer, Mr. Mirman served as our President beginning in September 2013. During that same time, from April 2013 until September 2014,Mr. Mirman served as the Managing Director, Investment Banking at T.R. Winston & Company, LLC (“TRW”). Between 2012 and February 2013, Mr.Mirman served as Head of Investment Banking at John Thomas Financial. From 2011 to 2012, Mr. Mirman served as Head of Investment Banking at BMASecurities. Lastly, from 2006 to 2011, Mr. Mirman served as Chairman of the Board of Cresta Capital Strategies LLC. During Mr. Mirman’s service as ChiefExecutive Officer, we have completed several significant capital raising transactions and negotiated a final settlement with its senior secured lender. 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 at TRW. ●Industry Experience – Personal investment in oil and gas industry, and experience as executive officer of Lilis Energy, Inc. Ronald D. Ormand: Chairman of the Board of Directors. Mr. Ormand joined our Board of Directors in February, 2015, bringing with him more than 33years of experience as a senior executive and investment banker in energy, including extensive financing and mergers and acquisitions expertise in the oiland gas industry. During his career, he has completed more than $25 billion of capital markets and financial advisory transactions, both as a principal and asa banker. He is currently the Chairman and Head of Energy Investment Banking Group at MLV & Co. (“MLV”), which is now FBR & Co., after it acquiredMLV in September of 2015, where he focuses on investment banking and principal investments in the energy sector. Prior to joining MLV in November2013, from 2009 to 2013 he was a senior executive at Magnum Hunter Resources Corporation (“MHR”) (NYSE:MHR), an exploration and productioncompany engaged in unconventional resource plays, as well as midstream and oilfield services operations. He was part of the management team that tookover prior management and grew MHR from approximately $35 million enterprise value to over $2.5 billion enterprise value at the time he left in 2013. Mr.Ormand served on the Board of Directors and in several senior management positions for MHR, including Executive Vice President, Chief Financial Officerand Executive Vice President of Capital Markets. On March 10, 2016, in connection with his prior position as Chief Financial Officer of MHR, Mr. Ormand,without admitting or denying any of the allegations, settled with the SEC in connection with an investigation of MHR’s books and records and internalcontrols 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 ExchangeAct 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-fraud violations, intentionalmisrepresentations or willful conduct on the part of Mr. Ormand. Mr. Ormand’s career includes serving as Managing Director and Group Head of U.S. Oil andGas Investment Banking at CIBC World Markets and Oppenheimer (1988-2004); Head Of North American Oil and Gas Investment Banking at West LB A.G.(2005-2007), and President and CFO of Tremisis Energy Acquisition Corp. II, an energy special purpose acquisition company from 2007-2009. Mr. Ormandhas previously served as a Director of Greenhunter Resources, Inc. (2011-2013), Tremisis (2007-2009), and Eureka Hunter Holdings, Inc., a private midstreamcompany (2010-2013). Mr. Ormand holds a B.A. in Economics, an M.B.A. in Finance and Accounting from UCLA and studied Economics at CambridgeUniversity, England. 51  Director Qualifications: ● Leadership Experience – Chairman, Head of Energy Investment Banking Group at MLV; Senior executive at Magnum Hunter ResourcesCorporation 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 of ScorpionCapital Partners, L.P., a private equity firm organized as a small business investment company until June 2014. Prior to forming Scorpion Capital and itspredecessor firm, Scorpion Holding, Inc., in 1995, Mr. Brandolini served as managing director of Rosecliff, Inc., a leveraged buyout fund co-founded by Mr.Brandolini in 1993. Mr. Brandolini served previously as a vice president in the investment banking department of Salomon Brothers, Inc., and a principalwith the Batheus Group and Logic Capital, two venture capital firms. Mr. Brandolini began his career as an investment banker with Lazard Freres & Co. Mr.Brandolini is a director of Cheniere Energy, Inc. (NYSE MKT: LNG), a Houston-based company primarily engaged in LNG related businesses. Mr. Brandolinireceived a law degree from the University of Paris and an M.B.A. from the Wharton School. 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 and gasexploration 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 VelvetExploration Ltd. in July 2000. Mr. Dawson was a co-founder and Vice President of Exploration of TriLoch Resources Inc., a then-public Canadian oil and gasexploration company, from 2001 to 2005, until it was acquired by Enerplus Resources Fund. As a result of the sale of TriLoch Resources Inc. to EnerplusResources Fund, Mr. Dawson founded NuLoch Resources, Inc. in 2005. Mr. Dawson graduated in 1980 from Weber State University of Utah with a Bachelor’sdegree in Geology and attended the University of Calgary from 1980 to 1982 in the Masters Program for Geology. As a result of these professionalexperiences, Mr. Dawson possesses particular knowledge and experience in the operations of oil and gas companies that strengthen the Board’s collectivequalifications, skills, and experience. 52  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 the U.S. AirForce and flew 269 combat missions in Vietnam during his distinguished 37-year military career. Following retirement from active service in 1994, GeneralMcPeak launched a second career in business. He was a founding investor and chairman of Ethicspoint, an ethics and compliance software and servicescompany, which was subsequently restyled as industry leader Navex Global, and acquired in 2011 by a private equity firm. General McPeak co-invested andremained a board member of NAVEX Global, which was sold again in 2014. From 2012 to 2014, General McPeak was Chairman of Coast Plating, Inc., a LosAngeles-based, privately held provider of metal processing and finishing services, primarily to the aerospace industry, which was also acquired in a privateequity buyout. He remains a director of that company, now called Valence Surface Technologies. He also currently serves as a director of DGT Holdings,GenCorp, Lion Biotechnologies and Research Solutions, Inc. Formerly, he was a director of Tektronix, TWA and ECC International, a defense subcontractor,where he served for many years as chairman of the Board. 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. Kevin K. Nanke: Executive Vice President and Chief Financial Officer. On March 6, 2015, our Board appointed Kevin Nanke to the position of ExecutiveVice President and Chief Financial Officer, effective immediately. Mr. Nanke served as the President of KN Consulting, Inc., a consulting firm focused on theenergy, real estate and restaurant industries, from 2012 to 2015. Previously, Mr. Nanke served as the Treasurer and Chief Financial Officer of Delta PetroleumCorporation (“Delta”) from 1999 to 2012, and as its Controller from 1995 to 1999. At the same time, Mr. Nanke served as Treasurer and Chief FinancialOfficer of Amber Resources, an E&P subsidiary of Delta, and as Treasurer, Chief Financial Officer and Director of DHS Drilling Company, a drilling companythat was 50% owned by Delta. He was instrumental in preserving a $1.3 billion tax loss carryforward when Delta successfully completed a reorganization andemerged as Par Petroleum Corporation after Delta and its subsidiaries filed voluntary petitions under Chapter 11 of the U.S. Bankruptcy Code in December of2011. Prior to joining Delta, Mr. Nanke was employed by KPMG LLP, a global audit, tax and advisory firm. Mr. Nanke received a B.A. in Accounting fromthe University of Northern Iowa in 1989 and is a Certified Public Accountant (inactive). Ariella Fuchs: General Counsel and Secretary. Ariella Fuchs joined our company in March 2015. Prior to that, Ms. Fuchs was an associate with Baker BottsL.L.P. from April 2013 to February 2015, specializing in securities transactions and corporate governance. Prior to joining Baker Botts L.L.P, she served as anassociate at White & Case LLP and Dewey and LeBoeuf LLP from January 2010 to March 2013 in their mergers and acquisitions groups. Ms. Fuchs receiveda J.D. from New York Law School and a B.A. in Political Science from Tufts University. Directors hold office for a period of one year from their election at the annual meeting of stockholders and until a particular director’s successor is dulyelected and qualified. Officers are elected by, and serve at the discretion of, our Board of Directors. None of the above individuals has any family relationshipwith any other. It is expected that our Board of Directors will elect officers annually following each annual meeting of stockholders. 53  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, disclosing theamount 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 2015, except as follows: ●Abraham “Avi” Mirman filed one Form 4, reporting one transaction late. ●Nuno Brandolini filed one Form 4 reporting one transaction late. ●General Merrill McPeak filed one Form 4 reporting three transactions late. ●Kevin K. Nanke filed one Form 4 reporting one transaction late and a Form 3 reporting his initial beneficial ownership late. ●Ariella S. Fuchs filed one Form 4 reporting one transaction late and a Form 3 reporting her initial beneficial ownership late. ●Eric Ulwelling filed one Form 4 reporting one transaction late. ●Tyler G. Runnels filed one Form 4 reporting one transaction late. ●Ronald D. Ormand filed a 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 fifteen meetings in 2015 and tookaction by unanimous written consent on four 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 our CorporateGovernance 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 and has determined that four of ourcurrent directors, Mr. Brandolini, General McPeak, Mr. Ormand 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 in his or hercapacity as a director or indirectly through their respective companies, except as described below. See “Certain Relationships and Related Transactions, andDirector Independence”. There were no transactions, relationships or arrangements not otherwise disclosed that were considered by the Board of Directors indetermining 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. Tofacilitate 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. Audit Committee In 2015, our audit committee consisted of Mr. Brandolini and General McPeak. Mr. Ormand had also served on our audit committee but resigned following adetermination that he could not be considered independent and eligible for audit committee service pursuant to Rule 10A-3 of the Exchange Act, since heworked for an investment bank that received compensation from us in the amount of $25,000 per month. However, Mr. Ormand remains independentpursuant to the Nasdaq independence definition. Mr. Brandolini is the audit committee chair and meets the definition of an audit committee financial expert.On January 13, 2016, our Board appointed Mr. Dawson to the audit committee. Our Board determined that each of Mr. Brandolini, General McPeak, and Mr.Dawson were independent as required by Nasdaq for audit committee members. 54  The audit committee has met six times since January 1, 2015 through the date of this Annual Report on Form 10-K, but met separately on several occasions inconnection with a meeting of the full Board. The audit committee is governed by a written charter that is reviewed, and amended if necessary, on an annualbasis. A copy of the charter is available on our website at www.lilisenergy.com under “Investors—Corporate Governance—Highlights.” Compensation Committee Our compensation committee currently consists of Mr. Brandolini and General McPeak. Mr. Ormand had also served on the compensation committee butresigned following a determination that he should not be considered independent and eligible for compensation committee service based on the above-described compensation paid to his investment bank. General McPeak is the chair of the compensation committee. The compensation committee has met twice since January 1, 2015 through the date of thisAnnual Report on Form 10-K, but met separately on several occasions in connection with a meeting of the full Board. The Board determined that each of Mr.Brandolini and General McPeak 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, executiveofficers and key associates. The compensation committee also reviews and approves short-term and long-term incentive plans and other stock or stock-basedincentive plans. In addition, the committee reviews our compensation and benefit philosophy, plans and programs on an as-needed basis. In reviewing ourcompensation and benefits policies, the compensation committee may consider the recruitment, development, promotion, retention, compensation of ourexecutive and senior officers, trends in management compensation and any other factors that it deems appropriate. Under its charter, the compensationcommittee may create and delegate such tasks to such standing or ad hoc subcommittees as it may determine to be necessary or appropriate for the dischargeof its responsibilities, as long as the subcommittee has at least the minimum number of directors necessary to meet any regulatory requirements. Thecompensation committee may engage consultants in determining or recommending the amount of compensation paid to our directors and executive officers.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. Brandolini, General McPeak and Mr. Ormand, who is the chair of thenominating and corporate governance committee. The nominating and corporate governance committee has met twice since January 1, 2015 through the dateof this Annual Report on Form 10-K, 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 the approval ofthe entire Board of Directors, potential candidates to become members of the Board of Directors, recommending membership on standing committees of theBoard of Directors, developing and recommending to the entire Board of Directors corporate governance principles and practices for the Company andassisting in the implementation of such policies, and assisting in the identification, evaluation and recommendation of potential candidates to becomeofficers of the Company. The nominating and corporate governance committee will review our code of business conduct and ethics and its enforcement andreviews and recommends to the Board whether waivers should be made with respect to such code. A copy of the nominating and corporate governancecommittee charter may be found on our website at www.lilisenergy.com under “Investor Relations—Corporate Governance—Highlights.” 55  Director Nominations Process In the event that vacancies on our Board of Directors arise, the nominating and corporate governance committee will consider potential candidates fordirector, which may come to the attention of the nominating and corporate governance committee through current directors, professional executive searchfirms, stockholders or other persons. The nominating and corporate governance committee and in the past, our Board does not set specific, minimumqualifications that nominees must meet in order to be recommended as directors, but believes that each nominee should be evaluated based on his or herindividual merits, taking into account the needs of the Company and the composition of our Board. We do not have any formal policy regarding diversity inidentifying nominees for a directorship, but consider it among the various factors relevant to any particular nominee. We do not discriminate based uponrace, religion, sex, national origin, age, disability, citizenship or any other legally protected status. In the event we decide to fill a vacancy that exists or wedecide to increase the size of the Board, we identify, interview and examine appropriate candidates. We identify potential candidates principally throughsuggestions from our Board and senior management. Our chief executive officer and Board members may also seek candidates through informal discussionswith third parties. We also consider candidates recommended or suggested by stockholders. The nominating and corporate governance committee will consider candidates recommended by stockholders if the names and qualifications of suchcandidates are submitted in writing in accordance with the notice provisions for stockholder proposals set forth below under the caption “StockholderProposals” in this Annual Report to our General Counsel, Lilis Energy, Inc., 216 16th St., Suite #1350, Denver, CO 80202, Attention: General Counsel. TheBoard considers properly submitted stockholder nominations for candidates for the Board of Directors in the same manner as it evaluates other nominees.Following verification of the stockholder status of persons proposing candidates, recommendations are aggregated and considered by the Board and thematerials provided by a stockholder to the general counsel for consideration of a nominee for director are forwarded to the Board. All candidates areevaluated at meetings of the Board. In evaluating such nominations, the Board seeks to achieve the appropriate balance of industry and business knowledgeand experience in light of the function and needs of the Board of Directors. The Board considers candidates with excellent decision-making ability, businessexperience, personal integrity and reputation. Our management recommended our incumbent directors for election at our 2015 annual meeting. We did notreceive any other director nominations. 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 of Directors orany of the directors, Lilis Energy, Inc., 216 16th St., Suite #1350, Denver, CO 80202, Attention: General Counsel. All communications are compiled by thegeneral counsel and forwarded to the Board 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 and employees,including our principal executive officer, principal financial officer, principal accounting officer or controller, and persons performing similar functions. TheCode codifies the business and ethical principles that govern all aspects of our business. A copy of the Code is available on our website atwww.lilisenergy.com under “Investors—Corporate Governance—Highlights.” We undertake to provide a copy of the Code to any person, at no charge, upona written request. All written requests should be directed to: Lilis Energy, Inc., 216 16th St., Suite #1350, Denver, CO 80202, Attention: General Counsel. Ifany substantive amendments are made to the written Code, or if any waiver (including any implicit waiver) is granted from any provision of the Code to ourprincipal executive officer, principal financial officer, principal accounting officer or controller, we will disclose the nature of such amendment or waiver onour website at www.lilisenergy.com under “Investors—Corporate Governance—Highlights.” or, if required, in a current report on Form 8-K. Board Leadership Structure Our Board has separated the chairman and chief executive officer roles. This leadership structure permits the chief executive officer to focus his attention onmanaging our business and allows the chairman to function as an important liaison between management and the Board, enhancing the ability of the Boardto provide oversight of our management and affairs. Our chairman provides input to the chief executive officer and is responsible for presiding over themeetings of the Board and executive sessions of the non-employee directors. Our Chief Executive Officer, who is also a member of the Board, is responsiblefor setting our strategic direction and for the day-to-day leadership performance of the Company. Based on the current circumstances and direction of theCompany and the experienced membership of our Board, our Board believes that separate roles for our Chairman and our Chief Executive Officer, coupledwith a majority of independent directors and strong corporate governance guidelines, is the most appropriate leadership structure for our Company and itsstockholders at this time. 56  The Board’s Role in Risk Oversight It is management’s responsibility to manage risk and bring to the Board’s attention any material risks to the Company. The Board has oversightresponsibility for our risk policies and processes relating to the financial statements and financial reporting processes and the guidelines, policies andprocesses for mitigating those risks. Item 11.EXECUTIVE COMPENSATION Executive Compensation for Fiscal Year 2015 The compensation earned by our executive officers for the fiscal year ending December 31, 2015 consisted of base salary and long-term incentivecompensation consisting of awards of stock grants. Summary Compensation Table The table below sets forth compensation paid to our named executive officers for the fiscal years ending December 31, 2015 and 2014. Name andPrincipal Position Year Salary Bonus StockAwards(1) OptionAwards(2) All OtherCompensation(3) TotalAbraham “Avi” Mirman 2015 $325,466 $100,000(4) $90,000 $1,397,721 $31,504 $1,944,691(president from September 2013 to April2014; chief executive officer from April2014 to present) 2014 $260,356 $1,000,000(5) $- $- $8,800 $1,269,156 Kevin K. Nanke (executive vice presidentand chief financial officer from 2015 $200,000 $200,000(4) $99,000 $608,291 $24,634 $1,131,925March 2015 to present) Ariella Fuchs (general counsel andsecretary 2015 $182,083 $- $48,000 $234,887 $10,538 $475,508from February 2015 to present) Eric Ulwelling 2015 $158,542 $- $- $300,736 $26,242 $485,520(principal accounting officer andcontroller from March 2015 to October2015)(6) 2014 $152,667 $- $21,125 $- $4,896 $178,688 (1)Represents restricted stock awards under our 2012 Equity Incentive Plan (“EIP”). The grant date fair values for restricted stock awards were computed inaccordance with FASB ASC Topic 718. The amounts reported in this column reflect the accounting cost for the stock awards and do not necessarilycorrespond to the actual economic value that may be received for the stock awards. (2)Awards in this column are reported at grant date fair value, if awarded in the period, and at incremental fair value, if modified in the period, in each casein accordance with FASB ASC Topic 718. The grant date fair values for options granted during the year ended December 31, 2015 to Mr. Nanke, Ms.Fuchs and Mr. Ulwelling were $0.8111, $0.7830, and $0.7830, respectively. The incremental fair value for options modified in the year endedDecember 31, 2015 for Mr. Mirman was $0.6989. The amounts reported in this column reflect the accounting cost for the options and do notcorrespond to the actual economic value that may be received for the options. The assumptions used to calculate the fair value of options are set forth inthe notes to our consolidated financial statements included in this Annual Report on Form 10-K. (3) Reflects reimbursement of health insurancepremiums and employer contributions to our 401(k) plan.(4)Reflects a sign-on bonus.(5)Reflects a bonus paid to Mr. Mirman in 2014. See Item 13— Certain Relationships and Related Transactions, and Director Independence—AbrahamMirman. (6)Mr. Ulwelling served as our Principal Accounting Officer and Controller until he was appointed to the position of Acting Chief Financial Officer inMay 2014 and then to the position of Chief Financial Officer in October 2014. In March of 2015, Mr. Ulwelling returned to his position as PrincipalAccounting Officer and Controller. He subsequently resigned from all positions with us on October 15, 2015. 57  Outstanding Equity Awards at Fiscal Year-End Option Awards Stock Awards Name Number ofsecuritiesunderlyingunexercisedoptionsexercisable Number ofsecuritiesunderlyingoptionsunexercisable Equityincentive planawards;Number ofsecuritiesunderlyingunexercisedunearnedoptions Optionexerciseprice Optionexpirationdate Number ofshares orunits ofstock thathave notvested Marketvalue ofshares ofunits of stockthat have notvested(3) Equityincentiveplan awards:Number ofunearnedshares, unitsor otherrights thathave notvested Equityincentiveplan awards:Market orpayout valueof unearnedshares, unitsor otherrights thathave notvested (#) (#) (#) ($) (#) ($) (#) ($) Abraham“Avi”Mirman(1) 666,667 1,333,333(2) - $0.90 3/10/2025 - - - - 600,000 - - $2.11 9/6/2018 Kevin K.Nanke - 750,000(3) - $0.99 3/6/2018 - - - - AriellaFuchs - 300,000(4) - $0.96 3/16/2018 - - - - EricUlwelling(5) 100,000 - - $2.50 2/19/2016 - - - - (1)During 2015, Mr. Mirman entered into an amended and restated employment agreement. Pursuant to this agreement, Mr. Mirman forfeited 2,000,000options with an exercise price of $2.45. The 2,000,000 options outstanding included in the table represent options granted under the amended andrestated employment agreement.(2)Options vest in equal installments on each of March 30, 2016 and March 30, 2017, subject to acceleration provisions and continued service.(3)Options vest in equal installment on each of March 6, 2016, 2017 and 2018.(4)Options vest in equal installments on each of March 16, 2016, 2017 and 2018.(5)Mr. Ulwelling served as our Principal Accounting Officer and Controller until he was appointed to the position of Acting Chief Financial Officer in May2014 and then to the position of Chief Financial Officer in October 2014. In March of 2015, Mr. Ulwelling returned to his position as PrincipalAccounting Officer and Controller. He subsequently resigned from all positions with us on October 15, 2015 and forfeited any unvested options 58  Employment Agreements and Other Compensation Arrangements 2012 Equity Incentive Plan (“EIP”) Our Board and stockholders approved our EIP in August 2012. The EIP provides for grants of equity incentives to attract, motivate and retain the bestavailable personnel for positions of substantial responsibility; to provide additional incentives to our employees, directors and consultants; and to promotethe success and growth of our business. Equity incentives that may be granted under our EIP include: (i) incentive stock options qualified as such under U.S.federal income tax laws; (ii) stock options that do not qualify as incentive stock options; (iii) stock appreciation rights (“SARs”); (iv) restricted stock awards;(v) restricted stock units; and (vi) unrestricted stock awards. Our compensation committee believes long-term incentive-based equity compensation is an important component of our overall compensation programbecause it: ●rewards the achievement of our long-term goals;●aligns our executives’ interests with the long-term interests of our stockholders;●aligns compensation with sustained long-term value creation;●encourages executive retention with vesting of awards over multiple years; and●conserves our cash resources. Our EIP is administered by our compensation committee, subject to the ultimate authority of our Board, which has full power and authority to take all actionsand to make all determinations required or provided for under the EIP, including designation of grantees, determination of types of awards, determination ofthe number of shares of Common Stock subject an award and establishment of the terms and conditions of awards. Under our EIP, originally 900,000 shares of our Common Stock were available for issuance. At the annual meeting of stockholders held on June 27, 2013, ourstockholders approved an amendment to the EIP to increase the number of common shares available for grant under the EIP from 900,000 shares to 1,800,000shares. At a special meeting of stockholders held on November 13, 2013, the stockholders approved an amendment to the EIP to increase the number ofcommon shares available for grant under the EIP from 1,800,000 shares to 6,800,000 shares. At the annual meeting of stockholders held on December 29,2015, our stockholders approved an amendment to the EIP to increase the number of common shares available for grant under the EIP from 6,800,000 sharesto 10,000,000 shares. The number of shares issued or reserved pursuant to our EIP is subject to adjustment as a result of certain mergers, exchanges or otherchanges in our Common Stock. Each member of the Board of Directors and the management team has been periodically awarded stock options and/orrestricted stock grants and restricted stock units, and in the future may be awarded such grants under the terms of the EIP. 59  During the year ended December 31, 2015, the Company granted 1,145,013 shares of restricted Common Stock and 4,800,000 options to purchase shares ofCommon Stock, to employees and directors. Also during the year ended December 31, 2015, the Company forfeited or cancelled 807,414 shares of restrictedCommon Stock and 2,300,000 stock options previously issued in connection with the termination of certain employees and directors. As a result, as ofDecember 31, 2015, the Company had 1,009,373 restricted shares of Common Stock and 6,083,333 options to purchase shares of Common Stock outstandingto employees and directors. Options issued to employees and directors vest in equal installments over specified time periods during the service period orupon achievement of certain performance based operating thresholds. During the year ended December 31, 2015, the Company also issued 75,000 shares ofCommon Stock to consultants for professional services which was not pursuant to an equity compensation plan. Employment Agreements Mr. Mirman In connection with his appointment as the Company’s President, we entered into an employment agreement with Mr. Mirman, dated September 16, 2013. Theagreement provided, among other things, that Mr. Mirman would receive an annual salary of $240,000 which was deferred until we successfullyconsummated a financing of any kind of not less than $2.0 million in gross proceeds. Additionally, he was granted 100,000 shares of Common Stock, whichvested immediately and were fully paid and non-assessable as an inducement for joining the Company. Mr. Mirman was granted an option to purchase600,000 shares of our Common Stock, at a strike price equal to the Company’s closing share price on the September 16, 2013, to become exercisable uponthe date we achieved certain conditions specified in the agreement. The Board determined in September 2014 that those criteria had been met andconsequently the options vested. Mr. Mirman was also provided an incentive bonus package and an additional stock option grant contingent on ourachievement of certain additional performance conditions. We engaged a third-party to complete a valuation of this incentive bonus and not having beenpaid out, has been recorded as a liability and valued at each reporting period. Effective as of March 30, 2015, we entered into an amended and restated employment agreement with Mr. Mirman, which replaced the prior agreement. Theagreement has a three year term and provides for a $100,000 cash bonus due upon signing, base compensation of $350,000 per year, plus 2,000,000 optionsto purchase shares of our Common Stock where one-third of the options vest immediately and two-thirds vest in two annual installments on each of the nexttwo anniversaries of the grant date, which we refer to as the Unvested Shares. The Unvested Shares were subject to the approval of the stockholders of anincrease in the number of shares available for grant under the Plan, which was approved on December 29, 2015. The agreement also provides for additionalbonuses due based on our achievement of certain performance thresholds, which are described in further detail in the agreement as filed with the SEC. Mr. Nanke In connection with the appointment of Mr. Nanke as the Company’s Executive Vice President and Chief Financial Officer, we entered into an executiveemployment agreement with Mr. Nanke, dated March 6, 2015. Pursuant to the terms of the agreement, Mr. Nanke will serve as our Executive Vice Presidentand Chief Financial Officer until his employment is terminated in accordance with the terms of the agreement. The agreement provides, among other things,that Mr. Nanke will receive an annual salary of $240,000. Additionally, as of the effective date of the agreement, Mr. Nanke was granted (i) 100,000 restrictedshares of our Common Stock; (ii) paid a cash signing bonus of $100,000; and (iii) an incentive stock option to purchase up to 750,000 shares of our CommonStock, which vests in equal installments on each of the next three anniversaries of the effective date of the agreement. Mr. Nanke will also receive a cashincentive bonus if we achieve certain production thresholds, which are described in further detail in the agreement as filed with the SEC, and a performancebonus of $100,000 if we achieve certain goals set forth in the agreement. 60  Ms. Fuchs In connection with the appointment of Ms. Fuchs as the Company’s General Counsel, we entered into an executive employment agreement with Ms. Fuchsdated March 16, 2015. Pursuant to the terms of the agreement, Ms. Fuchs will serve as the Company’s General Counsel until her employment is terminated inaccordance with the terms of the agreement. The agreement provides, among other things, that Ms. Fuchs will receive an annual salary of $230,000.Additionally, as of the effective date of the agreement, Ms. Fuchs was granted (i) 50,000 restricted shares of our Common Stock and (ii) an incentive stockoption to purchase up to 300,000 shares of our Common Stock, which vests in equal installments on each of the next three anniversaries of the effective dateof the agreement. Ms. Fuchs will also receive a cash incentive bonus if we achieve certain production thresholds, which are described in further detail in theagreement as filed with the SEC. Mr. Ulwelling In connection with his original position of Principal Accounting Officer and Controller, Mr. Ulwelling entered into an employment agreement, dated as ofJanuary 19, 2012, which provided for a minimum base salary of $110,000 per year, a $15,000 signing bonus in 2012, an automatic increase of $15,000 uponachievement of specified performance targets and a grant of 25,000 shares of common stock to vest in equal installments over three years. Upon his appointment to Interim Chief Financial Officer in May of 2014, Mr. Ulwelling did not immediately enter into a new employment agreement and hisoriginal employment agreement remained in effect until February of 2015, when an executive employment agreement was entered into, dated as of February19, 2015, appointing him as our Chief Financial Officer. That agreement remained in effect as to his role of Principal Accounting Officer and Controllerthrough the date of his resignation on October 15, 2015. Pursuant to the terms of the agreement, Mr. Ulwelling served as our Principal Accounting Officer and Controller until his employment terminated. Theagreement provided, among other things, that Mr. Ulwelling would receive an annual salary of $175,000. Additionally, as of the effective date of theagreement, Mr. Ulwelling was (i) granted an option to purchase 400,000 shares of our Common Stock, with an exercise price equal to the greater of fairmarket value on the effective date or $2.50 per share, of which one-fourth of the option vested immediately, and the remainder of the option was to vest inequal installments on each of the next three anniversaries of the effective date. Mr. Ulwelling had the opportunity to receive a discretionary annual bonusequal to 50% of his base salary, based on achievement of annual target performance goals established by our compensation committee. In addition, theagreement provided for the payment of severance to Mr. Ulwelling in connection with termination of his employment in certain circumstances, includingtermination by the Company without “cause” or upon Mr. Ulwelling’s resignation for “good reason,” in each case subject to Mr. Ulwelling’s execution, non-revocation and delivery of a release agreement, described further below. In October 2015, in connection with his resignation from all positions with the Company, Mr. Ulwelling forfeited 28,333 unvested restricted stock awardsand 300,000 stock option awards. Potential Payments Upon Termination or Change-In-Control Each of the named executive officers’ employment agreements provides for the payment of severance to the executive in connection with termination ofemployment in certain circumstances, including termination by the Company without “cause” or upon the executive resignation for “good reason,” equal to(i) a lump sum payment of twelve months base salary, in the case of Mr. Mirman, and six months base salary, in the case of Mr. Nanke and Ms. Fuchs, in effectimmediately prior to the executive’s last date of employment ($350,000, $125,000 and $115,000 for each of Mr. Mirman, Mr. Nanke and Ms. Fuchs,respectively) less applicable withholdings and deductions and (ii) immediate and full vesting of and lifting of restrictions on any unvested shares included inthe EIP, in each case subject to the executive’s execution, non-revocation and delivery of a release agreement. Upon a “change in control,” as defined in the agreements, each executive is entitled to a severance payment equal to a lump sum payment of twenty-fourmonths base salary in effect immediately prior to the executive’s last date of employment ($700,000, $500,000 and $460,000 for each of Mr. Mirman, Mr.Nanke and Ms. Fuchs, respectively) less applicable withholdings and deductions; and (ii) immediate and full vesting of and lifting of restrictions on anyunvested shares included in the EIP, in each case subject to the executive’s execution, non-revocation and delivery of a release agreement. 61  In each case referenced above, Mr. Nanke is also entitled to a pro rata portion of the $100,000 cash bonus referenced above, adjusted for the number of daysof service of the applicable 12 month period in which the termination occurs. Additionally, each executive and his or her eligible dependents are alsoentitled to continue to be covered by all medical, vision and dental benefit plans maintained by the Company under which the executive was coveredimmediately prior to the date of his or her termination of employment at the same active employee premium cost as a similarly situated active employee;provided, however, that in the event that the executive’s employment is terminated without “cause” or as the result of a “change in control,” we must pay allsuch expenses on behalf of that executive and his or her eligible dependents during the entire eighteen-month period following the date of the termination ofemployment. Narrative Disclosure to Summary Compensation Table Overview The following Compensation Discussion and Analysis describes the material elements of compensation for the named executive officers identified in theSummary Compensation Table above. As more fully described below, our compensation committee reviews and recommends to our full Board of Directorsthe total direct compensation programs for our named executive officers. Our chief executive officer also reviews the base salary, annual bonus and long-termcompensation levels for the other named executive officers. Neither our compensation committee nor management, nor any other person on behalf of ourcompany, retained any compensation consultant for the fiscal year ending December 31, 2015. Compensation Philosophy and Objectives Our compensation philosophy has been to encourage growth in our oil and natural gas reserves and production, encourage growth in cash flow, and enhancestockholder value through the creation and maintenance of compensation opportunities that attract and retain highly qualified executive officers. To achievethese goals, the compensation committee believes that the compensation of executive officers should reflect the growth and entrepreneurial environment thathas characterized our industry in the past, while ensuring fairness among the executive management team by recognizing the contributions each individualexecutive makes to our success. Based on these objectives, the compensation committee has recommended an executive compensation program that includes the following components: ● a base salary at a level that is competitive with the base salaries being paid by other oil and natural gas exploration and production enterprises thathave characteristics similar to ours and could compete with the Company for executive officer level employees; ●annual incentive compensation to reward achievement of the our objectives, individual responsibility and productivity, high quality work, reservegrowth, performance and profitability and that is competitive with that provided by other oil and natural gas exploration and productionenterprises that have some characteristics similar to ours; and ●long-term incentive compensation in the form of stock-based awards that is competitive with that provided by other oil and natural gasexploration and production enterprises that have some characteristics similar to ours. As described below, the compensation committee periodically reviews data about the compensation of executives in the oil and gas industry. Based on thesereviews, we believe that the elements of our executive compensation program have been comparable to those offered by our industry competitors. Elements of Our Compensation Program The three principal components of our compensation program for our executive officers, base salary, annual incentive compensation and long-term incentivecompensation in the form of stock-based awards, are discussed in more detail below. 62  Base Salary Base salaries (paid in cash) for our executive officers have been established based on the scope of their responsibilities, taking into account competitivemarket compensation paid by our peer companies for similar positions. We have reviewed our executives’ base salaries in comparison to salaries forexecutives in similar positions and with similar responsibilities at companies that have certain characteristics similar to ours. Base salaries are reviewedannually, and typically are adjusted from time to time to realign salaries with market levels after taking into account individual responsibilities, performance,experience and other criteria. The compensation committee reviews with the chief executive officer his recommendations for base salaries for the named executive officers, other thanhimself, each year. New base salary amounts have historically been based on an evaluation of individual performance and expected future contributions toensure competitive compensation against the external market, including the companies in our industry with which we compete. The compensation committeehas targeted base salaries for executive officers, including the chief executive officer, to be competitive with the base salaries being paid by other oil andnatural gas exploration and production enterprises that have some characteristics similar to ours. We believe this is critical to our ability to attract and retaintop level talent. Long Term Incentive Compensation We believe the use of stock-based awards creates an ownership culture that encourages the long-term performance of our executive officers. Our namedexecutive officers generally receive a stock grant upon becoming an employee of the Company. These grants vest over time. Retirement and Other Benefits All employees may participate in our 401(k) retirement savings plan (“401(k) Plan”). Each employee may make before tax contributions in accordance withthe Internal Revenue Service limits. We provide this 401(k) Plan to help our employees save a portion of their cash compensation for retirement in a taxefficient manner. We make a matching contribution in an amount equal to 100% of the employee’s elective deferral contribution below 3% of the employee’scompensation and 50% of the employee’s elective deferral that exceeds 3% of the employee’s compensation but does not exceed 5% of the employee’scompensation. All full time employees, including our named executive officers, may participate in our health and welfare benefit programs, including medical, dental andvision care coverage, disability insurance and life insurance. Compensation of Non-Employee Directors Name Fees Earnedor Paid in CashCompensation StockAwards(1)(2) OptionAwards(3) All OtherCompensation Total G. Tyler Runnels* (4) $81,667 $225,000 $577,634 $- $884,301 Nuno Brandolini (5) $168,750 $124,500 $- $- $293,250 General Merrill McPeak (6) $92,556 $165,000 $577,634 $- $835,190 Ronald D. Ormand (7) $76,056 $165,000 $577,634 $- $818,690 R. Glenn Dawson (8) $- $- $- $- $- * No longer a director of the Company. (1)Represents restricted stock awards under our EIP. The grant date fair values for restricted stock awards were determined in accordance with FASB ASCTopic 718. The amounts reported reflect the accounting cost for the awards and do not correspond to the actual economic value that may be receivedfor the awards. At the date of separation from the Board, all unvested shares are forfeited and any compensation expense previously recorded forunvested shares will be reversed. 63  (2)For the year ended December 31, 2015, each director elected to take restricted stock instead of cash for a portion of their fees in the following amounts:Runnels (37,749), Brandolini (84,934), McPeak (53,478), Ormand (18,875).(3)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.(4)Mr. Runnels served as a director from November 21, 2014, through January 13, 2016. Compensation includes $81,667 in director fees (of which aportion was taken as stock in lieu of cash), 100,000 and 315,789 shares of restricted stock awards granted on April 20, 2015 and November 23, 2015,respectively, and 450,000 options to purchase shares of Common Stock granted on April 20, 2015.(5)Mr. Brandolini has served as a director since February 13, 2014. Compensation includes $168,750 in director fees (of which a portion was taken as stockin lieu of cash) and 34,188 and 50,000 shares of restricted stock granted on February 13, 2015 and May 15, 2015, respectively.(6)General McPeak was appointed to the board on January 29, 2015. Compensation includes $92,556 in director fees (of which a portion was taken asstock in lieu of cash), 100,000 shares of restricted stock granted on April 20, 2015 and 450,000 options to purchase shares of Common Stock granted onApril 20, 2015.(7)Mr. Ormand was appointed to the Board on February 25, 2015 and became Chairman of the Board of Directors on January 13, 2016. Compensationincludes $76,056 in director fees (of which a portion was taken as stock in lieu of cash), 100,000 shares of restricted stock granted on April 20, 2015 and450,000 options to purchase shares of Common Stock.(8)Mr. Dawson was appointed to the Board on January 13, 2016 and received no compensation during the year ended December 31, 2015. On April 16, 2015, the Board adopted an amended non-employee director compensation program. Our non-employee director compensation program iscomprised of the following components: ● Initial Grant: Each non-employee director will receive 100,000 restricted shares of Common Stock on the first anniversary of the date of thedirector’s appointment, which vest in three equal installments over a three-year period, (subject to the continued service of the director and certainaccelerated vesting provisions); Annual Stock Award: Each non-employee director will receive an annual stock award equal to $60,000 divided by the most recent per shareclosing price of the Common Stock on the national securities exchange on which the Common Stock is traded prior to the date of each annualgrant, payable on each anniversary of the date an independent director was initially appointed to our Board, and subject to certain acceleratedvesting provisions; ●Annual Cash Retainer: Each non-employee director will receive an annual cash retainer fee of $60,000, paid quarterly, which at the election of thedirector is payable in cash or stock (calculated by dividing the value of cash compensation (or a portion thereof), by the most recent per shareclosing price of the Common Stock on the national securities exchange on which the Common Stock is traded prior to the date of the grant; and ●Option Award: Each non-employee director will receive a one-time initial grant of 250,000 stock options, which vest immediately and 200,000options that 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 non-employee director toChairman of the Board, Chairman of the Audit Committee or Chairman of the Compensation Committee, the director will receive $12,500, $6,250and $6,250, respectively, in cash compensation, which at the election of the director is payable in cash or stock (calculated by dividing the valueof cash compensation (or a portion thereof), by the most recent per share closing price of the Common Stock on the national securities exchangeon which the Common Stock is traded prior to the date of the grant). 64  In connection with the Annual Stock Award, so long as such director continues to be a non-employee director on such date, we issue to such director anumber of shares of our Common Stock equal to $60,000 divided by the most recent closing price per share prior to the date of each annual grant on theanniversary of the date an independent director was initially appointed to our Board (February 13, 2014 for Mr. Brandolini, November 24, 2014 for Mr.Runnels, January 29, 2015 for General McPeak, February 25, 2015 for Mr. Ormand, and January 13, 2016 for Mr. Dawson), These grants are fully vested uponissuance. Accordingly, we granted Mr. Brandolini 34,188 shares on February 13, 2015 and Mr. Runnels, 315,789 shares on November 21, 2015. We have entered into agreements with each of our directors that permit the director to engage in other business activities in the energy industry, some ofwhich may be in conflict with the best interests of our company, and that also provide that if the director becomes aware of a business opportunity, he has noaffirmative duty to present or make such opportunity available to us, except as may be required by his fiduciary duty as a director or by applicable law. 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. Webelieve that this indemnification is necessary to attract and retain qualified directors and officers. Item 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS Securities Authorized for Issuance under Equity Compensation Plans The following table represents the securities authorized for issuance under our equity compensation plans as of December 31, 2015. Equity Compensation Plan InformationPlan category Number ofsecurities to beissued uponexercise ofoutstandingoptions,warrants andrights(1) Weighted-average exercise priceof outstandingoptions,warrants andrights Number ofsecuritiesremainingavailable forfuture issuanceunder equitycompensationplans Equity compensation plans approved by security holders 7,952,333 1.40(2) 1,038,294 Equity compensation plans not approved by security holders - - - Total 7,952,333 1.40(2) 1,038,294 (1)Includes stock options and restricted stock units outstanding under our EIP as of December 31, 2015. Does not include 1,009,373 shares of restrictedstock issued pursuant to our EIP.(2)Represents the weighted average exercise price of outstanding options issued pursuant to our EIP as of December 31, 2015. Other Equity Compensation We have entered into various services agreements for which compensation has been paid with equity securities, including (i) a consulting agreement withBristol Capital LLC pursuant to which we issued to Bristol a five year warrant to purchase up to 1,000,000 shares of Common Stock at an exercise price of$2.00 per share (or, in the alternative, 1,000,000 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 500,000 shares of Common Stock at an exercise price of $2.33 for a warrant to purchase250,000 shares of Common Stock and $2.00 for the warrant to purchase 250,000 shares of Common Stock; (iii) an investment banking agreement with TRWpursuant to which the Company issued 900,000 warrants at an exercise price of $4.25 per share; and (iv) various agreements pursuant to which issued anaggregate amount of 150,000 and 300,000 five year warrants to purchase shares of Common Stock at an exercise price of $2.50 and $2.00, respectively. Withrespect to the warrants awarded to Bristol Capital, the Company recorded the warrants as a derivative due to the ratchet down provision encompassed in thewarrants. 65  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 30, 2016 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 totalnumber of shares outstanding as of March 30, 2016 of 29,166,590. Unless otherwise indicated, the persons and entities named in the table have sole votingand sole investment power with respect to the shares set forth opposite the stockholder’s name. Beneficial ownership is determined in accordance with Rule13d-3 under the Securities Exchange Act of 1934, as amended. In computing the number of shares beneficially owned by a person or a group and thepercentage ownership of that person or group, shares of our Common Stock subject to options or warrants currently exercisable or exercisable within 60 daysafter the date hereof are deemed outstanding by such person or group, but are not deemed outstanding for the purpose of computing the percentage ownershipof any other person. Unless otherwise indicated, the address of each stockholder listed in the table is c/o Lilis Energy, Inc., 216 16th St., Suite #1350, Denver,CO 80202. Name and Address of Beneficial Owner CommonStock HeldDirectly CommonStockAcquirableWithin 60Days TotalBeneficiallyOwned Percent ofClassBeneficiallyOwned Directors and Executive Officers Abraham Mirman,Chief Executive Officer 310,861(1) 1,599,797(2) 1,910,658 6.21% Eric Ulwelling, Former Chief Financial Officer; Principal Accounting Officer and Controller - 100,000(3) 100,000 * Kevin Nanke, Chief Financial Officer 100,000 250,000(4) 350,000 1.19% Ariella Fuchs, General Counsel and Secretary - 150,000(5) 150,000 * Nuno Brandolini,Director 906,205 570,575(6) 1,476,780(7) 4.97% G. Tyler Runnels,Former Director 3,069,904(8) 316,667(9) 3,386,571(10) 11.49% General Merrill McPeak Director 606,864 572,267(11) 1,179,131(12) 3.96% Ronald D. Ormand Chairman of the Board 93,875 594,536(13) 688,411(14) 2.31% R. Glenn Dawson Director - 250,000(15) 250,000(16) * Directors and Officers as a Group (9 persons) 5,087,709 4,403,842 9,491,551 31.83% Pierre Caland Rutimatstrasse 16, 3780Gstadd, Switzerland Tortola, British Virgin Islands 4,317,129(17) 2,254,359(18) 6,571,488(19) 20.91% Scott J. Reiman730 17th Street, Suite 800Denver, CO 80202 1,558,471(20) 1,000,000(21) 2,558,471 8.48% Hexagon, LLC 730 17th Street, Suite 800Denver, CO 80202 1,250,000(22) 1,000,000(23) 2,250,000 7.46% Steven B. Dunn and LauraDunn Revocable Trust DTD 10/28/10 16689 Schoenborn Street North Hills, CA 91343 2,567,294(24) -(25) 2,567,294 8.80% 66  (1)Includes: (i) 110,861 shares of Common Stock held by The Bralina Group, LLC, in which Mr. Mirman has voting and dispositive power. (2)Includes: (i) 110,861 shares of Common Stock issuable to The Bralina Group, LLC, in which Mr. Mirman has voting and dispositive power upon theexercise of a warrant to purchase Common Stock; (ii) 103,734 shares issuable upon conversion of Series A 8% Convertible Preferred Stock purchased inMay 30, 2014 Private Placement; (iii) 51,868 shares issuable upon exercise of warrants purchased in the May 30, 2014 Private Placement; (iv) optionsto purchase 600,000 shares of Common Stock that vested upon achievement of criteria specified in Mr. Mirman's initial employment agreement and (vi)1,333,334 options to purchase shares of Common Stock issued pursuant to Mr. Mirman’s amended and restated employment agreement. Does notinclude (i) the additional 666,667 options to purchase Common Stock that are subject to vesting upon the second anniversary of the effective date ofMr. Mirman’s amended and restated employment agreement (March 30, 2017) or (ii) 1,000,000 and 2,000,000 shares of Common Stock issuable uponthe conversion of convertible notes and exercise of warrants, respectively, each of which are subject to stockholder approval. Each of the warrantscontain conversion caps that prevent an exercise that would result in more than a 4.99% beneficial ownership of the Company’s Common Stock (3)Includes vested options to purchase 100,000 shares of Common Stock. (4)Does not include options to purchase 500,000 shares of Common Stock subject to future vesting. (5)Does not include options to purchase 200,000 shares of Common Stock subject to future vesting. (6)Includes (i) 125,000 shares of Common Stock underlying warrants purchased in the January 2014 Private Placement, (ii) 41,494 shares of CommonStock underlying the Series A 8% Convertible Preferred Stock (iii) 20,747 shares of Common Stock underlying the accompanying warrants to purchaseCommon Stock purchased by Mr. Brandolini in the May 30, 2014 Private Placement, (iv) options to purchase 250,0000 shares of Common Stock thatvested immediately on October 1, 2014 pursuant to director compensation, (v) options to purchase 133,333 shares of Common Stock that vested on Mr.Brandolini’s anniversaries of his appointment to the Board pursuant to his non-employee director award agreement. (7)Does not include options to purchase 66,667 shares of Common Stock subject to future vesting, (ii) 41,667 restricted stock units granted in connectionwith director compensation or (iii) 300,000 and 600,000 shares of Common Stock issuable upon the conversion of convertible notes and exercise ofwarrants, respectively, each of which are subject to stockholder approval. Each of the warrants contain conversion caps that prevent an exercise thatwould result in more than a 4.99% beneficial ownership of the Company’s Common Stock (8)Based upon a Form 4 filed with the SEC on April 22, 2015, a Schedule 13D filed with the SEC on October 10, 2014 and additional informationreceived from a representative of Mr. Runnels. Includes (i) 157,565 shares of Common Stock held by the Runnels Family Trust DTD 1-11-2000 (the“Runnels Family Trust”), of which Mr. Runnels, with Jasmine N. Runnels, is trustee issued in connection with interest payments on the Company’sDebentures; (ii) 866,414 shares of Common Stock held by the Runnels Family Trust; (iiii) 906,610 shares of Common Stock held by TRW, of whichMr. Runnels is the majority owner (iv) 122,991 shares held by High Tide, LLC (“High Tide”), of which Mr. Runnels is the manager; (vi) 4,025 shares ofCommon Stock held by Pangaea Partners, LLC, of which Mr. Runnels is the manager; (v) 5,250 shares of Common Stock held by TR Winston CapitalManagement, LLC, of which Mr. Runnels is the chairman; (vi) 575,795 shares of Common Stock held by Golden Tiger, LLC, of which Mr. Runnels isthe manager; (ix) 25 shares of Common Stock held by Mr. Runnels through SEP IRA Pershing LLC Custodian; (vi) 15,000 shares of Common Stockheld by Mr. Runnels through G. Tyler Runnels 401k; (viii) 112,309 shares of Common Stock transferred to accredited investors for services rendered inconnection with an investment banking agreement on May 29, 2015, (ix) 461,872 shares of Common Stock issued in connection with Mr. Runnels’director compensation. (9)Includes options to purchase 316,667 shares of Common Stock issued in connection with Mr. Runnels’ director compensation. In connection with Mr.Runnels’ resignation from the Board on January 13, 2016, he forfeited 133,333 options to purchase shares of Common Stock subject to future vestingand 66,667 restricted stock units subject to future vesting. (10)Based upon Schedule 13D filed with the SEC on October 10, 2014 and additional information received from a representative of Mr. Runnels. Does notinclude (i) shares issuable to the Runnels Family Trust upon (a) conversion of outstanding debentures (427,164 shares of Common Stock), (b)conversion of outstanding preferred stock (103,734 shares of Common Stock), and (c) exercise of outstanding warrants to purchase Common Stock(220,682 shares of Common Stock); (ii) shares issuable to TRW upon (a) conversion of outstanding preferred stock (219,502 shares of Common Stock)and (b) exercise of outstanding warrants to purchase Common stock (2,550,699 shares of Common Stock), and (iii) 16,667 shares of Common Stockissuable to High Tide upon exercise of outstanding warrants to purchase Common Stock. These shares are excluded due to conversion caps that exist onMr. Runnels’ holdings that prevent any conversion that would result in more than a 9.9% beneficial ownership of the Company’s Common Stock. (11)Includes (i) 103,734 shares of Common Stock issuable upon conversion of Series A 8% Convertible Preferred Stock purchased in the May 30, 2014Private Placement; (ii) 51,867 shares of Common Stock issuable upon exercise of warrants purchased in the May 30, 2014 Private Placement; (iii)options to purchase 316,667 shares of Common Stock in connection with General McPeak’s appointment and anniversary of his appointment to theBoard. (12)This does not include (i) 66,667 shares of restricted stock units subject to future vesting, (ii) options to purchase 133,335 shares of Common Stocksubject to future vesting or (iii) 500,004 and 1,000,008 shares of Common Stock issuable upon the conversion of convertible notes and exercise ofwarrants, respectively, each of which are subject to stockholder approval. Each of the warrants contain conversion caps that prevent an exercise thatwould result in more than a 4.99% beneficial ownership of the Company’s Common Stock (13)Includes (i) 207,469 shares of Common Stock issuable upon conversion of Series A 8% Convertible Preferred Stock purchased in the May 30, 2014Private Placement; (ii) 103,734 shares of Common Stock issuable upon exercise of warrants purchased in the May 30, 2014 Private Placement, eachindirectly held by Mr. Ormand as the manager of Perugia Investments L.P., (iii) 33,334 vested restricted stock units and (iv) options to purchase316,667 shares of Common Stock directly held by Mr. Ormand. (14)Does not include (i) 66,666 restricted stock units, two-thirds of which are subject to future vesting, (ii) options to purchase 133,333 shares of CommonStock subject to future vesting or (iii) 2.3 million and 4.6 million shares of Common Stock issuable upon the conversion of convertible notes andexercise of warrants, respectively, each of which are subject to stockholder approval, each indirectly held by Mr. Ormand in connection with hisaffiliation with The Bruin Trust, an irrevocable trust managed by an independent trustee and whose beneficiaries include the adult children of Mr.Ormand. Mr. Ormand does not have voting or dispositive power over these securities. Additionally, each of the warrants contain conversion caps thatprevent an exercise that would result in more than a 4.99% beneficial ownership of the Company’s Common Stock (15)Includes (i) 250,000 options issued in connection with Mr. Dawson’s appointment. 67  (16)Does not include (i) 200,000 options to purchase Common Stock subject to vesting in equal installments on each appointment anniversary, (ii) 100,000shares of restricted stock units subject to future vesting and (iii) 100,000 and 200,000 shares of Common Stock issuable upon the conversion ofconvertible notes and exercise of warrants, respectively, each of which are subject to stockholder approval. The warrants contain conversion caps thatprevent an exercise that would result in more than a 4.99% beneficial ownership of the Company’s Common Stock(17)Based upon a Schedule 13D jointly filed with the SEC on April 15, 2015 by Mr. Caland, Wallington Investment Holdings, Ltd. (“Wallington”) andSilvercreek Investment Limited Inc. and certain information maintained by the Company. Includes: (i) 5,963,119 shares of Common Stock owneddirectly by Wallington Investment Holdings, Ltd. and indirectly by Mr. Pierre Caland, the holder of sole voting and dispositive power over such shares,(ii) 608,369 shares of Common Stock owned directly by Silvercreek Investment Limited Inc. and indirectly by Mr. Caland, the holder of sole voting anddispositive power over such shares, and (iii) 385,537 shares of Common stock issued to Wallington in connection with interest payments made on theCompany’s Debentures.(18)Based upon a Schedule 13D filed with the SEC on April 15, 2015. Includes 2,254,359 shares of Common Stock issuable to Wallington upon theexercise of warrants and (ii) 51,868 shares of Common Stock issuable to Wallington upon conversion of the Company's Series A 8% ConvertiblePreferred Stock.(19)Does not include (i) 1,027,508 shares of Common Stock issuable to Wallington upon the conversion of the remaining Debentures or (ii) 600,000 and1,200,000 shares of Common Stock issuable upon the conversion of convertible notes and exercise of warrants, respectively, each of which are subjectto stockholder approval..(20)Based upon a Schedule 13D filed with the SEC on September 5, 2014. Includes (i) 1,250,000 shares of Common Stock owned by Hexagon, LLC, (ii)129,008 shares of Common Stock owned by Labyrinth Enterprises LLC, which is controlled by Scott J. Reiman, (iii) 129,463 shares of Common Stockowned by Reiman Foundation, which is controlled by Scott J. Reiman, and (iv) 50,000 shares of Common Stock owned by Scott J. Reiman. Mr. Reimanis President of Hexagon.(21)Based upon a Schedule 13D filed with the SEC on September 5, 2014. Includes 1,000,000 shares of Common Stock underlying warrants held byHexagon.(22)Based upon a Schedule 13D filed with the SEC on September 5, 2014.(23)Based upon a Schedule 13D filed with the SEC on September 5, 2014. The Company entered into a settlement agreement with Hexagon pursuant towhich the Company issued 2,000 shares of Conditionally Redeemable 6% Preferred Stock, which pays a dividend on a quarterly basis in cash. Thepreferred stock does not have any voting rights and cannot be converted to Common Stock.(24)Based upon information received from a representative of Steven B. Dunn and Laura Dunn and company records. Includes (i) 187,608 shares ofCommon Stock issued in connection with interest payments made on the Company’s Debentures; (ii) 2,205,768 shares of Common Stock owned bySteven B. Dunn and Laura Dunn Revocable Trust (the “Trust”), (iii) 86,959 shares of Common Stock owned by Beau 8, LLC; and (iv) 86,959 shares ofCommon Stock owned by Winston 8, LLC. Steven B. Dunn and Laura Dunn are trustees of the Trust and also share voting and dispositive power withrespect to the shares owned by the LLCs.(25)Based upon information received from a representative of Steven B. Dunn and Laura Dunn. Does not include (i) 500,000 shares of Common Stockissuable upon the conversion of the remaining Debentures, with the right to convert being subject to stockholder approval or (ii) 925,223 shares ofCommon Stock issuable to the Steven B. Dunn and Laura Dunn Revocable Trust upon the exercise of warrants, some of which are subject to conversioncaps and some of which are not yet exercisable by their terms. To our knowledge, except as noted above, no person or entity is the beneficial owner of more than 5% of the voting power of our Common Stock. 68  Item 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE During the fiscal years ended December 31, 2015 and 2014, we have engaged in the following transactions with related parties: Debenture Conversion Agreement On December 29, 2015, we entered into a Debenture Conversion Agreement (the “Conversion Agreement”) between us and all of the remaining holders of ourDebentures. The terms of the Conversion Agreement provide that the entire amount of approximately $6.85 million in outstanding Debentures areautomatically converted into our Common Stock upon the closing of the proposed merger with Brushy, which we refer to as the Conversion Date, providedthat we obtain the requisite stockholder approval as required by the Nasdaq Marketplace Rules, which we plan to seek at the next stockholders’ meeting to beheld in connection with approving the proposed merger with Brushy. Pursuant to the terms of the Conversion Agreement, the Debentures will be converted ata price of $0.50, which will result in the issuance of an aggregate of 13,692,930 shares of our Common Stock upon conversion of the Debentures. Holders ofthe Debentures have waived and forfeited any and all rights to receive accrued but unpaid interest. Upon the conversion of the Debentures, the holders’security interest will also be extinguished. Certain parties to the Conversion Agreement include related parties of our company, such as the Steven B. Dunn and Laura Dunn Revocable Trust dated10/28/10, of which its respective Debenture amount to be converted on the Conversion Date is $1,017,111.11, and Wallington Investment Holdings, Ltd., ofwhich its respective Debenture amount to be converted on the Conversion Date is $2,090,180.12. Each of the Steven B. Dunn and Laura Dunn RevocableTrust dated 10/28/10 and Wallington Investment Holdings, Ltd. are a more than 5% shareholder of our company. From December 29, 2015 to January 5, 2016, we entered into 12% Convertible Subordinated Note Purchase Agreements with various lending parties, whichwe refer to as the Purchasers, for the issuance of an aggregate principal amount of $3.75 million Convertible Notes, which includes the $750,002 of short-termnotes exchanged for Convertible Notes by us and warrants to purchase up to an aggregate of approximately 15,000,000 shares of our Common Stock at anexercise price of $0.25 per share. The proceeds from this financing was used to pay a $2 million refundable deposit in connection with the Merger, to fundapproximately $1.3 million of interest payments to certain of our lenders and for our working capital and accounts payables. The Convertible Notes bear interest at a rate of 12% per annum, payable at maturity on June 30, 2016. The Convertible Notes and accrued but unpaid interestthereon are convertible in whole or in part from time to time at the option of the holders thereof into shares of our common stock at a conversion price of$0.50. The Convertible Notes may be prepaid in whole or in part by paying all or a portion of the principal amount to be prepaid together with accruedinterest thereon to the date of prepayment at a premium of 103% for the first 120 days and a premium of 105% thereafter, so long as no Senior Debt isoutstanding. The Convertible Notes contain customary events of default, which, if uncured, entitle each noteholder to accelerate the due date of the unpaidprincipal amount of, and all accrued and unpaid interest, subject to certain subordination provisions. The Purchasers include certain related parties of us, including Abraham Mirman, our Chief Executive Officer and a member of our Board of Directors($750,000 including the short-term note exchange investment), the Bruin Trust, an irrevocable trust managed by an independent trustee and whosebeneficiaries include the adult children of Ronald D. Ormand, Chairman of our Board of Directors ($1.15 million) and Pierre Caland through WallingtonInvestment Holdings, Ltd. ($300,000), who holds more than 5% of our Common Stock. Certain of our officers, directors and consultants who entered into short-term note agreements with us in 2015, also entered into note exchange agreements,whereby the short-term noteholder agreed to exchange all of our outstanding obligations under such short-term notes, which as of December 29, 2015 hadoutstanding obligations of $750,002, into the Convertible Notes at a rate, expressed in principal amount of Convertible Notes equal to $1.00 for $1.00, inexchange for the cancellation of the short-term notes, with all amounts due thereunder being cancelled and deemed to have been paid in full, including anyaccrued but unpaid interest. The short-term noteholders include certain related parties of the Company, including Abraham Mirman, the Chief Executive Officer and a director of theCompany ($250,000), General Merrill McPeak, a director of the Company ($250,000), and Nuno Brandolini, a director of the Company ($150,000). Additionally, on March 18, 2016, we issued an additional aggregate principal amount of $500,000 in Convertible Notes and warrants to purchase up to 2.0million shares of our Common Stock. The terms and conditions of the Convertible Notes are identical to those of the Convertible Notes with the exception ofthe maturity date, which is April 1, 2017. 69  The Purchasers include a related party of the Company, R. Glenn Dawson, a director of the Company ($50,000). Abraham Mirman Abraham Mirman, the Chief Executive Officer and a director of our company, is an indirect owner of a group which converted approximately $220,000 ofDebentures in connection with the $9.00 million of Debentures converted in January 2014, and was paid $10,000 in interest at the time of the Debentureconversion. During the January 2014 private placement, Mr. Mirman entered into a subscription agreement with us to invest $500,000, for which Mr. Mirman will receive250,000 shares of stock and 250,000 warrants. The subscription agreement will not be consummated until a shareholder meeting is conducted to receive therequired approval to allow executives and Board directors the ability to participate in the offering. Additionally, as discussed below, on January 31, 2014, we entered into the First Conversion Agreement with the holders of the Debentures, which alsoincluded The Bralina Group, LLC, in which Mr. Mirman has voting and dispositive power, In April 2014, we appointed Abraham Mirman to serve as the Company’s Chief Executive Officer. Prior to joining us, Mr. Mirman was employed by TRW, asits Managing Director of Investment Banking and until September 2014 continued to devote a portion of his time to serving in that role. In connection withthe appointment of Mr. Mirman, we and TRW amended the investment banking agreement in place between the us and TRW at that time to provide that,upon our receipt of gross cash proceeds or drawing availability of at least $30.00 million, measured on a cumulative basis and including certain restructuringtransactions, subject to the Company’s continued employment of Mr. Mirman, TRW would receive from the Company a lump sum payment of $1.00 million.Mr. Mirman’s compensation arrangements with TRW provided that upon TRW’s receipt from the Company of the lump sum payment, TRW would make apayment of $1 million to Mr. Mirman. The Board determined in September 2014 that the criteria for the lump sum payment had been met. Mr. Mirman alsoreceived, as part of his compensation arrangement with TRW, the 100,000 common shares of the Company that were issued to TRW in conjunction with theinvestment banking agreement. 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 and majorityowner. Mr. Runnels also beneficially holds more than 5% of our Common Stock, including the holdings of TRW and his personal holdings, and haspersonally participated in certain transactions with us. On January 22, 2014, we paid TRW a commission equal to $486,000 (equal to 8% of gross proceeds at the closing of the January 2014 private placement). Ofthis $486,000 commission, $313,750 was paid in cash and $172,250 was paid in 86,125 Units. In addition, we paid TRW a non-accountable expenseallowance of $182,250 (equal to 3% of gross proceeds at the closing of the January 2014 private placement) in cash. If the participation of certain of ourcurrent and former officers and directors, who remain committed, is approved by our shareholders, we will pay TRW an additional commission. The Unitsissued to TRW were the same Units sold in the January 2014 private placement and were invested in the January 2014 private placement. On January 31, 2014, we entered into a debenture conversion agreement with all of the holders of the Debentures, including TRW and Mr. Runnels’ personaltrust, which we refer to as the First Conversion Agreement. Under the terms of the First Conversion Agreement, $9.0 million of the approximately $15.6million in Debentures outstanding as of January 30, 2014 immediately converted to shares of Common Stock at a price of $2.00 per common share. Asadditional inducement for the conversions, we issued warrants to the converting Debenture holders to purchase one share of Common Stock, at an exerciseprice equal to $2.50 per share, for each share of Common Stock issued upon conversion of the Debentures. TRW acted as the investment banker for the FirstConversion Agreement and was compensated by being issued 225,000 shares of our Common Stock valued at a market price of $3.05 per share. During theyear ended December 31, 2014, we valued the investment banker compensation at $686,000. 70  On May 19, 2014, we and the holders of the Debentures agreed to extend the maturity date under the Debentures until August 15, 2014, and on June 6, 2014,they agreed to further extend the maturity date under the Debentures from August 15, 2014 to January 15, 2015. In January 2015, we entered into anextension agreement which extends the maturity date of the Debentures until January 8, 2018. Upon completion of the conversion of the remainingDebentures, TRW will be entitled to an additional commission. On October 6, 2014, we entered into a letter agreement, or the Waiver, with the holders of our Debentures, including TRW and Mr. Runnels’ personal trust.Pursuant to the Waiver, the holders of the Debentures agreed to waive any Event of Default (as that term is defined in the Debentures) that may have occurredprior to the date of the Waiver, including any default in connection with the Hexagon term loan, and to rescind and annul any acceleration or right toacceleration that may have been triggered thereby. In exchange for the Waiver, we agreed that TRW, as representative for the holders of the Debentures,would have the right to nominate two qualified individuals to serve on our Board. Mr. Runnels is one of the qualified nomination designees which TRW haselected to place on the Board. On March 28, 2014, we entered into a Transaction Fee Agreement with TRW in connection the May private placement, which we refer to as the TransactionFee Agreement. Pursuant to the Transaction Fee Agreement, we agreed to compensate TRW 5% of the gross proceeds of the May private placement, plus a$25,000 expense reimbursement. On April 29, 2014, we and TRW amended the Transaction Fee Agreement to increase TRW’s compensation to 8% of thegross proceeds, plus an additional 1% of the gross proceeds as a non-accountable expense reimbursement in addition to the $25,000 originally contemplated.All fees were netted against gross proceeds from the May private placement. On May 30, 2014, we paid TRW a commission equal to $600,000 (equal to 8% of gross proceeds at the closing of the May private placement). Of this$600,000 commission, $51,850 was paid in cash to TRW, $94,150 was paid in cash to other brokers designated by TRW, and remaining $454,000 wasinvested by TRW into shares of Series A 8% Convertible Preferred Stock. In addition, we paid TRW a non-accountable expense allowance of $75,000 (equalto 1% of gross proceeds at the closing of the May private placement) in cash. On June 6, 2014, TRW executed a commitment to purchase or affect the purchase by third parties of an additional $15 million in Series A 8% ConvertiblePreferred Stock, to be consummated within ninety (90) days thereof. The agreement was subsequently extended and expired on February 22, 2015. OnFebruary 25, 2015, we and TRW agreed in principal to a replacement commitment, pursuant to which TRW has agreed that, at the request of our Board, TRWwould purchase or effect the purchase by third parties of an additional $7.5 million in Series A 8% Convertible Preferred Stock, to be consummated no laterthan February 23, 2016, with all other terms substantially the same as those of the original commitment, which has not yet occurred. Ronald D. Ormand On March 20, 2014, we entered into an Engagement Agreement, or the MLV Engagement Agreement, with MLV. Pursuant to the MLV EngagementAgreement, MLV acted as our exclusive financial advisor. Ronald D. Ormand, director of the Company since February 2015 and Chairman of our Board ofDirectors as of January 2016, was the former Managing Director and Head of the Energy Investment Banking Group at MLV until January 2016. The MLVEngagement Agreement provided for a fee of $25,000 to be paid monthly to MLV, subject to certain adjustments and other specific fee arrangements inconnection with the nature of financial services being provided. The term of the MLV Engagement Agreement expired on October 31, 2015. We expensed $150,000 and $50,000 for the years ended December 31, 2015 and 2014, respectively. A total of $150,000 was paid to MLV for the year endedDecember 31, 2014. On May 27, 2015, MLV agreed to take $150,000 of its accrued fees Common Stock and was issued 75,000 shares in lieu of cashpayment. The closing share price on May 27, 2015 was $1.56. 71  Hexagon, LLC Hexagon, LLC, which we refer to as Hexagon, our former primary lender, still holds over 5% of our Common Stock. We were a party to three term loan credit agreements dated as of January 29, 2010, March 25, 2010, and April 14, 2010, respectively, which collectively, werefer to as the credit agreements with Hexagon. On April 15, 2013, Hexagon agreed to amend the credit agreements to extend their maturity dates to May 16,2014. Pursuant to the amendment, Hexagon agreed to (i) reduce the interest rate under the credit agreements from 15% to 10% beginning retroactively withMarch 2013, (ii) permit us to make interest only payments for March, April, May, and June 2013, after which time the minimum secured term loan paymentbecame $0.23 million, and (iii) forbear from exercising its rights under the term loan credit agreements for any breach that may have occurred prior to theamendment. In consideration for the extended maturity date, the reduced interest rate and minimum loan payment under the secured term loans, we providedHexagon an additional security interest in 15,000 acres of our undeveloped acreage. In addition, Hexagon and its affiliates had interests in certain of our wells independent of Hexagon’s interests under the term loans, for which Hexagon or itsaffiliates receive revenue and joint-interest billings. On September 2, 2014, we entered into the Final Settlement Agreement with Hexagon, to settle all amounts payable by us pursuant to existing creditagreements with Hexagon that were secured by mortgages against the Hexagon Collateral. Pursuant to the Final Settlement Agreement, in exchange for fullextinguishment of all amounts payable ($15.1 million in principal and interest) pursuant to the credit agreements and related promissory notes, we agreed toassign to Hexagon all of the Hexagon Collateral, and issued to Hexagon $2.0 million in a new series of 6% Redeemable Preferred Stock. The Final SettlementAgreement also prohibited Hexagon from selling or otherwise disposing of any shares of our Common Stock held by Hexagon until February 29, 2016. Inaddition, pursuant to the Final Settlement Agreement, we and Hexagon each mutually released and discharged all known and unknown claims against theother and their respective representatives that they had or may have, including claims relating to the credit agreements. Officers and Directors As discussed above, on January 31, 2014, we entered into the First Conversion Agreement with the holders of the Debentures, which also included W. PhillipMarcum, our then Chief Executive Officer, and A. Bradley Gabbard, our then Chief Financial Officer. Employment Agreements with Officers See “Employment Agreements and Other Arrangements” above. Compensation of Directors See “Compensation of 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. We have acorporate conflict of interest policy that prohibits conflicts of interests unless approved by our Board of Directors. Our Board of Directors has established acourse of conduct whereby it considers in each case, whether the proposed transaction is on terms as favorable or more favorable to us than would beavailable from a non-related party. Our Board of Directors also looks at whether the transaction is fair and reasonable to us, taking into account the totality ofthe relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us. Each of the relatedparty transactions described above was presented to our Board of Directors for consideration and each of these transactions was unanimously approved by ourBoard of Directors after reviewing the criteria set forth in the preceding two sentences. 72  Director Independence Our Board of Directors has determined that each of Nuno Brandolini, General Merrill McPeak and Ronald D. Ormand qualifies as an independent directorunder rules promulgated by the SEC and Nasdaq listing standards, and has concluded that none of these directors has a material relationship with us thatwould interfere with the exercise of independent judgment in carrying out the responsibilities of a director. Item 14.PRINCIPAL ACCOUNTING FEES AND SERVICES Hein & Associates LLP (“Hein”) became our independent registered public accounting firm on January 19, 2010. On November 7, 2014, we were notified byHein that it did not wish to stand for re-election. On November 25, 2014, we engaged Marcum LLP (“Marcum”) as our independent registered publicaccounting firm, which was approved by our Board. There were no disagreements in 2014 or 2015 on any matter of accounting principles or practices, financial statement disclosures or auditing scope orprocedures. The following table sets forth fees billed by our principal accounting firm of Marcum for (i) the year ended December 31, 2015 and from November 25, 2014through December 31, 2014 and (ii) Hein from January 1, 2014 through November 7, 2014: Year Ended December 31, Fee Category 2015 2014 Marcum Hein Audit Fees $264,000 $294,000 $111,254 Audit-Related Fees $5,200 — — Tax Fees $— — 66,920 All Other Fees $— — — Total Fees $269,200 $294,000 $178,174 Audit Fees consist of the aggregate fees for professional services rendered for the audit of our annual financial statements and the reviews of the financialstatements included in our quarterly reports on Forms 10-Q and for any other services that were normally provided by our auditors in connection with ourstatutory and regulatory filings or engagements. Audit-Related Fees consist of the aggregate fees billed or reasonably expected to be billed for professional services rendered for assurance and relatedservices that were reasonably related to the performance of the audit or review of our financial statements and were not otherwise included in Audit Fees. Tax Fees consist of the aggregate fees billed for professional services rendered for tax consulting. Included in such Tax Fees were fees for consultancy,review, and advice related to our income tax provision and the appropriate presentation on our financial statements of the income tax related accounts. All Other Fees consist of the aggregate fees billed for products and services provided by our auditors and not otherwise included in Audit Fees, Audit-RelatedFees 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 be providedby 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 fiscal year ended December 31, 2015, we had no non-auditservices. 73  Part IV Item 15.EXHIBITS AND FINANCIAL STATEMENT SCHEDULES INDEX TO FINANCIAL STATEMENTS a) Report of Independent Registered Public Accounting FirmF-1Balance Sheets as of December 31, 2015 and 2014F-2Statements of Operations for the years ended December 31, 2015 and 2014F-4Statements of Stockholders’ (Deficit)/Equity for the years ended December 31, 2015 and 2014.F-5Statements of Cash Flows for the years ended December 31, 2015 and 2014F-6Notes to Financial StatementsF-7 b) Financial statement schedules Not applicable. c) 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. 74  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: April 14, 2016By:/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 April 14, 2016Abraham Mirman (Principal Executive Officer) /s/ Kevin K. Nanke Executive Vice President and Chief Financial Officer April 14, 2016Kevin Nanke (Principal Financial and Accounting Officer) /s/ Ronald D. Ormand Chairman of the Board April 14, 2016Ronald D. Ormand /s/ Nuno Brandolini Director April 14, 2016Nuno Brandolini /s/ R. Glenn Dawson Director April 14, 2016R. Glenn Dawson /s/ General Merrill McPeak Director April 14, 2016General Merrill McPeak 75  Exhibit Index The following exhibits are either filed herewith or incorporated herein by reference 2.1Asset Purchase Agreement (incorporated herein by reference to Exhibit 2.1 to the Company’s current report on Form 8-K filed on May 5, 2015).2.2First Amendment to the Asset Purchase Agreement (incorporated herein by reference to Exhibit 2.2 to the Company’s current report on Form 8-Kfiled on June 11, 2015).2.3Second Amendment to the Asset Purchase Agreement, dated June 30, 2015 (incorporated herein by reference to Exhibit 2.3 to the Company’squarterly report on Form 10-Q filed on August 19, 2015).2.4Agreement and Plan of Merger, dated as of December 29, 2015 between 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).2.5First Amendment to Agreement and Plan of Merger, dated January 20, 2016, by and 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).2.6Second Amendment to the Agreement and Plan of Merger, dated March 24, 2016, by and 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).3.1Amended and Restated Articles of Incorporation (incorporated herein by reference to Exhibit 3.1 from the Company’s current report on Form 8-Kfiled on October 20, 2011).3.2Certificate of Amendment to the Articles of Incorporation of Recovery Energy, Inc. (incorporated herein by reference to Exhibit 3.1 from theCompany’s current report on Form 8-K filed on November 19, 2013).3.3Amended and Restated Bylaws (incorporated herein by reference to Exhibit 3.2 to the Company’s current report on Form 8-K filed on June 18,2010).3.4Certificate of Designation of Preferences, Rights, and Limitations, dated May 30, 2014 (incorporated herein by reference to Exhibit 3.1 from theCompany’s current report on Form 8-K filed on June 4, 2014).3.5Amendment to Certificate of Designations of Preferences, Rights, and Limitations, dated June 12, 2014 (incorporated herein by reference toExhibit 3.1 from the Company’s quarterly report on Form 10-Q for the quarter ended March 31, 2014, filed on June 17, 2014).3.6Certificate of Designation of 6% Redeemable Preferred Stock, dated August 29, 2014 (incorporated by reference to Exhibit 3.3 to the Company’squarterly report on Form 10-Q for the period ended June 30, 2014, filed on November 26, 2014).4.1Form of Warrant (incorporated 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 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 quarterly reporton 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).4.6Form of Warrant dated May 30, 2014 (incorporated herein by reference to Exhibit 10.2 from the Company’s current report on Form 8-K filed onJune 4, 2014).4.7Warrant to Purchase Common Stock issued to Bristol Capital (incorporated herein by reference to Exhibit 4.3 to the Company’s quarterly reporton Form 10-Q for the period ended June 30, 2014, filed on November 26, 2014). 76  4.8Warrant to Purchase Common Stock issued to Heartland Bank (incorporated herein by reference to Exhibit 4.3 to the Company’s quarterly reporton Form 10-Q, filed on February 26, 2015).4.9Form of Convertible Note (incorporated by reference to Exhibit 4.1 to the Company’s current report on Form 8-K filed on January 5, 2016).4.10Form of Warrant (incorporated by reference to Exhibit 4.1 to the Company’s current report on Form 8-K filed on January 5, 2016).10.1Form of Securities Purchase Agreement (incorporated herein by reference to Exhibit 10.1 to the Company’s current report on Form 8-K filed onJune 4, 2010).10.2Form of Registration Rights Agreement (incorporated herein by reference to Exhibit 10.2 to the Company’s current report on Form 8-K filed onJune 4, 2010).10.3Form of Convertible Debenture Securities Purchase Agreement dated February 2, 2011 (incorporated herein by reference to Exhibit 10.1 to theCompany’s current report on Form 8-K filed on February 3, 2011). 10.4Form of Convertible Debenture (incorporated herein by reference to Exhibit 10.2 to the Company’s current report on Form 8-K filed on February3, 2011).10.5Amendment to 8% Senior Secured Convertible Debentures dated December 16, 2011 (incorporated herein by reference to Exhibit 10.1 to theCompany’s current report on Form 8-K filed on December 19, 2011).10.6Second Amendment to 8% Senior Secured Convertible Debentures dated March 19, 2012 (incorporated herein by reference to Exhibit 10.56 to theCompany’s Annual Report on Form 10-K for the year ended December 31, 2011, filed on March 21, 2012).10.7Securities Purchase Agreement for additional 8% Senior Secured Convertible Debentures dated March 19, 2012 (incorporated herein by referenceto Exhibit 10.57 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2011, filed on March 21, 2012).10.8Form of 8% Senior Secured Convertible Debentures dated March 19, 2012 (incorporated herein by reference to Exhibit 10.58 to the Company’sAnnual Report on Form 10-K for the year ended December 31, 2011, filed on March 21, 2012).10.9Amendment to 8% Senior Secured Convertible Debenture and Waiver under Securities Purchase Agreement, dated July 23, 2012 (incorporatedherein by reference to Exhibit 10.35 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2013, filed on June 11,2014).10.10Amendment to Securities Purchase Agreement dated August 7, 2012 (incorporated herein by reference to Exhibit 10.1 to the Company’s currentreport on Form 8-K filed on August 9, 2012).10.11Amendment to Securities Purchase Agreement dated August 7, 2012 (incorporated herein by reference to Exhibit 10.2 to the Company’s currentreport on Form 8-K filed on August 9, 2012).10.12Amendment to 8% Senior Secured Convertible Debentures due February 8, 2014, dated April 15, 2013 (incorporated herein by reference toExhibit 10.56 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2013, filed on June 11, 2014).10.13Letter Agreement with Debenture Holder dated April 16, 2013 (incorporated herein by reference to Exhibit 10.39 to the Company’s AnnualReport on Form 10-K for the year ended December 31, 2013, filed on June 11, 2014).10.14Securities Purchase Agreement dated June 18, 2013 (incorporated herein by reference to Exhibit 10.1 to the Company’s quarterly report on Form10-Q for the quarter ended June 30, 2013, filed on August 15, 2013).10.15Form of Convertible Debenture (incorporated herein by reference to Exhibit 10.2 to the Company’s quarterly report on Form 10-Q for the quarterended June 30, 2013, filed on August 15, 2013).10.16Letter Agreement dated June 18, 2013 regarding 8% Senior Secured Debentures (incorporated herein by reference to Exhibit 10.3 to theCompany’s quarterly report on Form 10-Q for the quarter ended June 30, 2013, filed on August 15, 2013).10.17Debenture Conversion Agreement, dated as of January 31, 2014 (incorporated herein by reference to Exhibit 10.1 from the Company’s currentreport on Form 8-K filed on February 6, 2014).10.18Form of Subscription Agreement, dated January 22, 2014 (incorporated herein by reference to Exhibit 10.1 to the Company’s current report onForm 8-K filed on January 28, 2014.10.19Form of Hexagon Replacement Note (incorporated herein by reference to Exhibit 10.4 from the Company’s current report on Form 8-K filed onJune 4, 2014).10.20Letter Agreement dated May 19, 2014 with holders of the 8% Senior Secured Convertible Debentures (incorporated herein by reference to Exhibit10.1 to the Company’s quarterly report on Form 10-Q for the period ended March 31, 2014, filed on June 17, 2014). 77  10.21Amendment to Debentures dated June 6, 2014 (incorporated herein by reference to Exhibit 10.2 to the Company’s quarterly report on Form 10-Qfor the period ended March 31, 2014, filed on June 17, 2014).10.22Transaction Fee Agreement with T.R. Winston dated as of March 28, 2014 (incorporated herein by reference to Exhibit 10.6 to the Company’squarterly report on Form 10-Q for the period ended March 31, 2014, filed on June 17, 2014).10.23Amendment to Transaction Fee Agreement with T.R. Winston dated as of April 29, 2014 (incorporated herein by reference to Exhibit 10.7 to theCompany’s quarterly report on Form 10-Q for the period ended March 31, 2014, filed on June 17, 2014).10.24Engagement Agreement for Financial Advisory Services with MLV & Co. LLC dated as of February 21, 2014 (incorporated herein by reference toExhibit 10.8 to the Company’s quarterly report on Form 10-Q for the period ended March 31, 2014, filed on June 17, 2014).10.25†Consulting Agreement with Market Development Consulting Group, Inc. dated January 17, 2014 (incorporated herein by reference to Exhibit10.28 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2013, filed on June 11, 2014).10.26†Market Development Consulting Group, Inc. Termination letter, dated August 1, 2014 (incorporated herein by reference to Exhibit 10.15 to theCompany’s quarterly report on Form 10-Q for the period ended September 30, 2014, filed on February 26, 2015).10.27†Consulting Agreement with Bristol Capital dated September 2, 2014 (incorporated herein by reference to Exhibit 10.11 to the Company’squarterly report on Form 10-Q for the period ended June 30, 2014, filed on November 26, 2014).10.28Form of Securities Purchase Agreement dated May 30, 2014 (incorporated herein by reference to Exhibit 10.1 from the Company’s current reporton Form 8-K filed on June 4, 2014).10.29Hexagon Settlement Agreement, dated May 30, 2014 (incorporated herein by reference to Exhibit 10.3 from the Company’s current report onForm 8-K filed on June 4, 2014).10.30Settlement Agreement with Hexagon dated September 2, 2014 (incorporated herein by reference to Exhibit 10.10 to the Company’s quarterlyreport on Form 10-Q for the period ended June 30, 2014, filed on November 26, 2014).10.31Letter Agreement with holders of the Company’s 8% Senior Secured Convertible Debentures, dated October 6, 2014 (incorporated herein byreference to Exhibit 99.1 from the Company’s current report on Form 8-K filed on October 7, 2014).10.32Credit Agreement, dated January 8, 2015, among Lilis Energy, Inc., Heartland Bank, as administrative agent, and the other lender parties thereto(incorporated herein by reference to Exhibit 10.1 from the Company’s current report on Form 8-K filed on January 13, 2015).10.33Security Agreement, dated as of January 8, 2015, by and between Lilis Energy, Inc. and Heartland Bank, as collateral agent (incorporated hereinby reference to Exhibit 10.12(a) from the Company’s quarterly report on Form 10-Q for the period ended September 30, 2014, filed on February26, 2015).10.34Form of Promissory Note from Lilis Energy, Inc. as Borrower to Heartland Bank as Payee, dated as of January 8, 2015 (incorporated herein byreference to Exhibit 10.12(b) from the Company’s quarterly report on Form 10-Q for the period ended September 30, 2014, filed on February 26,2015).10.35Subordination Agreement, dated as of January 8, 2015 (incorporated herein by reference to Exhibit 10.12(c) from the Company’s quarterly reporton Form 10-Q for the period ended September 30, 2014, filed on February 26, 2015).10.36Form of Mortgage from Lilis Energy, Inc. as Mortgagor to Heartland Bank as Mortgagee (Colorado Oil and Gas Properties) (incorporated herein byreference to Exhibit 10.12(d) from the Company’s quarterly report on Form 10-Q for the period ended September 30, 2014, filed on February 26,2015).10.37Form of Mortgage from Lilis Energy, Inc. as Mortgagor to Heartland Bank as Mortgagee (Nebraska Oil and Gas Properties) (incorporated herein byreference to Exhibit 10.12(e) from the Company’s quarterly report on Form 10-Q for the period ended September 30, 2014, filed on February 26,2015).10.38Form of Mortgage from Lilis Energy, Inc. as Mortgagor to Heartland Bank as Mortgagee (Wyoming Oil and Gas Properties) (incorporated hereinby reference to Exhibit 10.12(f) from the Company’s quarterly report on Form 10-Q for the quarter ended September 30, 2014, filed on February26, 2015).10.39Letter Agreement with holders of the Company’s 8% Senior Secured Convertible Debentures (incorporated herein by reference to Exhibit 10.13 tothe Company’s quarterly report on Form 10-Q for the period ended September 30, 2014, filed on February 26, 2015). 78  10.40†Separation Agreement with W. Phillip Marcum dated April 24, 2014 (incorporated herein by reference to Exhibit 10.3 to the Company’squarterly report on Form 10-Q for the period ended March 31, 2014, filed on June 17, 2014).10.41†Employment Agreement with Robert A. Bell dated May 1, 2014 (incorporated herein by reference to Exhibit 10.4 to the Company’s quarterlyreport on Form 10-Q for the period ended March 31, 2014, filed on June 17, 2014).10.42†Independent Director Appointment Agreement with Robert A. Bell effective March 1, 2014 (incorporated herein by reference to Exhibit 10.55to the Company’s Annual Report on Form 10-K for the year ended December 31, 2013, filed on June 11, 2014).10.43†Separation Agreement with Robert A. Bell dated August 1, 2014 (incorporated herein by reference to Exhibit 10.9 to the Company’s quarterlyreport on Form 10-Q for the period ended June 30, 2014, filed on November 26, 2014).10.44†Employment Agreement with Eric Ulwelling, dated as of February 19, 2015 (incorporated herein by reference to Exhibit 10.14 to theCompany’s quarterly report on Form 10-Q for the period ended September 30, 2014, filed on February 26, 2015).10.45†Stock Option Award Agreement with Eric Ulwelling, dated April 14, 2015 (incorporated herein by reference to Exhibit 10.81 to the Company’sAnnual Report on Form 10-K for the year ended December 31, 2014, filed on April 15, 2015).10.46†Employment Agreement with Kevin Nanke, dated March 6, 2015 (incorporated herein by reference to Exhibit 10.1 to the Company’s currentreport on Form 8-K filed on March 12, 2015).10.47†Stock Option Award Agreement with Kevin Nanke, dated April 14, 2015 (incorporated herein by reference to Exhibit 10.83 to the Company’sAnnual Report on Form 10-K for the year ended December 31, 2014, filed on April 15, 2015).10.48†Employment Agreement with Ariella Fuchs, dated March 16, 2015 (incorporated herein by reference to Exhibit 10.84 to the Company’s AnnualReport on Form 10-K for the year ended December 31, 2014, filed on April 15, 2015).10.49†Stock Option Award Agreement with Ariella Fuchs, dated April 14, 2015 (incorporated herein by reference to Exhibit 10.85 to the Company’sAnnual Report on Form 10-K for the year ended December 31, 2014, filed on April 15, 2015).10.50†Amended and Restated Employment Agreement between the Company and Abraham Mirman, dated March 30, 2015 (incorporated herein byreference to Exhibit 10.1 to the Company’s current report on Form 8-K filed on April 2, 2015).10.51†Stock Option Award Agreement with Abraham Mirman, dated April 14, 2015 (incorporated herein by reference to Exhibit 10.87 to theCompany’s Annual Report on Form 10-K for the year ended December 31, 2014, filed on April 15, 2015).10.52†Form of Non-Employee Director Award Agreement (incorporated herein by reference to Exhibit 10.2 to the Company’s quarterly report on Form10-Q for the period ended June 30, 2015, filed on August 19, 2015) Form of Non-Employee Director Stock Option Award Agreement (incorporated herein by reference to Exhibit 10.2 to the Company’s quarterlyreport on Form 10-Q for the period ended June 30, 2015, filed on August 19, 2015)10.53†Recovery Energy, Inc. 2012 Equity Incentive Plan dated August 31, 2012, as amended (incorporated by reference to Annex A to the Company’sdefinitive proxy filed on December 15, 2015).10.54Voting Agreement, dated as of December 29, 2015 between 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).10.55Voting Agreement, dated as of December 29, 2015 between 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).10.56Debenture Conversion Agreement, dated as of December 29, 2015 between Lilis Energy, Inc., T.R. Winston and 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). 79  10.57Forbearance Agreement, dated as of December 29, 2015, between Lilis Energy, Inc. and Heartland Bank, as administrative agent (incorporatedherein by reference to Exhibit 10.4 to the Company’s current report on Form 8-K filed on January 5, 2016).10.58First Amendment to the Forbearance Agreement, dated as of March 1, 2016 between Lilis Energy, Inc. and Heartland Bank, as administrativeagent (incorporated herein by reference to Exhibit 10.4 to the Company’s current report on Form 8-K filed on March 7, 2016)10.59Form of Convertible Note Purchase Agreement (incorporated herein by reference to Exhibit 10.5 to the Company’s current report on Form 8-Kfiled on January 5, 2016).10.60Form 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). 21.1List of subsidiaries of the registrant.23.1Consent of Marcum LLP.23.2Consent of Forrest A Garb & Associates, Inc.31.1Certifications Pursuant to Section 302 of Sarbanes Oxley Act of 2002.31.2Certifications Pursuant to Section 302 of Sarbanes Oxley Act of 2002.32.1Certifications Pursuant to Section 906 of Sarbanes Oxley Act of 2002.32.2Certifications Pursuant to Section 906 of Sarbanes Oxley Act of 2002.99.1Report of Forrest A Garb & Associates, Inc.101.INSXBRL Instance Document101.SCHXBRL Taxonomy Extension Schema Document101.CALXBRL Taxonomy Extension Calculation Linkbase Document101.DEFXBRL Taxonomy Extension Definition Linkbase Document † Indicates a management contract or any compensatory plan, contract or arrangement. 80  REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Audit Committee of the Board of Directors and Stockholders of Lilis Energy, Inc. We have audited the accompanying balance sheets of Lilis Energy, Inc. (the “Company”) as of December 31, 2015 and 2014, and the related statements ofoperations, stockholders’ (deficit)/equity and cash flows for the years then ended. These financial statements are the responsibility of the Company’smanagement. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require thatwe plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is notrequired to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internalcontrol over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing anopinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includesexamining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used andsignificant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonablebasis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Lilis Energy, Inc., as of December 312015 and 2014, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in theUnited States of America. The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As more fully described in Note 2,the Company has a significant accumulated deficit, working capital deficit, incurred significant net losses and needs to raise additional funds to meet itsobligations and sustain its operations. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. Management’splans in regard to these matters are described in Note 2. The financial statements do not include any adjustments that might result from the outcome of thisuncertainty /s/ Marcum LLPMarcum llpNew York, NYApril 14, 2016 F-1  LILIS ENERGY, INC.BALANCE SHEETS December 31, December 31, 2015 2014 Assets Current assets: Cash $110,022 $509,628 Restricted cash 3,777 183,707 Accounts receivable (net of allowance of $80,000 at December 31, 2015 and 2014) 951,645 831,706 Prepaid assets 75,233 54,064 Total current assets 1,140,677 1,579,105 Oil and gas properties (full cost method), at cost: Evaluated properties 50,096,063 46,268,756 Unevaluated acreage, excluded from amortization - 2,885,758 Wells in progress, excluded from amortization - 6,041,743 Total oil and gas properties, at cost 50,096063 55,196,257 Less accumulated depreciation, depletion, amortization, and impairment (49,573,439) (24,550,217)Oil and gas properties at cost, net 522,624 30,646,040 Other assets: Office equipment net of accumulated depreciation $137,149 and $107,712 at December 31, 2015 and 2014,respectively. 44,386 73,823 Deferred financing costs, net 220,020 60,000 Restricted cash and deposits 2,000,406 215,541 Total other assets 2,264,812 349,364 Total Assets $3,928,113 $32,574,509 The accompanying notes are an integral part of these financial statements. F-2  LILIS ENERGY, INC.BALANCE SHEETS December 31, December 31, 2015 2014 Liabilities, Redeemable Preferred Stock and Stockholders' (Deficit)/EquityCurrent liabilities: Dividends accrued on preferred stock $720,000 180,000 Accrued expenses for drilling activity 535,938 5,734,131 Accounts payable 1,331,963 975,749 Accrued expenses 2,955,419 1,248,995 Convertible bridge notes, net of discount 673,739 - Convertible bridge notes – related parties, net of discount 1,054,552 - Term loan – Heartland, net of discount 2,712,089 - Convertible debentures, net of discount 6,846,465 - Convertible debentures conversion derivative liability 5,511 - Total current liabilities 16,835,676 8,138,875 Long term liabilities: Asset retirement obligation 207,953 200,063 Warranty liability 55,655 393,788 Convertible debentures, net of discount - 6,840,076 Convertible debentures conversion derivative liability - 1,249,442 Total long-term liabilities 263,608 8,683,369 Total liabilities 17,099,284 16,822,244 Commitments and contingencies Conditionally redeemable 6% preferred stock, $0.0001 par value: 7,000 shares authorized, 2,000 shares issued andoutstanding with a liquidation preference of $2,150,000 as of December 31, 2015. 1,172,517 1,686,102 Stockholders’ (deficit)/equity Series A Preferred stock, $0.0001 par value; stated rate $1,000:10,000,000 shares authorized, 7,500 issued andoutstanding with a liquidation preference of $8,040,000 as of December 31, 2015. 6,794,000 6,794,000 Common stock, $0.0001 par value: 100,000,000 shares authorized; 27,858,255 and 26,988,240 shares issued andoutstanding as of December 31, 2015 and December 31, 2014, respectively 2,786 2,699 Additional paid in capital 159,769,184 155,097,785 Accumulated deficit (180,909,658) (147,828,321)Total stockholders' (deficit)/equity (14,343,688) 14,066,163 Total Liabilities, Redeemable Preferred Stock and Stockholders’ (Deficit)/Equity $3,928,113 $32,574,509 The accompanying notes are an integral part of these financial statements. F-3  LILIS ENERGY, INC.STATEMENTS OF OPERATIONSYears Ended December 31, 2015 and 2014 2015 2014 Revenue: Oil sales $292,332 $2,581,689 Gas sales 77,068 364,732 Operating fees 26,664 182,773 Realized gain on commodity price derivatives - 11,143 Total revenue 396,064 3,140,337 Costs and expenses: Production costs 195,435 954,347 Production taxes 27,917 269,823 General and administrative 7,929,628 10,325,842 Depreciation, depletion and amortization 584,203 1,337,662 Impairment of evaluated oil and gas properties 24,478,378 - Total costs and expenses 33,215,561 12,887,675 Loss from operations before conveyance (32,819,497) (9,747,338)Loss on conveyance of oil and gas properties - (2,269,760)Loss from operations (32,819,497) (12,017,098) Other income (expenses): Other income 3,160 32,444 Inducement expense - (6,661,275)Change in fair value of convertible debentures conversion derivative liability 1,243,931 (5,526,945)Change in fair value of warrant liability 394,383 571,228 Change in fair value of conditionally redeemable 6% Preferred stock 513,585 - Interest expense (1,696,899) (4,837,025)Total other income (expenses) 458,160 (16,421,573) Net loss (32,361,337) (28,438,671)Dividend on Preferred stock (120,000) (341,848)Deemed dividend Series A Convertible Preferred stock (600,000) (3,519,370)Net loss attributable to common stockholders $(33,081,337) $(32,299,889) Net loss per common share basic and diluted $(1.21) $(1.23)Weighted average shares outstanding: Basic and diluted 27,267,749 26,333,161 The accompanying notes are an integral part of these financial statements F-4  LILIS ENERGY, INC.STATEMENTS OF STOCKHOLDERS’ (DEFICIT)/EQUITYYears Ended December 31, 2015 and 2014 Additional Preferred Stock Common Stock Paid-In Accumulated Shares Amount Shares Amount Capital Deficit Total Balance, January 1, 2014 - $- 19,671,901 $1,967 $121,451,232 $(115,528,432) $5,924,767 Common stock issued in connection with January 2014private placement - - 2,959,125 296 3,557,107 - 3,557,403 Fair value of warrants issued in connections withJanuary 2014 private placement including placementwarrants - - - - 1,678,596 - 1,678,596 Common stock issued in connection with January 2014conversion of convertible debt - - 4,366,726 437 8,733,001 - 8,733,438 Common stock issued for placement fees in connectionwith January 2014 conversion of convertible debt - - 225,000 23 686,227 - 686,250 Fair value of inducement expense in connection withdebenture conversion - - - - 6,661,275 - 6,661,275 Reclassification of conversion liability in connectionwith January 2014 conversion of convertible debt - - - 4,882,815 - 4,882,815 Preferred stock issued in connection with May 2014private placement, net 7,500 6,794,000 - - - - 6,794,000 Fair value of warrant and beneficial conversion featurein connection with May 2014 private placement - - - - 3,519,370 (3,519,370) - Common stock issued for interest in connection withconvertible debt outstanding - - 1,396,129 140 1,188,299 - 1,188,439 Common shares issued for restricted stock vested - - 327,901 32 (32) - - Stock based compensation for issuance of restrictedstock - - - - 514,804 - 514,804 Stock based compensation for issuance of stock options - - - - 1,242,256 - 1,242,256 Common stock issued for professional services - - 90,000 9 305,040 - 305,049 Fair value of warrants issued for professional services - - - - 677,590 - 677,590 Adjustment for restricted stock not vested - - (2,048,542) (205) 205 - - Dividend Preferred stockholders - - - - - (341,848) (341,848)Net Loss - - - - - (28,438,671) (28,438,671) Balance, December 31, 2014 7,500 6,794,000 26,988,240 2,699 155,097,785 (147,828,321) 14,066,163 Common stock issued for professional services - - 75,000 7 149,993 - 150,000 Common stock issued for officer and boardcompensation - - 795,015 80 214,922 - 215,002 Fair value of warrants issued for professional services - - - - 424,636 - 424,636 Fair value of warrants issued for bridge term loan - - - - 476,261 - 476,261 Fair value of warrants issued for bridge term loan –related parties - - - - 745,450 - 745,450 Stock based compensation for issuance of stock options - - - - 2,191,274 - 2,191,274 Stock based compensation for issuance of restrictedstock - - - - 468,863 - 468,863 Dividend Preferred stockholders - - - - - (120,000) (120,000)Deemed dividend Series A Convertible Preferred stock - - - - - (600,000) (600,000)Net loss - - - - - (32,361,337) (32,361,337)Balance, December 31, 2015 7,500 $6,794,000 27,858,255 $2,786 $159,769,184 $(180,909,658) $(14,343,688) The accompanying notes are an integral part of these financial statements. F-5  LILIS ENERGY, INC.STATEMENTS OF CASH FLOWSYears Ended December 31, 2015 and 2014 Year ended December 31, 2015 2014 Cash flows from operating activities: Net loss $(32,361,337) $(28,438,671)Adjustments to reconcile net loss to net cash used in operating activities: Inducement expense - 6,661,275 Common stock issued to investment bank for fees related to conversion of convertible debentures - 686,250 Equity instruments issued for services and compensation 3,449,775 2,739,699 Reserve on bad debt expense - 30,000 Loss on conveyance of property - 2,269,760 Loss from hedge settlements - 11,143 Change in fair value of price derivative (4,464)Change in fair value of executive incentive bonus 33,508 (105,000)Amortization of deferred financing cost 27,391 234,699 Common stock issued for convertible note interest - 1,188,439 Change in fair value of convertible debenture conversion derivative (1,243,931) 5,526,945 Change in fair value of warrant liability (394,383) (571,228)Change in fair value of conditionally redeemable 6% Preferred stock (513,585) 965,016 Depreciation, depletion, amortization and accretion of asset retirement obligation 584,203 1,337,662 Impairment of evaluated oil and gas properties 24,478,378 - Accretion of debt discount 24,728 849,147 Changes in operating assets and liabilities: Accounts receivable (119,939) (394,369)Restricted cash 145,065 320,916 Other assets 57,728 141,652 Accounts payable and other accrued expenses 2,027,098 (755,108)Net cash used in operating activities (3,805,301) (7,306,237) Cash flows from investing activities: Acquisition of undeveloped acreage - (305,000)Drilling capital expenditures (97,999) (190,786)Additions of office equipment - (10,815)Deposit on potential merger (1,750,000) - Net cash used in investing activities (1,847,999) (506,601) Cash flows from financing activities: Net proceeds from issuance of Common Stock - 5,236,000 Proceeds from issuance of debt 5,950,002 - Net proceeds from issuance of Series A Convertible Preferred Stock - 6,794,000 Debt issuance cost (266,308) - Dividend payments on Preferred stock (180,000) (161,848)Repayment of debt (250,000) (3,711,051)Net cash provided by financing activities 5,253,694 8,157,101 Increase (decrease) in cash (399,606) 344,263 Cash at beginning of year 509,628 163,365 CASH AT END OF YEAR $110,022 $509,628 Supplemental disclosure: Cash paid for interest $365,303 $1,324,988 Cash paid for income taxes $- $- Non-cash transactions: Fair value of warrants issued as debt discount $1,221,711 $- Disposition of oil and gas assets for elimination of accrued expenses for drilling $5,198,193 $- Common stock issued for accrued convertible debenture interest $- $1,188,439 Acquisition of oil and gas assets for accounts payable and accrued interest $- $5,466,405 Transfer from derivative liability to equity $- $4,882,815 Issuance of Common Stock for payment of convertible debentures $- $8,733,438 Issuance of redeemable preferred stock for payment of term notes payable $- $1,686,102 Conveyance of oil and gas properties for payment of term notes payable $- $15,063,289 Conveyance of oil and gas properties for reduction in asset retirement obligation $- $973,132 The accompanying notes are an integral part of these financial statements.  F-6  LILIS ENERGY, INC.NOTES TO THE FINANCIAL STATEMENTS NOTE 1 – ORGANIZATION On September 21, 2009, 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”, “we”, “our”, and the “Company”).The acquisition was accounted for as a reverse acquisition with Coronado being treated as the acquirer for accounting purposes. Accordingly, the financialstatements of Coronado and Recovery Energy have been adopted as the historical financial statements of Lilis. The Company is an independent oil and gas exploration and production company focused on the Denver-Julesburg Basin (“DJ Basin”) where it holds 16,000net acres. Lilis drills for, operates and produces oil and natural gas wells through the Company’s land holdings located in Wyoming, Colorado, and Nebraska. All references to production, sales volumes and reserves quantities are net to the Company’s interest unless otherwise indicated. NOTE 2 – GOING CONCERN AND MANAGEMENT PLANS The Company’s financial statements for the year ended December 31, 2015 have been prepared on a going concern basis. The Company has reported netoperating losses during the year ended December 31, 2015 and for the past five years. This history of operating losses, along with the recent decrease incommodity prices, may adversely affect the Company’s ability to access capital it needs to continue operations. These factors raise substantial doubt aboutthe Company’s ability to continue as a going concern. The accompanying financial statements do not include any adjustments relating to the recoverabilityand classification of recorded asset amounts, or amounts of liabilities, that might result from this uncertainty. We will need to raise additional funds to finance continuing operations. However, we may not be successful in doing so. Without sufficient additionalfinancing, it would be unlikely for us to continue as a going concern. Our ability to continue as a going concern is dependent upon our ability to successfullyaccomplish our business plan and eventually secure other sources of financing and attain profitable operations. Information about our year-end financial position is presented in the following table (in thousands): Year ended December 31, 2015 2014 Financial Position Summary Cash and cash equivalents $110 $510 Working capital (deficit) $(15,695) $(6,560)Balance outstanding on convertible debentures, convertible notes payable and term loan $11,317 $6,840 Stockholders’ (deficit)/equity $(14,344) $14,067 As of December 31, 2015, the Company had a negative working capital balance and a cash balance of approximately $15.7 million and $110,000,respectively. As of March 30, 2016, the Company’s cash balance was approximately $50,000. The Company has historically financed its operations throughthe sale of debt and equity securities and borrowings under credit facilities with financial institutions. For a complete description of the Company’s indebtedness, see Note 7 — Loan Agreements. F-7  Development and Production During the year ended December 31, 2015, the Company transferred $847,000 from wells-in progress to developed oil and natural gas properties. Thisincluded approximately $491,000 from a well currently producing in Northern Wattenberg and approximately $356,000 of cost incurred for projects that theCompany no longer plans to pursue. During the year ended December 31, 2015, the Company entered into five joint operating agreements to participate as a non-operator in the drilling of fivehorizontal wells. The Company has an average of 2.78% working interest in each of these wells which are being drilled by reliable companies. However, dueto capital constraints, the Company expects that it will be put into non-consent status on each of these wells unless other arrangements can be made. Additionally, as of March 30, 2016, the Company was producing approximately 20 BOE a day from eight economically producing wells. Due to a decline incommodity prices, the cash generated from the Company’s production activity is not sufficient to pay its operating costs and the Company does not havesufficient cash to continue operations in the ordinary course. Proposed Merger with Brushy Resources On December 29, 2015, the Company entered into the Merger Agreement, which is described in more detail under “Business and Properties—Pending Mergerwith Brushy Resources.” Among other conditions to the Merger, the Company is required to repay its Term Loan in full, convert the $6.85 millionoutstanding under its Debentures into Common Stock at $0.50 and convert $7.5 million of its outstanding Series A Preferred Stock into Common Stock at$0.50. In addition, Brushy will have to repay, refinance or negotiate alternative terms with its senior lender prior to completing the Merger. The Company believes that if the Merger is successfully completed, it will substantially increase its producing properties resulting in significantly greatercash flow while eliminating or refinancing its existing indebtedness. The Company will however be required to obtain significant additional capital to payoutstanding debt obligations, pay professional fees related to the Merger, pay outstanding payables in the ordinary course and to fund the combinedcompany’s working capital requirements. While the Company expects to raise additional capital to fund all of these obligations, the current volatility in thecommodity markets has made it difficult for oil and gas exploration companies, including the Company, to access debt or equity financing or obtainborrowings from financial lenders. If the Company is unable to complete the Merger or otherwise obtain significant capital, it will likely not be able to continue its current operations andwould have to consider other alternatives to preserve value for the Company’s stockholders. These alternatives could include engaging in discussions toacquire other producing properties, selling or disposing of some or all of the Company’s assets or a liquidation of its business. NOTE 3 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND ESTIMATES Basis of Presentation The accompanying financial statements were prepared by the Company in accordance with generally accepted accounting principles in the United States(“U.S. GAAP”). The financial statements reflect all normal recurring adjustments which are, in the opinion of management, necessary to provide a fairstatement of the results of operations and financial position. Use of Estimates The preparation of financial statements in conformity with U.S. GAAP requires the Company 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. Although actual results may differ from these estimates under different assumptions or conditions, the Company believes that its estimates arereasonable. F-8  The most significant financial estimates are associated with the Company’s estimated volumes of proved oil and natural gas reserves, asset retirementobligations, 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. Restricted Cash and Deposits Short term restricted cash consists of severance and ad valorem tax proceeds which are payable to various tax authorities. As of December 31, 2015 and 2014,the short-term deposits were approximately $4,000 and $184,000, respectively. At December 31, 2015 and 2014, the Company had $215,000 of non-currentrestricted cash for plugging bonds. Long term restricted cash and deposits consist of a $1.75 million deposit for the proposed merger with Brushy described inmore detail below, plugging bonds and other deposits. As of December 31, 2015 and 2014 the long-term deposits were approximately $2.0 million and$216,000, respectively. Accounts Receivable The Company records actual and estimated oil and gas revenue receivable from third parties at its net revenue interest. The Company also reflects costsincurred 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, 2015 and 2014, the Company’s cash wasmaintained in accounts that are insured up to the limit determined by the federal governmental agency. The Company may at times have balances in excessof the federally insured limits. Periodically, the Company evaluates the creditworthy of the financial institutions, and has not experienced any losses in suchaccounts. Significant Customers The Company’s major customers include, Shell Trading (US), PDC Energy and Noble Energy. These customers accounted for approximately 43%, 26% and21% for the year ended December 31, 2015 and approximately 63%, 14% and 9% for the year ended December 31, 2014, respectively. However, the Company does not believe that the loss of a single purchaser would materially affect the Company’s business because there are numerous otherpurchasers in the area in which the Company sells its production. 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 SEC, including rule revisions designed to modernize the oil and gas company reserves reporting requirements, which theCompany implemented effective December 31, 2010. Reservoir engineering is a subjective process of estimating underground accumulations of crude oiland natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Uncertainties include theprojection of future production rates and the expected timing of development expenditures. The accuracy of any reserves estimate is a function of the qualityof available data and of engineering and geological interpretation and judgment. As a result, reserves estimates may be different from the quantities of crudeoil and natural gas that are ultimately recovered. In addition, the ability to produce economic reserves is dependent on the oil and gas prices used in thereserves estimate. The Company’s reserves estimates are based on 12-month average commodity prices, unless contractual arrangements otherwise designatethe 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 changein the future. F-9  Estimates of proved crude oil and natural gas reserves significantly affect the Company’s depreciation, depletion, and amortization “DD&A” expense. Forexample, if estimates of proved reserves decline, the DD&A rate will increase, resulting in a decrease in net income. A decline in estimates of proved reservescould also result in an impairment charge, which would reduce earnings. Oil and Gas Producing Activities The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration, non-production relateddevelopment and acquisition of oil and natural gas reserves are capitalized. Such costs include land acquisition costs, geological and geophysical expenses,carrying charges on non-producing properties, costs of drilling, developing and completing productive wells and/or plugging and abandoning non-productive wells, and any other costs directly related to acquisition and exploration activities. Proceeds from property sales are generally applied as a creditagainst capitalized exploration and development costs, with no gain or loss recognized, unless such a sale would significantly alter the relationship betweencapitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of proved reserves. The Company accounts for its unproven long-lived assets in accordance with Accounting Standards Codification (“ASC”) Topic 360-10-05, Accounting forthe Impairment or Disposal of Long-Lived Assets. ASC Topic 360-10-05 requires that long-lived assets be reviewed for impairment whenever events orchanges 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-production methodbased upon estimated proved oil and gas reserves. Costs included in the depletion base to be amortized include (a) all proved capitalized costs includingcapitalized asset retirement costs net of estimated salvage values, less accumulated depletion, (b) estimated future development cost to be incurred indeveloping proved reserves; and (c) estimated decommissioning and abandonment/restoration costs, net of estimated salvage values, that are not otherwiseincluded in capitalized costs. The costs of undeveloped acreage are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties.When proved reserves are assigned to such properties or one or more specific properties are deemed to be impaired, the cost of such properties or the amountof the impairment is 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 may not exceedan 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 cost ofunproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are notsubject to amortization. Should capitalized costs exceed this ceiling, an impairment expense is recognized. During the year ended December 31, 2015, theCompany recorded a $24.5 million impairment. No impairment was recorded in 2014. The present value of estimated future net cash flows was computed by applying: a flat oil price to forecast revenues from estimated future production ofproved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves (assuming thecontinuation of existing economic conditions), less any applicable future taxes. Effective as of December 31, 2014, the Company completed an assessment of its inventory of unevaluated acreage, which resulted in a transfer of $9.90million from unevaluated acreage to evaluated properties. In assessing the unevaluated acreage, the Company analyzed the expiration dates during the yearsended December 31, 2014 and 2015 of leases that are not otherwise renewable, and transferred such acreage in the amount of $6.99 million. In addition to thetransfer of near and intermediate term expirations, the Company assessed the carrying value of its remaining acreage, and concluded that an additionaltransfer of $2.91 million was necessary. No proved reserves were associated with the transferred acreage. F-10  Due to the decline in commodity prices, the Company incurred a full cost ceiling impairment in the year ended December 31, 2015. Because the ceilingcalculation uses rolling 12-month average commodity prices, lower quarter-over-quarter prices in 2015 compared to 2014 resulted in a lower ceiling valueeach quarter. Impairment charges do not affect cash flow from operating activities, but have and could continue to adversely affect the Company’s net incomeand stockholders’ equity. During the year ended December 31, 2015, the Company transferred its remaining inventory of unevaluated acreage of $2.9 million to evaluated properties. Wells in Progress Wells in progress connotes wells that are currently in the process of being drilled or completed or otherwise under evaluation as to their potential to produceoil and gas reserves in commercial quantities. Such wells continue to be classified as wells in progress and withheld from the depletion calculation and theceiling test until such time as either proved reserves can be assigned, or the wells are otherwise abandoned. Upon either the assignment of proved reserves orabandonment, the costs for these wells are then transferred to the full cost pool and become subject to both depletion and the ceiling test calculations inaccordance with full cost accounting under Rule 4-10 of Regulation S-X of the Securities Exchange Act of 1934, as amended. Deferred Financing Costs As of December 31, 2015 and 2014, the Company recorded unamortized deferred financing costs of $220,000 and $60,000, respectively, related to theclosing of its term loans and credit agreements. Deferred financing costs include origination (cash and warrants), legal and engineering fees incurred inconnection with the Company's term notes, which are being amortized using the straight-line method, which approximated interest rate method, over the termof the loans. The Company recorded amortization expense of approximately $27,000 and $295,000, respectively, in the years ended December 31, 2015 and2014. Property and Equipment Property and equipment are stated at cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets. Theestimated useful lives of property and equipment range from one to seven years. The Company recorded approximately $29,000 and $28,000 of depreciationfor the years ended December 31, 2015 and 2014, respectively. Impairment of Long-lived Assets The Company accounts for long-lived assets (other than oil and gas properties) at cost. Other long-lived assets consist principally of property and equipmentand identifiable intangible assets with finite useful lives (subject to amortization, depletion, and depreciation). The Company may impair these assetswhenever events or changes in circumstances indicate that the carrying amount of such assets may not be fully recoverable. Recoverability is measured bycomparing the carrying amount of an asset to the expected undiscounted future net cash flows generated by the asset. If it is determined that the asset may notbe recoverable, and if the carrying amount of an asset exceeds its estimated fair value, an impairment charge is recognized to the extent of the difference. Fair Value of Financial Instruments As of December 31, 2015 and 2014, the carrying value of cash and cash equivalents, accounts receivable, accounts payable, accrued expenses, interest anddividends payable and customer deposits approximates fair value due to the short-term nature of such items. The carrying value of the Company’s secureddebt is carried at cost as the related interest rate are at the terms approximates rates currently available to the Company. F-11  Commodity Derivative Instrument The Company utilizes swaps to reduce the effect of price changes on a portion of its future oil production. On a monthly basis, a swap requires the Companyto pay the counterparty if the settlement price exceeds the strike price and the same counterparty is required to pay the Company if the settlement price is lessthan the strike price. The objective of the Company's use of derivative financial instruments is to achieve more predictable cash flows in an environment ofvolatile oil and gas prices and to manage its exposure to commodity price risk. While the use of these derivative instruments limits the downside risk ofadverse price movements, such use may also limit the Company's ability to benefit from favorable price movements. The Company may, from time to time,add incremental derivative contracts to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify theterms of current contracts in order to realize the current value of the Company's existing positions. The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. TheCompany's derivative contracts have typically been arranged with one counterparty. The Company has netting arrangements with this counterparty thatprovide for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination. Thederivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement. The Company periodicallyenters into various commodity derivative financial instruments intended to hedge against exposure to market fluctuations of oil prices. As of December 31,2015 and 2014, the Company did not have any commodity derivative instruments outstanding. Revenue Recognition The Company records revenues from the sales of crude oil, natural gas and natural gas liquids when the product is delivered at a fixed or determinable price,title has transferred and collectability is reasonably assured. Oil and Natural Gas Revenue Sales of oil and natural gas, net of any royalties, are recognized when persuasive evidence of a sales arrangement exists, oil and natural gas have beendelivered to a custody transfer point, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale isreasonably assured, and the sales price is fixed or determinable. Virtually all of the Company’s contracts’ oil and natural gas pricing provisions are tied to aNYMEX market index, with certain local differential adjustments based on, among other factors, whether a well delivers oil or natural gas to a gathering,refinery, marketing company, or transmission line and prevailing local supply and demand conditions. The price of the oil and natural gas fluctuates toremain competitive with other local oil suppliers. 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 recorded asliabilities on a discounted basis. The costs associated with these liabilities are capitalized as part of the related assets and depreciated. Over time, theliabilities are accreted for the change in their present value. For purposes of depletion calculations, the Company also includes estimated dismantlement and abandonment costs, net of salvage values, associated withfuture 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. As of December 31, 2015 and 2014, the Company recorded a related liability of approximately$208,000 and $200,000, respectively. F-12  The information below reconciles the value of the asset retirement obligation for the periods presented (in thousands): For the years ended December 31, 2015 2014 Balance, beginning of year $200 $1,105 Liabilities incurred - 4 Accretion expense 10 64 Conveyance of liability with oil and gas properties conveyance - (973)Change in estimate (2) - Balance, end of year $208 $200 Stock Based Compensation The Company measures the fair value of stock-based compensation expense awards made to employees and directors, including stock options, restrictedstock units, restricted stock and employee stock purchases related to employee stock purchase plans, on the date of grant using a Black-Scholesmodel. Restricted stock awards are recorded at the fair market value of the stock on the date of grant. The value of the portion of the award that is ultimatelyexpected to vest is recognized as an expense ratably over the requisite service periods. The measurement of share-based compensation expense is based onseveral criteria, including but not limited to the valuation model used and associated input factors, such as expected term of the award, stock price volatility,risk free interest rate, dividend rate and award cancellation rate. These inputs are subjective and are determined using management’s judgment. If differencesarise between the assumptions used in determining share-based compensation expense and the actual factors, which become known over time. The Companymay change the input factors used in determining future share-based compensation expense. The Company accounts for warrant grants to non-employees whereby the fair values of such warrants are determined using the option pricing model at theearlier of the date at which the non-employee’s performance is complete or a performance commitment is reached. 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 the excess, ifany, of the fair value of the modified award over the fair value of the original award immediately before modification, and is either expensed as a periodexpense or amortized over the performance or vesting date. The Company estimates the incremental value of each warrant using the Black-Scholes optionpricing 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. Net Loss per Common Share Earnings (losses) per share are computed based on the weighted average number of common shares outstanding during the period presented. Diluted earningsper share are computed using the weighted-average number of common shares outstanding plus the number of common shares that would be issued assumingexercise or conversion of all potentially dilutive common shares. Potentially dilutive securities, such as shares issuable upon the conversion of debt or preferred stock, and exercise of stock purchase warrants and options, areexcluded from the calculation when their effect would be anti-dilutive. As of December 31, 2015 and 2014 shares underlying options, warrants, preferredstock and convertible debentures have been excluded from the diluted share calculations as they were anti-dilutive as a result of net losses incurred. F-13  The Company had the following Common Stock equivalents at December 31, 2015 and 2014: December 31,2015 December 31,2014 Stock Options 6,083,333 3,583,333 Restricted Stock Units (employees/directors) 1,869,000 1,630,667 Series A Preferred Stock 3,112,033 3,112,033 Stock Purchase Warrants 24,383,161 17,007,065 Convertible Debentures 3,423,233 3,423,233 Convertible Bridge Notes 5,900,004 - 44,770,764 28,756,311 Income Taxes The Company uses the asset and liability method in accounting for income taxes. Deferred tax assets and liabilities are recognized for temporary differencesbetween financial statement carrying amounts and the tax bases of assets and liabilities, and are measured using the tax rates expected to be in effect when thedifferences reverse. Deferred tax assets are also recognized for operating loss and tax credit carry forwards. The effect on deferred tax assets and liabilities of achange in tax rates is recognized in the results of operations in the period that includes the enactment date. A valuation allowance is used to reduce deferredtax 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 amountrecognized is measured as the largest amount of benefit that is greater than 50 percent likely to be realized upon settlement. A liability for “unrecognized taxbenefits” is recorded for any tax benefits claimed that do not meet these recognition and measurement standards. As of December 31, 2015 and 2014, theCompany has determined that no liability is required to be recognized. The Company’s policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense. No interest or penalties wererequired to be accrued at December 31, 2015 and December 31, 2014. Further, the Company does not expect that the total amount of unrecognized taxbenefits will significantly increase or decrease during the next 12 months. Recently Issued Accounting Pronouncements In May 2014, the FASB issued ASU No. 2014-09 (“ASU 2014-09”), “Revenue from Contracts with Customers,” which requires an entity to recognizerevenue representing the transfer of promised goods or services to customers in an amount that reflects the consideration which the company expects toreceive in exchange for those goods or services. ASU 2014-09 is intended to establish principles for reporting useful information to users of financialstatements about the nature, amount, timing and uncertainty of revenues and cash flows arising from the entity’s contracts with customers. ASU 2014-09 willreplace most existing revenue recognition guidance in GAAP when it becomes effective. The new standard is effective for us on January 1, 2018. Earlyapplication is only permitted as of January 1, 2017. The Company is currently evaluating the effect that ASU 2014-09 will have on its financial statementsand related disclosures. In June 2014, the FASB issued ASU No. 2014-12 (“ASU 2014-12”), “Accounting for Share-Based Payments When the Terms of an Award Provide That aPerformance Target Could Be Achieved after the Requisite Service Period,” which requires a performance target that affects vesting, and that could beachieved after the requisite service period, be treated as a performance condition. ASU 2014-12 states that the performance target should not be reflected inestimating the grant date fair value of the award. ASU 2014-12 clarifies that compensation cost should be recognized in the period in which it becomesprobable that the performance target will be achieved and should represent the periods for which the requisite service has already been rendered. The newstandard is effective for us on January 1, 2016. The Company does not expect adoption of ASU 2014-12 to have a significant impact on its financialstatements. In August 2014, the FASB issued ASU No. 2014–15 (“ASU 2014-15”), “Presentation of Financial Statements – Going Concern.” ASU 2014-15 providesGAAP guidance on management’s responsibility in evaluating whether there is substantial doubt about a company’s ability to continue as a going concernand about related footnote disclosures. For each reporting period, management will be required to evaluate whether there are conditions or events that raisesubstantial doubt about a company’s ability to continue as a going concern within one year from the date the financial statements are issued. The newstandard is effective for us on January 1, 2017. The Company does not expect the adoption of ASU 2014–15 to have a significant impact on its financialstatements. F-14  In November 2014, the FASB issued ASU No. 2014-16 (“ASU 2014-16”), “Derivative and Hedging (Topic 815).” ASU 2014-16 addresses whether the hostcontract in a hybrid financial instrument issued in the form of share should be accounted for as debt or equity. ASU 2014-16 is effective for fiscal years, andinterim periods within those fiscal years, beginning after December 15, 2015. The Company does not expect the adoption of ASU 2014–16 to have asignificant impact on its financial statements. In April 2015, the FASB issued ASU No. 2015-03 (“ASU 2015-03”), “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of DebtIssuance Costs.” ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deductionfrom the carrying amount of the related debt liability, consistent with debt discounts, instead of being presented as an asset. ASU 2015-03 is effective for uson January 1, 2016. Once adopted, entities are required to apply the new guidance retrospectively to all prior periods presented. The retrospective applicationrepresents a change in accounting principle. Early adoption is permitted for financial statements that have not been previously issued. The Company doesnot expect the adoption of ASU 2015-03 to have a significant impact on its financial statements. In May 2015, the FASB issued ASU No. 2015-07 (“2015-07”), “Fair Value Measurement.” ASU 2015-07 removes the requirement to categorize within thefair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. The amendments also remove therequirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practicalexpedient. ASU 2015-07 is effective for us on January 1, 2016. Early adoption is permitted. The Company does not expect the adoption of ASU 2015–07 tohave a significant impact on its financial statements. In September 2015, the FASB issued ASU No. 2015-16 (“ASU 2015-16”), “Business Combinations (Topic 805), Simplifying the Accounting forMeasurement-Period Adjustments”. 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. ASU 2015-16 is effective for us on January 1, 2016. The adoption of this standard is notexpected to have a material impact on the Company’s financial statements. In November 2015, the FASB has issued an update to ASU No. 2015-17 (“ASU 2015-17”) “Income Taxes (Topic 740): Balance Sheet Classification ofDeferred Taxes.” The update requires a company to classify all deferred tax assets and liabilities as noncurrent. The update of ASU 2015-17 is effective for uson January 1, 2018. The Company does not expect the adoption of the update of ASU 2015–17 to have a significant impact on its financial statements. In January 2016, the FASB issued ASU No. 2016-01 (“ASU 2016-01”), “Financial Instruments – Overall (Subtopic 825-10)”. ASU 2016-01 updates certainaspects of recognition, measurement, presentation and disclosure of financial instruments. The new guidance is effective for us on January 1, 2018. TheCompany does not expect the adoption of ASU 2016–01 to have a significant impact on its financial statements. In February 2016, the FASB issued ASU No. 2016-02 (“ASU 2016-02), “Leases (Topic 842).” ASU 2016-02 requires a lessee to recognize a lease liability forthe obligation to make lease payments and a right-to-use asset for the right to use the underlying asset for the lease term. ASU 2016-02 is effective for us onJanuary 1, 2019. Early adoption is permitted. The Company is currently evaluating the effect that ASU 2016-02 will have on its financial statements andrelated disclosures. F-15  In March 2016, the FASB issued ASU No. 2016-06 (“ASU 2016-06”), “Contingent Put and Call Option in Debt Instruments”. ASU 2016-06 is intended tosimplify the analysis of embedded derivatives for debt instruments that contain contingent put or call options. The amendments in ASU 2016-06 clarify thatan entity is required to assess the embedded call or put options solely in accordance with the four-step decision sequence. Consequently, when a call (put)option is contingently exercisable, an entity does not have to initially assess whether the event that triggers the ability to exercise a call (put) option isrelated to interest rates or credit risks. The amendments in ASU 2016-06 take effect for public business entities for financial statements issued for fiscal yearsbeginning after December 15, 2016, and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. TheCompany does not expect the adoption of ASU 2016–01 to have a significant impact on its financial statements. Management does not believe that these or any other recently issued, but not yet effective accounting pronouncements, if adopted, would have a materialeffect on the accompanying condensed financial statements. NOTE 4 – OIL AND GAS PROPERTIES & OIL AND GAS PROPERTIES ACQUISITIONS AND DIVESTITURES The following table sets forth a summary of oil and gas property costs (net of divestitures) not being amortized as of December 31, 2015 and 2014 (inthousands): As of December 31, 2015 2014 Undeveloped unevaluated acreage Beginning Balance $2,886 $18,664 Lease purchases - 305 Assets Conveyed - (6,194)Transfer and other reclassification to evaluated properties (2,886) (9,889)Total undeveloped acreage $- $2,886 Wells in progress: Beginning Balance $6,042 $1,146 Additions - 5,412 Disposition of wells in progress for elimination of accrued expenses for drilling (5,198) - Reclassification to evaluated properties (844) (516)Total wells in progress and not subject to DD&A $- $6,042 During the year ended December 31, 2015, the Company did not buy or sell any of its oil and gas properties. Upon entering into the Credit Agreement, the Company believed we had secured adequate access to capital generally, and specifically, to fund the drillingand development of its proved undeveloped reserves. Due to the lack of liquidity that had been expected, but unavailable to the Company pursuant to theCredit Agreement, the Company recorded a $24.5 million impairment of its proved undeveloped and unproved properties during the year ended December31, 2015. No impairment was recorded in the year ended December 31, 2014. Depreciation, depletion and amortization (“DD&A”) expenses related to the proved properties were approximately $555,000 and $1.24 million for the yearsended December 31, 2015 and 2014, respectively. During the year ended December 31, 2015, the Company was put in non-consent status on three wells it agreed to participate in within the NorthernWattenberg field which includes each of two Wattenberg horizontal wells (1 Niobrara and 1 Codell), and a third well (Niobrara) that are described furtherbelow in connection with the Great Western Operating Company, LLC litigation. As such, the previously capitalized and accrued costs of approximately$5.20 million relating to these wells were eliminated since being placed in non-consent status relieved the Company of such liabilities. The Company hasretained the right to participate in future drilling on this acreage block. F-16  On September 2, 2014, the Company entered into a final settlement agreement, or the Final Settlement Agreement to convey its interest in 31,725 evaluatedand unevaluated net acres located in the DJ Basin and the associated oil and natural gas, which we refer to as the Hexagon Collateral to the Company’sprimary lender, Hexagon, LLC, which we refer to as Hexagon, in exchange for extinguishment of all outstanding debt and accrued interest obligations owedto Hexagon in an aggregate amount of approximately $15.1 million. The conveyance assigned all assets and liabilities associated with the property, whichincludes PDP and PUD reserves, plugging and abandonment, and other assets and liabilities associated with the property. Pursuant to the Final SettlementAgreement, we also issued to Hexagon $2.0 million in 6% Conditionally Redeemable Preferred Stock valued at $1.69 million and considered as temporaryequity for reporting purposes. The Hexagon transaction was accounted for under the full cost method of accounting for oil and natural gas operations. Under the full cost method, sales orabandonments of oil and natural gas properties, whether or not being amortized, are accounted for as adjustments of capitalized costs, with no gain or lossrecognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to thecost center. The transfer to Hexagon represents greater than 25% of the Company’s proved reserves of oil and gas attributable to the full cost pool and thusthe Company incurred a loss on the conveyance. Following this methodology, the following table represents an allocation of the transaction. Payment of debt and accrued interest payable $15,063,289 Add: disposition of asset retirement obligations 973,132 Total disposition of liabilities $16,036,421 Proved oil and natural gas properties $32,574,603 Accumulated depletion (22,148,686)Unproved oil and natural gas properties 6,194,162 Net oil and natural gas conveyed at cost 16,620,079 Redeemable Preferred Stock at fair value 1,686,102 Total conveyance of assets and preferred stock 18,306,181 Loss on conveyance $(2,269,760) As of December 31, 2015 and 2014, the Company completed an assessment of its inventory of unevaluated acreage, which resulted in a transfer of $2.89million and $9.90 million, respectively from unevaluated acreage to evaluated properties. NOTE 5 - DERIVATIVES The Company periodically enters into various commodity derivative financial instruments intended to hedge against exposure to market fluctuations of oilprices. As of December 31, 2015 and 2014, the Company did not have any commodity derivative instruments. The Company had an active commodity swapfor 100 barrels of oil per day through January 31, 2014 at a price of $99.25 per barrel and realized a gain on that contract of $11,000 during the year endedDecember 31, 2014. Realized gains and losses are recorded as individual swaps mature and settle. These gains and losses are recorded as income or expenses in the periods duringwhich applicable contracts settle. Swaps which are unsettled as of a balance sheet date are carried at fair market value, either as an asset or liability.Unrealized gains and losses result from mark-to-market changes in the fair value of these derivatives between balance sheet dates. F-17  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 valuation methodologies inmeasuring fair value: ●Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.●Level 2 – Other inputs that are directly or indirectly observable in the marketplace.●Level 3 – Unobservable inputs which are supported by little or no market activity. The fair value hierarchy also requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fairvalue. The Company’s interest rate Loan and Debentures are measured using Level 3 inputs. Derivative Instruments The Company determines its estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted marketprices in active markets, quotes from third parties, and the credit rating of its counterparty. The Company also performs an internal valuation to ensure thereasonableness of third-party quotes. The types of derivative instruments utilized by the Company included commodity swaps. The oil derivative markets are highly active. Although theCompany’s economic hedges are valued using public indices, the instruments themselves are traded with third-party counterparties and are not openly tradedon an exchange. As such, the Company classifies these instruments as Level 2. In evaluating counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to makeany contractually required payments. The Company considered that the counterparty is of substantial credit quality and has the financial resources andwillingness to meet its potential repayment obligations associated with the derivative transactions. The Company has no such derivative instruments at December 31, 2015 and 2014. 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 of abandoning oiland gas wells, which is based on the Company’s and/or Industry’s historical experience for similar work, or estimates from independent third-parties; theeconomic lives of its properties, which are based on estimates from reserve engineers; the inflation rate; and the credit adjusted risk-free rate, which takes intoaccount the Company’s credit risk and the time value of money. Given the unobservable nature of the inputs, the initial measurement of the asset retirementobligation liability is deemed to use Level 3 inputs. Impairment.The Company estimates the expected undiscounted future cash flows of its oil and natural gas properties and compares such amounts to the carrying amountof the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cashflows, the Company will adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value are subject tomanagement’s judgement and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows,net of estimated operating and development costs using estimates or proved reserves, future commodity pricing, future production estimates, anticipatedcapital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flowsprojected. These assumptions represent Level 3 inputs. Impairment of oil and gas assets for the year ended December 31, 2015 was $24.5 million. Noimpairment charges on proved oil and natural gas properties were recorded for the years ended December 31, 2014. Executive Compensation In September 2013, the Company announced the appointment of Abraham Mirman as its new president. In connection with Mr. Mirman’s appointment, theCompany entered into an employment agreement with Mr. Mirman (the “Mirman Agreement”). The Mirman Agreement provides for an incentive bonuspackage that, depending upon the relative performance of the Company’s Common Stock compared to the performance of stocks of certain peer groupcompanies 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 upto 3.0 times his base salary. The incentive bonus is recorded as a liability and valued at each reporting period. The Company engaged a valuation firm(“VFIRM”) to complete a valuation of this incentive bonus. As of December 31, 2014, the Company recorded a liability of $40,000 for accruedcompensation. As previously announced, on March 30, 2015, the Company entered into an amended and restated employment agreement, which we refer toas the Mirman CEO Agreement with Mr. Mirman. The Mirman CEO Agreement also provides for Mr. Mirman to receive a cash incentive bonus if certainproduction thresholds are achieved by the Company. Mr. Mirman’s new incentive bonus liability was valued by VFIRM at $104,000 at December 31, 2015.As of December 31, 2015, the Company provided for $87,000 of the bonus liability which represents the amount earned as of December 31, 2015. F-18  On March 6, 2015, the Company announced the appointment of Kevin Nanke as its new Executive Vice President and Chief Financial Officer. Mr. Nankewill also receive a cash incentive bonus if certain production thresholds are achieved by the Company and a performance bonus of $100,000 if the Companyachieves certain goals set forth in Mr. Nanke’s employment agreement. Mr. Nanke’s new incentive bonus liability was valued by VFIRM at $83,000 atDecember 31, 2015. As of December 31, 2015, 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, 2015, the Company has provided for $67,000 of the liability whichrepresents the amount 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 to Bristol awarrant to purchase up to 1,000,000 shares of Common Stock at an exercise price of $2.00 per share (or, in the alternative, 1,000,000 options, but in no caseboth). The agreement has a price protection feature that will automatically reduce the exercise price if the Company enters into another consulting agreementpursuant to which warrants are issued with a lower exercise price. On December 31, 2014, the Company revalued the warrants/option using the followingvariables: (i) 1,000,000 total warrants/options issued (as stated above, the Company will only issue a total of 1,000,000 shares of Common Stock under theoption or the warrant, but no more than 1,000,000 shares in the aggregate); (ii) stock price of $0.72; (iii) exercise price of $2.00; (iv) expected life of 4.67years; (v) volatility of 96.78%; (vi) risk free rate of 1.10% for a total value of $394,000, which adjusted the change in fair value valuation of the derivative by$571,000. On December 31, 2015, the Company revalued the warrants/options using the following variables: (i) 1,000,000 total warrants/options issued (as statedabove, the Company will only issue a total of 1,000,000 shares of Common Stock under the option or the warrant, but no more than 1,000,000 shares in theaggregate); (ii) stock price of $0.20; (iii) exercise price of $2.00; (iv) expected life of 3.7 years; (v) volatility of 100%; risk free rate of 1.5% for a total valueof $44,000, which adjusted the change in fair value valuation of the derivative 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 a warrant topurchase up to 225,000 shares of Common Stock at an exercise price of $2.50 with the initial advance, which contains an anti-dilution feature that willautomatically reduce the exercise price if the Company enters into another agreement pursuant to which warrants are issued with a lower exercise price. On December 31, 2015, the Company revalued the warrants using the following variables: (i) 225,000 warrants issued; (ii) stock price of $0.20; (iii) exerciseprice of $ 2.50; (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 fairvalue valuation of the derivative by $12,000 for the year ended December 31, 2015. 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 any time atthe holders’ option into shares of Common Stock at $2.00 per share, or 3,423,233 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 $2.00 per share, subject to certain adjustments, including the requirement to reset the conversion for any subsequent offering ata lower price per share amount. The Company values this conversion liability at each reporting period using a Monte Carlo pricing model. F-19  At December 31, 2015 and 2014, the Company valued the conversion feature associated with the Debentures at $6,000 and $1.25 million, respectively. TheCompany used the following inputs to calculate the valuation of the derivative as of December 31, 2015: (i) volatility of 100%; (ii) conversion price of$2.00; (iii) stock price of $0.20; and (iv) present value of conversion feature of $0.0016 per convertible share and as of December 31, 2014: (i) volatility of70%; (ii) conversion price of $2.00; (iii) stock price of $0.72; and (iv) present value of conversion feature of $0.47 per convertible share. The change in fairvalue valuation of the derivative was $1.24 million for the year ended December 31, 2015. The following table provides a summary of the fair values of assets and liabilities measured at fair value: December 31, 2015: Level 1 Level 2 Level 3 Total Liability Executive employment agreements $- $- $(223,000) $(223,000)Warrant liabilities - - (56,000) (56,000)Convertible debenture conversion derivative liability - - (6,000) (6,000)Total liability, at fair value $- $- $(285,000) $(285,000) December 31, 2014: Level 1 Level 2 Level 3 Total Liability Executive employment agreement $- $- $(40,000) $(40,000)Warrant liabilities - - (394,000) (394,000)Convertible debenture conversion derivative liability - - (1,249,000) (1,249,000)Total liability, at fair value $- $- $(1,683,000) $(1,683,000) 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, 2015 and 2014: Conversionderivativeliability Bristol/ Heartlandwarrantliability Incentivebonus Total Balance at January 1, 2015 $1,249,000 $394,000 $40,000 $1,683,000 Additional liability - 56,000 149,000 205,000 Change in fair value of liability (1,243,000) (394,000) 34,000 (1,603,000)Balance at December 31, 2015 $6,000 $56,000 $223,000 $285,000 F-20  Conversionderivativeliability Bristol warrantliability Incentivebonus Total Balance at January 1, 2014 $605,000 $- $145,000 $750,000 Additional liability - 965,000 - 965,000 Change in fair value of liability 5,527,000 (571,000) (105,000) 4,851,000 Reclassification from liability to equity (4,883,000) - - (4,883,000 Balance at December 31, 2014 $1,249,000 $394,000 $40,000 $1,683,000 The Company did not have any transfers of assets or liabilities between Level 1, Level 2 or Level 3 of the fair value measurement hierarchy during the yearsended December 31, 2015 and 2014. NOTE 7 - LOAN AGREEMENTS Credit Agreement As ofDecember 31,2015 Term loan - Heartland (due January 8, 2018) $2,750,000 Unamortized debt discount (37,911)Term loan - Heartland, net 2,712,089 Less: amount due within one year (2,712,089)Term loan - Heartland due after one year $- On January 8, 2015, the Company entered into the Credit Agreement with Heartland Bank, as administrative agent and the Lenders party thereto. The CreditAgreement provides for a three-year senior secured term loan in an initial aggregate principal amount of $3,000,000, or the Term Loan, which principalamount may be increased to a maximum principal amount of $50,000,000 at the request of the Company pursuant to an accordion advance provision in theCredit Agreement subject to certain conditions, including the discretion of the lender. Funds borrowed under the Credit Agreement may be used by theCompany to (i) purchase oil and gas assets, (ii) fund certain Lender-approved development projects, (iii) fund a debt service reserve account, (iv) pay all costsand expenses arising in connection with the negotiation and execution of the Credit Agreement, and (v) fund the Company’s general working capital needs. The Term Loan bears interest at a rate calculated based upon the Company’s leverage ratio and the “prime rate” then in effect. In connection with its entryinto the Credit Agreement, the Company also paid a nonrefundable commitment fee in the amount of $75,000, and agreed to issue to the Lenders 75,000 5-year warrants for every $1 million funded. An initial warrant to purchase up to 225,000 shares of the Company’s common stock at $2.50 per share was issuedin connection with closing. As of January 8, 2015, the Company valued the 225,000 warrants at $56,000, which was accounted for as debt discount andamortized over the life of the debt. The Company accreted $18,000 of debt discount for the year ended December 31, 2015. The Credit Agreement contains certain customary representations and warranties and affirmative and negative covenants. The Credit Agreement also containsfinancial covenants with respect to the Company’s (i) debt to EBITDAX ratio and (ii) debt coverage ratio. In addition, in certain situations, the CreditAgreement requires mandatory prepayments of the Term Loans, including in the event of certain non-ordinary course asset sales, the incurrence of certaindebt, and the Company’s receipt of proceeds in connection with insurance claims. As previously disclosed, as of June 30, 2015 and September 30, 2015, the Company was not in compliance with the financial covenant in the CreditAgreement that relates to the total debt to EBITDAX ratio. EBITDAX is defined in the Credit Agreement as, for any period of determination, determined inaccordance with GAAP, the pre-tax net income for such period plus (without duplication and only to the extent deducted in determining such net income),interest expense for such period, depreciation and amortization expense, extraordinary or non-recurring items reducing net income for such period, and othernon-cash expenses for such period less gains on sales of assets and other non-cash income for such period included in the determination of net income plus(without duplication and only to the extent deducted in determining such net income) exploration, drilling and completion expenses or costs. Specifically,the ratio requires that the Company maintain at all times, as determined on June 30 of each year, a ratio of (i) the aggregate amount of all Debt (as defined inthe Credit Agreement), to (ii) EBITDAX of not less than 4.5:1, 3.5:1 and 2.5:1 for the periods ending June 30, 2015, 2016, and 2017 and thereafter,respectively. Prior to the filing of our quarterly report for the period ended June 30, 2015, the Company received a waiver from Heartland for this covenantviolation, which will not be measured again until June 30, 2016. The Company will need to raise additional capital and acquire and/or successfully developits oil and gas assets to meet this covenant. F-21  On December 29, 2015, after a default on an interest payment and in connection with the merger transactions, the Company entered into the ForbearanceAgreement with Heartland. The Forbearance Agreement restricts Heartland from exercising any of its remedies until April 30, 2016 and is subject to certainconditions, including a requirement for the Company to make a monthly interest payment to Heartland. On April 1, 2016, the Company failed to make therequired interest payment to Heartland for the month of March. As a result, Heartland has the right to declare an event of default under the ForbearanceAgreement, terminate the remaining commitment and accelerate payment of all principal and interest outstanding. The Company has not yet received anotice of default and is currently in discussions with Heartland with respect to the missed interest payment. Moreover, the Debentures also contain certaincross-default provisions with certain other debt instruments. Therefore, a default under the Credit Agreement, constitutes an event of default pursuant to theDebentures which may result in an acceleration of our obligations at the holders’ election. Convertible Notes RelatedParty Non RelatedParty Convertible notes $1,800,002 $1,150,000 Unamortized debt discount (745,450) (476,261)Convertible notes, net 1,054,552 673,739 Less: amount due within one year (1,054,552) (673,739)Convertible notes due after one year $- $- From December 29, 2015 to January 5, 2016, the Company entered into 12% Convertible Subordinated Note Purchase Agreements with various lendingparties, which we refer to as the Purchasers, for the issuance of an aggregate principal amount of $3.75 million unsecured subordinated convertible notes, orthe Convertible Notes, which includes the $750,002 of short-term notes exchanged for Convertible Notes by the Company and warrants to purchase up to anaggregate of approximately 15,000,000 shares of Common Stock at an exercise price of $0.25 per share. The proceeds from this financing were used to pay a$2 million refundable deposit in connection with the Merger, to fund approximately $1.3 million of interest payments to our lenders and for our workingcapital and accounts payables. The Convertible Notes bear interest at a rate of 12% per annum, payable at maturity on June 30, 2016. The Convertible Notes and accrued but unpaid interestthereon are convertible in whole or in part from time to time at the option of the holders thereof into shares of our Common Stock at a conversion price of$0.50. The Convertible Notes may be prepaid in whole or in part (but with payment of accrued interest to the date of prepayment) at any time at a premium of103% for the first 120 days and a premium of 105% thereafter, so long as no Senior Debt is outstanding. The Convertible Notes contain customary events ofdefault, which, if uncured, entitle each noteholder to accelerate the due date of the unpaid principal amount of, and all accrued and unpaid interest, subject tocertain subordination provisions. Additionally, on March 18, 2016, the Company issued an additional aggregate principal amount of $500,000 of Convertible Notes, which have the terms andconditions as the Convertible Notes with the exception of the maturity date, which is April 1, 2017. The proceeds from these Convertible Notes were used tomake advances to Brushy for payment of operating expenses pending completion of the Merger. If the Merger is not completed, these amounts are subject torepayment by Brushy. F-22  Debentures As ofDecember 31,2015 As ofDecember 31,2014 8% Convertible debentures, net (due 2018; 8% weighted average interest rate) $6,846,465 $6,846,465 Unamortized debt discount - (6,389)8% Convertible debenture, net 6,846,465 6,840,076 Less: amount due within one year (6,846,465) - 8% Convertible debenture due after one year $- $6,840,076 In numerous separate private placement transactions between February 2011 and October 2013, the Company issued an aggregate of approximately $15.6million of Debentures, secured by mortgages on several of its properties. On January 31, 2014, the Company entered into a debenture conversion agreement(the “First Conversion Agreement”) with all of the holders of the Debentures. Pursuant to the terms of the First Conversion Agreement, $9.0 million in Debentures (approximately $8.73 million of principal and $270,000 in interest) wasconverted by the holders to shares of Common Stock at a conversion price of $2.00 per share. In addition, the Company issued warrants to the Debentureholders to purchase one share of Common Stock for each share issued in connection with the conversion of the Debentures, at an exercise price equal to $2.50per 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 automatic conversion ofDebentures into shares of the Company’s Common Stock at a price of $0.50 per share, upon the receipt of requisite stockholder approval and theconsummation of the Merger. If the Debentures are converted on these terms, it would result in the issuance of 13,692,930 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. As of December 31, 2015 and 2014, the Company had $6.85 million and $6.84 million, net, remaining Debentures, respectively, which prior to December 29,2015, were convertible at any time at the holders’ option into shares of Common Stock at a conversion price of $2.00 per share, subject to certain standardadjustments. If the Merger is not successful or the stockholders do not approve the conversion of the Debentures at the Company’s special meeting to be heldin the second quarter of 2016, the Debentures will no longer be subject to the terms of current debenture conversion agreement. The debt discount amortization on the Debentures was approximately $6,000 and $472,000 for the years ended December 31, 2015 and 2014, respectively. 10% Term Loans On May 30, 2014, the Company entered into the First Settlement Agreement with Hexagon, which provided for the settlement of all amounts outstandingunder the term loans. In connection with the execution of the First Settlement Agreement, the Company made an initial cash payment of $5.0 millionreducing the total principal and interest due under the term loan from $19.83 million to $14.83 million. The First Settlement Agreement required theCompany to make an additional cash payment of $5.0 million (the “Second Cash Payment”) by August 15, 2014, and at that time issue to Hexagon (i) a two-year $6.0 million unsecured note (the “Replacement Note”), bearing interest at an annual rate of 8%, requiring principal and interest payments of $90,000 permonth, and (ii) 943,208 shares of unregistered Common Stock (the “Shares”). The parties also agreed that if the Second Cash Payment was not made by June30, 2014, an additional $1.0 million in principal would be added to the Replacement Note, and if the Replacement Note was not retired by December 31,2014, the Company would issue an additional 1.0 million shares of Common Stock to Hexagon. The First Settlement Agreement was superseded by the FinalSettlement Agreement which is discussed below. F-23  On September 2, 2014, the Company entered into the Final Settlement Agreement with Hexagon which replaced the First Settlement Agreement, pursuant towhich, in exchange for full extinguishment of all amounts outstanding under the term loans (approximately $15.06 million in principal and interest as of thesettlement date), the Company assigned Hexagon the collateral securing the term loans, which consisted of approximately 32,000 net acres including 17producing wells that consisted of several economic wells which secured properties with PDP reserves and PUD reserves with a carrying value ofapproximately $16.62 million. The Company also conveyed $973,000 in asset retirement obligations (“ARO”) for the 17 active and several non-producingwells. In addition to the conveyance of oil and natural gas property, the Company issued to Hexagon 2,000 shares of 6% Conditionally Redeemable PreferredStock with a par value of $0.0001, stated value of $1,000 and dividends paid on a quarterly basis valued at approximately $1.69 million at December 31,2014. As a result of this conveyance, the Company recorded a loss on conveyance of property of $2.27 million. The 2,000 shares of Conditionally Redeemable 6% Preferred Stock were issued on September 2, 2014 with a stated rate of $1,000 per share, par $0.0001. Theshares were valued using the Monte Carlo projection model to determine the value of the preferred stock. The Company used the following inputs tocalculate the valuation of the preferred stock at conveyance. The inputs consisted of a maturity range from 13.91 to 17.29 percent, redemption probabilityrate of 50%, and other probability weighted projected inputs including acquisitions, production, and other criteria that trigger a mandatory redemption. Inducement Expense On January 31, 2014, as discussed above, the Company entered into the Initial Conversion Agreement with all of the holders of the Debentures. Under theterms of the Initial Conversion Agreement, $9.0 million of the approximately $15.6 million in Debentures outstanding as of January 30, 2014 immediatelyconverted to shares of Common Stock at a price of $2.00 per common share. As additional inducement for the conversions, the Company issued warrants tothe converting Debenture holders to purchase one share of Common Stock, at an exercise price equal to $2.50 per share (the “Warrants”), for each share ofCommon Stock issued upon conversion of the Debentures. The Company utilized a Black Scholes option price model, with a 3 year life and 65% volatility,risk free rate of 0.2%, and the market price of $3.05. The Company recorded an inducement expense of $6.66 million during the year ended December 31,2014 for the Warrants. TRW acted as the investment banker for the Initial Conversion Agreement and was compensated with 225,000 shares of CommonStock valued at a market price of $3.05 per share. During the year ended December 31, 2014, the Company valued that compensation at $686,000, which wasexpensed immediately. Interest Expense For the year ended December 31, 2015 and 2014, the Company incurred interest expense of approximately $1.70 million and $4.84 million, respectively, ofwhich approximately $131,000 and $2.43 million, respectively, were non-cash interest expense conveyed through property, amortization of the deferredfinancing costs, accretion of the Debentures payable discount, and Debentures interest paid in Common Stock. Debenture Interest – Non Cash During the year ended December 31, 2014, the Company elected to fund its interest payment for its Debentures with stock and issued 1,396,129 sharesvalued at approximately $1.19 million which is an add back to accrued expense in the cash flow and further disclosed in the supplemental disclosure. Theinterest was accrued for the period from November 15, 2013 to December 29, 2014. F-24  NOTE 8 - COMMITMENTS AND CONTINGENCIES Environmental and Governmental Regulation At December 31, 2015, there were no known environmental or regulatory matters which are reasonably expected to result in a material liability to theCompany. Many aspects of the oil and gas industry are extensively regulated by federal, state, and local governments in all areas in which the Company hasoperations. 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, 2015 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, theCompany’s liability, if any, in these pending actions would not have a material adverse effect on the financial position of the Company. The Company’sgeneral and administrative expenses would include amounts incurred to resolve claims made against the Company. Parker v. Tracinda Corporation, Denver District Court, Case No. 2011CV561. In November 2012, the Company filed a motion to intervene in garnishmentproceedings involving Roger Parker, the Company’s former Chief Executive Officer and Chairman. The Defendant, Tracinda, served various writs ofgarnishment on the Company to enforce a judgment against Mr. Parker seeking, among other things, shares of unvested restricted stock. The Companyasserted rights to lawful set-offs and deductions in connection with certain tax consequences, which may be material to the Company. The underlyingjudgment against Mr. Parker was appealed to the Colorado Court of Appeals and, by Order dated October 17, 2013, that Court reversed the trial court withrespect to Mr. Parker’s claims of waiver, estoppel and mitigation of damages and remanded with instruction to enter judgment for Mr. Parker. The Court ofAppeals also ordered the trial court to conduct further proceedings to determine the amount of damages to award Mr. Parker on his breach of contract claim.The trial court conducted a later hearing and found in its Findings of Fact, Conclusions of Law and Order dated January 9, 2015, in favor of Mr. Parker on hisclaim for breach of contract, awarding him $6,981,302.60.Tracinda’s Motion for Amendment of the Court’s January 9 Findings and Conclusions was thesubject of an Order dated April 10, 2015, in which the Court set off the award in favor of Mr. Parker against the award in favor of Tracinda, resulting injudgment in favor of Tracinda and against Mr. Parker in the amount of $625,572. On April 16, 2015, Tracinda filed a Notice of Appeal in the Colorado Courtof Appeals, appealing both the January 9 Order and the April 10 Order. On May 18, 2015, Parker filed a Notice of Cross-Appeal in the Colorado Court ofAppeals, cross-appealing both the January 9 Order and the April 10 Order. The record is in the process of being certified. The filing of the record will triggerthe parties' briefing schedule. In re Roger A. Parker: Tracinda Corp. v. Recovery Energy, Inc. and Roger A. Parker, United States Bankruptcy Court for the District of Colorado, Case No.13-10897-EEB. On June 10, 2013, Tracinda Corp. (“Tracinda”) filed a complaint (Adversary No. 13-011301 EEB) against the Company and Roger Parker inconnection with the personal bankruptcy proceedings of Roger Parker, alleging that the Company improperly failed to remit to Tracinda certain property inconnection with a writs of garnishment issued by the Denver District Court (discussed above). The Company filed an answer to this complaint on July 10,2013. A trial date has not been set and, by Order dated February 2, 2015, the Bankruptcy Court ordered that the Adversary Proceeding be held in abeyancepending final resolution of the state-court action (2011CV561). The Company is unable to predict the timing and outcome of this matter. Lilis Energy, Inc. v. Great Western Operating Company LLC, Eighth Judicial District Court for Clark County, Nevada, Case No. A-15-714879-B. On March 6,2015, the Company filed a lawsuit against Great Western Operating Company, LLC, or the Operator. The dispute related to the Company’s interest in certainproducing wells and the Operator’s assertion that the Company’s interest was reduced and/or eliminated as a result of a default or a farm-out agreement.Underlying the dispute is the JOA which provides the parties with various rights and obligations. In its complaint, the Company sought monetary damagesand declaratory relief on claims of breach of contract, breach of the implied covenant of good faith and fair dealing, tortious breach of the implied covenantof good faith and fair dealing, unjust enrichment, conversion and declaratory judgment related to the JOA. The Operator filed a motion to dismiss on May 26,2015 and the Company responded by filing an opposition motion on June 12, 2015. F-25  On July 7, 2015, as previously reported, the Company entered into a settlement agreement with the Operator. Due to the Company’s inability to securefinancing pursuant to the Credit Agreement or another funding source, payment was not remanded to the Operator and the dispute remained unsettled. During the year ended December 31, 2015, the Company was put in non-consent status. As such, the previously capitalized and accrued costs ofapproximately $5.20 million relating to these wells were eliminated since being placed in non-consent status relieved the Company of such liabilities. TheCompany has retained the right to participate in future drilling on this acreage block. The Company believes there is no other 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 leases an office space under a two year operating lease in Denver, Colorado and a one year operating lease in Melville, New York expiring inNovember 2017. Rent expense for the years ended December 31, 2015 and 2014, were $73,000 and $109,000, respectively. As of December 31, 2015, theCompany has approximately $90,000 of minimum lease payments on its existing operating leases. NOTE 9 - RELATED PARTY TRANSACTIONS During the fiscal years ended December 31, 2015 and 2014, the Company has engaged in the following transactions with related parties: Debenture Conversion Agreement On December 29, 2015, the Company entered into a Debenture Conversion Agreement between with all of the remaining holders of its Debentures. The termsof the Agreement provide that the entire amount of approximately $6.85 million in outstanding Debentures are automatically converted into the Company’sCommon Stock upon the closing of the proposed merger with Brushy Resources, Inc., or the Conversion Date, provided that the Company obtains therequisite stockholder approval as required by the Nasdaq Marketplace Rules, which it plans to seek at the next stockholders’ meeting to be held inconnection with approving the proposed merger with Brushy Resources, Inc. Pursuant to the terms of the Debenture Conversion Agreement, the Debentureswill be converted at a price of $0.50, or the Conversion Price, which will result in the issuance of an aggregate of 13,692,930 shares of Common Stock uponconversion of the Debentures. Holders of the Debentures have waived and forfeited any and all rights to receive accrued but unpaid interest. Upon theconversion of the Debentures, the holders’ security interest will also be extinguished. Certain parties to the Debenture Conversion Agreement include related parties of our the Company, such as the Steven B. Dunn and Laura Dunn RevocableTrust dated 10/28/10, of which its respective Debenture amount to be converted on the Conversion Date is $1,017,111, and Wallington Investment Holdings,Ltd., of which its respective Debenture amount to be converted on the Conversion Date is $2,090,180. Each of the Steven B. Dunn and Laura DunnRevocable Trust dated October 28, 2010 and Wallington Investment Holdings, Ltd. are a more than 5% shareholder of our company. From December 29, 2015 to January 5, 2016, the Company entered into 12% Convertible Subordinated Note Purchase Agreements with various lendingparties, or the Purchasers, for the issuance of an aggregate principal amount of $3.75 million unsecured subordinated convertible notes, or the ConvertibleNotes, which includes the $750,002 of short-term notes exchanged for Convertible Notes by the Company and warrants to purchase up to an aggregate ofapproximately 15,000,000 shares of Common Stock at an exercise price of $0.25 per share. As of December 31, 2015, $2.95 million Convertible Notes wereoutstanding. The proceeds from this financing was used to pay a $2 million refundable deposit in connection with the Merger, to fund approximately $1.3million of interest payments to certain of our lenders and for the Company’s working capital and accounts payables. The Convertible Notes bear interest at a rate of 12% per annum, payable at maturity on June 30, 2016. The Convertible Notes and accrued but unpaid interestthereon are convertible in whole or in part from time to time at the option of the holders thereof into shares of our common stock at a conversion price of$0.50. The Convertible Notes may be prepaid in whole or in part by paying all or a portion of the principal amount to be prepaid together with accruedinterest thereon to the date of prepayment at a premium of 103% for the first 120 days and a premium of 105% thereafter, so long as no Senior Debt isoutstanding. The Convertible Notes contain customary events of default, which, if uncured, entitle each noteholder to accelerate the due date of the unpaidprincipal amount of, and all accrued and unpaid interest, subject to certain subordination provisions. F-26  The Purchasers include certain related parties of the Company, including Abraham Mirman, our Chief Executive Officer and a member of the Board ofDirectors ($750,000 including the short-term note exchange investment), the Bruin Trust, an irrevocable trust managed by an independent trustee and whosebeneficiaries include the adult children of Ronald D. Ormand, Chairman of the Company’s Board of Directors ($1.15 million) and Pierre Caland throughWallington Investment Holdings, Ltd. ($300,000), who holds more than 5% of our Common Stock. Certain of the Company’s officers, directors and consultants who the Company entered into short-term note agreements with in 2015, also entered into noteexchange agreements, whereby the short-term noteholder agreed to exchange all of the Company’s outstanding obligations under such short-term notes,which as of December 29, 2015 had outstanding obligations of $750,002, into the Convertible Notes at a rate, expressed in principal amount of ConvertibleNotes equal to $1.00 for $1.00, in exchange for the cancellation of the short-term notes, with all amounts due thereunder being cancelled and deemed to havebeen paid in full, including any accrued but unpaid interest. The short-term noteholders include certain related parties of the Company, including Abraham Mirman, the Chief Executive Officer and a director of theCompany ($250,000), General Merrill McPeak, a director of the Company ($250,000), and Nuno Brandolini, a director of the Company ($150,000). Additionally, on March 18, 2016, the Company issued an additional aggregate principal amount of $500,000 in Convertible Notes and warrants to purchaseup to 2.0 million shares of our Common Stock. The terms and conditions of the Convertible Notes are identical to those of the Convertible Notes issuedpreviously with the exception of the maturity date, which is April 1, 2017. The Purchasers include a related party of the Company, R. Glenn Dawson, a director of the Company ($50,000). Abraham Mirman Abraham Mirman, the Chief Executive Officer and a director of the Company, is an indirect owner of a group which converted approximately $220,000 ofDebentures in connection with the $9.00 million of Debentures converted in January 2014, and was paid $10,000 in interest at the time of the Debentureconversion. During the January 2014 private placement, Mr. Mirman entered into a subscription agreement with the Company to invest $500,000, for which Mr. Mirmanwill receive 250,000 shares of stock and 250,000 warrants. The subscription agreement will not be consummated until a shareholder meeting is conducted toreceive the required approval to allow executives and Board directors the ability to participate in the offering. Additionally, as discussed below, on January 31, 2014, the Company entered into the First Conversion Agreement with the holders of the Debentures, whichalso included The Bralina Group, LLC, in which Mr. Mirman has voting and dispositive power, In April 2014, the Company appointed Abraham Mirman to serve as the Company’s Chief Executive Officer. Prior to joining the Company, Mr. Mirman wasemployed by T.R. Winston & Company, LLC, or TRW, as its Managing Director of Investment Banking and until September 2014 continued to devote aportion of his time to serving in that role. In connection with the appointment of Mr. Mirman, the Company and TRW amended the investment bankingagreement in place between the Company and TRW at that time to provide that, upon our receipt of gross cash proceeds or drawing availability of at least$30.00 million, measured on a cumulative basis and including certain restructuring transactions, subject to the Company’s continued employment of Mr.Mirman, TRW would receive from the Company a lump sum payment of $1.00 million. Mr. Mirman’s compensation arrangements with TRW provided thatupon TRW’s receipt from the Company of the lump sum payment, TRW would make a payment of $1 million to Mr. Mirman. The Board determined inSeptember 2014 that the criteria for the lump sum payment had been met. Mr. Mirman also received, as part of his compensation arrangement with TRW, the100,000 shares of Common Stock that were issued to TRW in conjunction with the investment banking agreement. F-27  G. Tyler Runnels and T.R. Winston The Company has participated in several transactions with TRW, of which G. Tyler Runnels, a former member of the Board of Directors, is chairman andmajority owner. Mr. Runnels also beneficially holds more than 5% of Common Stock, including the holdings of TRW and his personal holdings, and haspersonally participated in certain transactions with the Company. On January 22, 2014, the Company paid TRW a commission equal to $486,000 (equal to 8% of gross proceeds at the closing of the January 2014 privateplacement). Of this $486,000 commission, $313,750 was paid in cash and $172,250 was paid in 86,125 Units. In addition, the Company paid TRW a non-accountable expense allowance of $182,250 (equal to 3% of gross proceeds at the closing of the January 2014 private placement) in cash. If the participationof certain of the Company’s current and former officers and directors, who remain committed, is approved by stockholders, the Company will pay TRW anadditional commission. The Units issued to TRW were the same Units sold in the January 2014 private placement and were invested in the January 2014private placement. On January 31, 2014, the Company entered into a conversion agreement with all of the holders of the Debentures, including TRW and Mr. Runnels’ personaltrust, or the First Conversion Agreement. Under the terms of the First Conversion Agreement, $9.0 million of the approximately $15.6 million in Debenturesoutstanding as of January 30, 2014 immediately converted to shares of Common Stock at a price of $2.00 per common share. As additional inducement forthe conversions, the Company issued warrants to the converting Debenture holders to purchase one share of Common Stock, at an exercise price equal to$2.50 per share, for each share of Common Stock issued upon conversion of the Debentures. TRW acted as the investment banker for the First ConversionAgreement and was compensated by being issued 225,000 shares of Common Stock valued at a market price of $3.05 per share. During the year endedDecember 31, 2014, the Company valued the investment banker compensation at $686,000. On May 19, 2014, the Company and the holders of the Debentures agreed to extend the maturity date under the Debentures until August 15, 2014, and onJune 6, 2014, they agreed to further extend the maturity date under the Debentures from August 15, 2014 to January 15, 2015. In January 2015, the Companyentered into an extension agreement which extends the maturity date of the Debentures until January 8, 2018. Upon completion of the conversion of theremaining Debentures, TRW will be entitled to an additional commission. On October 6, 2014, the Company entered into a letter agreement, or the Waiver, with the holders of the Debentures, including TRW and Mr. Runnels’personal trust. Pursuant to the Waiver, the holders of the Debentures agreed to waive any Event of Default (as that term is defined in the Debentures) that mayhave occurred prior to the date of the Waiver, including any default in connection with the Hexagon term loan, and to rescind and annul any acceleration orright to acceleration that may have been triggered thereby. In exchange for the Waiver, the Company agreed that TRW, as representative for the holders of theDebentures, would have the right to nominate two qualified individuals to serve on the Board. Mr. Runnels is one of the qualified nomination designeeswhich TRW had elected to place on the Board. On March 28, 2014, the Company entered into a Transaction Fee Agreement with TRW in connection with the May private placement, or the Transaction FeeAgreement. Pursuant to the Transaction Fee Agreement, the Company agreed to compensate TRW 5% of the gross proceeds of the May private placement,plus a $25,000 expense reimbursement. On April 29, 2014, the Company and TRW amended the Transaction Fee Agreement to increase TRW’scompensation to 8% of the gross proceeds, plus an additional 1% of the gross proceeds as a non-accountable expense reimbursement in addition to the$25,000 originally contemplated. All fees were netted against gross proceeds from the May private placement. On May 30, 2014, the Company paid TRW a commission equal to $600,000 (equal to 8% of gross proceeds at the closing of the May private placement). Ofthis $600,000 commission, $51,850 was paid in cash to TRW, $94,150 was paid in cash to other brokers designated by TRW, and remaining $454,000 wasinvested by TRW into shares of Series A 8% Convertible Preferred Stock. In addition, the Company paid TRW a non-accountable expense allowance of$75,000 (equal to 1% of gross proceeds at the closing of the May private placement) in cash. F-28  On June 6, 2014, TRW executed a commitment to purchase or affect the purchase by third parties of an additional $15 million in Series A 8% ConvertiblePreferred Stock, to be consummated within ninety (90) days thereof. The agreement was subsequently extended and expired on February 22, 2015. OnFebruary 25, 2015, the Company and TRW agreed in principal to a replacement commitment, pursuant to which TRW has agreed that, at the request of theBoard, TRW would purchase or effect the purchase by third parties of an additional $7.5 million in Series A 8% Convertible Preferred Stock, to beconsummated no later than February 23, 2016, with all other terms substantially the same as those of the original commitment, which has not occurred. Ronald D. Ormand On March 20, 2014, the Company entered into an Engagement Agreement, or the MLV Engagement Agreement, with MLV in September of 2015. Pursuantto the Engagement Agreement, MLV acted as the Company’s exclusive financial advisor. Ronald D. Ormand, director of the Company since February 2015and chairman of the Board of Directors as of January 2016, was the former Managing Director and Head of the Energy Investment Banking Group at MLVuntil January 2016. The Engagement Agreement provided for a fee of $25,000 to be paid monthly to MLV, subject to certain adjustments and other specificfee arrangements in connection with the nature of financial services being provided. The term of the MLV Engagement Agreement expired on October 31,2015. The Company expensed $150,000 and $50,000 for the years ended December 31, 2015 and 2014, respectively. A total of $150,000 was paid to MLV for theyear ended December 31, 2014. On May 27, 2015, MLV agreed to take $150,000 of its accrued fees Common Stock and was issued 75,000 shares in lieu ofcash payment. The closing share price on May 27, 2015 was $1.56. Hexagon, LLC Hexagon, LLC, or Hexagon, our former primary lender, still holds over 5% of the Company’s Common Stock. The Company was a party to three term loan credit agreements dated as of January 29, 2010, March 25, 2010, and April 14, 2010, respectively, whichcollectively, are referred to as the credit agreements with Hexagon. On April 15, 2013, the Company and Hexagon agreed to amend the credit agreements toextend their maturity dates to May 16, 2014. Pursuant to the amendment, Hexagon agreed to (i) reduce the interest rate under the credit agreements from 15%to 10% beginning retroactively with March 2013, (ii) permit the Company to make interest only payments for March, April, May, and June 2013, after whichtime the minimum secured term loan payment became $0.23 million, and (iii) forbear from exercising its rights under the term loan credit agreements for anybreach that may have occurred prior to the amendment. In consideration for the extended maturity date, the reduced interest rate and minimum loan paymentunder the secured term loans, the Company provided Hexagon an additional security interest in 15,000 acres of its undeveloped acreage. In addition, Hexagon and its affiliates had interests in certain of the Company’s wells independent of Hexagon’s interests under the term loans, for whichHexagon or its affiliates receive revenue and joint-interest billings. On September 2, 2014, the Company entered into the Final Settlement Agreement with Hexagon, to settle all amounts payable by the Company pursuant toexisting credit agreements with Hexagon that were secured by the Hexagon Collateral. Pursuant to the Final Settlement Agreement, in exchange for fullextinguishment of all amounts payable ($15.1 million in principal and interest) pursuant to the credit agreements and related promissory notes, the Companyagreed to assign to Hexagon all of the Hexagon Collateral, and issued to Hexagon $2.0 million in a new series of 6% Redeemable Preferred Stock. The FinalSettlement Agreement also prohibited Hexagon from selling or otherwise disposing of any shares of Common Stock held by Hexagon until February 29,2016. In addition, pursuant to the Final Settlement Agreement, the Company and Hexagon each mutually released and discharged all known and unknownclaims against the other and their respective representatives that they had or may have, including claims relating to the credit agreements. F-29  Officers and Directors As discussed above, on January 31, 2014, the Company entered into the First Conversion Agreement with the holders of the Debentures, which also includedW. Phillip Marcum, the Company’s then Chief Executive Officer, and A. Bradley Gabbard, the Company’s then Chief Financial Officer. Employment Agreements with Officers See Note 12—Share Based and Other Compensation. Compensation of Directors See Note 12—Share Based and Other Compensation. NOTE 10 - INCOME TAXES The income tax provision (benefit) for the years ended December 31, 2015 and 2014 consisted of the following: December 31, 2015 2014 U.S. Federal: Current $- $- Deferred (10,559,507) (5,279,080) State and local: Current - - Deferred (914,239) (337,066) (11,473,746) (5,616,146)Change in valuation allowance 11,473,746 5,616,146 Income tax provision $- $- The tax effects of temporary differences that give rise to the Company’s deferred tax asset as of December 31, 2015 and 2014 consisted of the following: December 31, 2015 2014 Deferred tax assets: Oil and gas properties and equipment $3,448,288 $- Net operating loss carry-forward 41,375,037 37,857,532 Share based compensation 1,278,948 1,290,482 Abandonment obligation 76,826 72,365 Derivative instruments 20,561 142,434 Accrued liabilities 36,944 132,574 Debt conversion costs 502,048 477,439 Other 29,555 28,937 Total deferred tax asset 47,168,207 40,001,763 Valuation allowance (47,168,207) (35,694,459)Deferred tax asset , net of valuation allowance $- $4,307,304 Deferred tax liabilities: Oil and gas properties and equipment $- $(4,307,304)Total deferred tax liability - (4,307,304)Net deferred tax asset (liability) $- $- F-30  Reconciliation of the Company’s effective tax rate to the expected U.S. federal tax rate is: For the Year Ended December 31, 2015 2014 Effective federal tax rate 34.00% 34.00%State tax rate, net of federal benefit 2.94% 2.17%Change in fair value derivative liability 1.42% -7.03%Conversion inducement expense -% -8.47%Debt discount amortization -0.01% -1.08%Share based compensation differences and forfeitures -4.18% -%Change in rate 0.01% -1.28%Other permanent differences -1.06% 1.44%Valuation allowance -35.46% -19.75%Net -% -% The Company is in the process of filing its federal and state tax returns for the years ended April 30, 2011, December 31, 2011, December 31, 2012, December31, 2013, December 31, 2014 and December 31, 2015. The net operating losses for these years will not be available to reduce future taxable income until thereturns are filed. Assuming these returns are filed, as of December 31, 2015 and 2014, the Company had net operating loss carry-forwards for federal incometax purposes of approximately $112.0 million and $106.8 million, respectively, available to offset future taxable income. To the extent not utilized, the netoperating loss carry-forwards as of December 31, 2015 will expire beginning in 2027 through 2035. The net operating loss carryovers may be subject toreduction or limitation by application of Internal Revenue Code Section 382 from the result of ownership changes. A full Section 382 analysis has not beenprepared and the Company's net operating losses could be subject to limitation under Section 382. In assessing the need for a valuation allowance on our deferred tax assets, management considers whether it is more likely than not that some portion or all ofthe deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon whether future book income is sufficient to reverseexisting temporary differences that give rise to deferred tax assets, as well as whether future taxable income is sufficient to utilize net operating loss and creditcarryforwards. Assessing the need for, or the sufficiency of, a valuation allowance requires the evaluation of all available evidence, both positive andnegative. Management had no positive evidence to consider. Negative evidence considered by management includes cumulative book and tax losses inrecent years, forecasted book and tax losses, no taxable income in available carryback years, and no tax planning strategies contemplated to realize thevalued deferred tax assets. As of December 31, 2015 and 2014, management assessed the available positive and negative evidence to estimate if sufficient future taxable income wouldbe generated to use the Company’s deferred tax assets and determined that it is not more-likely-than-not that the deferred tax assets would be realized in thenear future. Therefore, the Company recorded a full valuation allowance of approximately 47.2 million and $35.7 million on its deferred tax assets as ofDecember 31, 2015 and 2014, respectively. NOTE 11 - STOCKHOLDERS’ EQUITY As of December 31, 2015, the Company has 100,000,000 shares of Common Stock authorized, 10,000,000 shares of Series A Preferred Stock, and 7,000shares of Conditionally Redeemable 6% Preferred Stock authorized. Of the shares authorized, 29,166,590 shares of Common Stock, 7,500,000 shares ofSeries A Preferred Stock, and 2,000 shares of Conditionally Redeemable 6% Preferred Stock were issued and outstanding. During the year ended December 31, 2014, the Company issued 9,348,213 shares of Common Stock including 2,959,125 issued in connection with theJanuary 2014 Private Placement, 4,366,726 shares issued in connection with the January 2014 conversion of Debentures, 225,000 shares issued for placementfees in connection with the January 2014 Debenture conversion, 1,396,129 shares issued for interest owed in connection with outstanding Debentures,327,901 shares issued for the vesting of restricted stock grants to employees, board members, or consultants, and 90,000 shares issued to consultants forprofessional services received. During the year ended December 31, 2015, the Company granted 870,015 shares of Common Stock including 795,015 shares issued for restricted stock toemployees and board members and 75,000 issued to consultants for professional services valued at $365,002. F-31  January 2014 Private Placement In January 2014, the Company entered into and closed a series of subscription agreements with accredited investors, pursuant to which the Company issuedan aggregate of 2,959,125 units, with each unit consisting of (i) one share of Common Stock for $2.00 a share and (ii) one three-year warrant to purchase oneshare of Common Stock at an exercise price equal to $2.50 per share (together, the “Units”), for a purchase price of $2.00 per Unit, for aggregate grossproceeds of $5.24 million (the “January Private Placement”). The warrants became exercisable in July 2014. As of February 23, 2015, neither the CommonStock issued in the January Private Placement nor the Common Stock underlying the warrants has been registered for resale. The Company intends to file aresale registration statement during the year 2015 that will cover the Common Stock issued in the private placement and the Common Stock underlying thewarrants. The Company valued the warrants within the Unit, utilizing a Black Scholes Option Pricing Model using a volatility calculation of 65%, risk freerate at the date of grant, and a 3 year term, the relative fair value allocated to warrants were approximately $1.68 million. The Company paid TRW 243,000warrants valued using the Black Scholes option model at $203,000 and cash of approximately $668,000 million in financing fees to TRW, of whichapproximately $172,000 was reinvested into the private placement. 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 to purchase upto 1,556,017 shares of Common Stock, at an exercise price of $2.89 per share, for aggregate gross proceeds of $7.50 million. The Series A Preferred Stock hasa par value of $0.0001 per share, a stated value of $1,000 per share, a conversion price of $2.41 per share, and a liquidation preference to any junior securities.Except as otherwise required by law, holders of Series A Preferred Stock shall not be entitled to voting rights, except with respect to proposals to alter orchange adversely the powers, preferences or rights given to the Series A Preferred Stock, authorize or create any class of stock ranking senior to the Series APreferred Stock as to dividends, redemption or distribution of assets upon liquidation, amend its certificate of incorporation or other charter documents in anymanner that adversely affects any rights of the Preferred Stock holder, or increase the number of authorized Series A Preferred Stock. The holders of the SeriesA Preferred Stock are entitled to receive a dividend payable, at the election of the Company (subject to certain conditions as set forth in the Certificate ofDesignations), in cash or shares of Common Stock, at a rate of 8% per annum payable a day after the end of each quarter. The Series A Preferred Stock isconvertible at any time at the option of the holders, or at the Company’s discretion when the Common Stock trades above $7.50 for ten consecutive dayswith 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 anyaccrued and unpaid dividends, at any time, subject to certain conditions as set forth in the Certificate of Designations. In addition, holders of the Series APreferred Stock can require the Company to redeem the Series A Preferred upon the occurrence of certain triggering events, including (i) failure to timelydeliver shares of Common Stock after valid delivery of a notice of conversion by the holder; (ii) failure to have available a sufficient number of authorizedand unreserved shares of Common Stock to issue upon conversion; (iii) the occurrence of certain change of control transactions; (iv) the occurrence of certainevents of insolvency; and (v) the ineligibility of the Company to electronically transfer its shares via the Depository Trust Company or another establishedclearing corporation. The Series A Preferred Stock is classified as equity based on the following criteria: i) the redemption of the instrument at the control of the Company; ii) theinstrument is convertible into a fixed amount of shares at a conversion price of $2.41; iii) the instrument is closely related to the underlying Company’sCommon Stock; iv) the conversion option is indexed to the Company’s stock; v) the conversion option cannot be settled in cash and only can be redeemedat the discretion of the Company; vi) and the Series A Preferred Stock is not considered convertible debt. F-32  In connection with the issuance of the Series A Preferred Stock, the Company also issued a warrant for 50% of the amount of shares of Common Stock intowhich the Series A Preferred Stock is convertible. In connection with issuance of the Series A Preferred Stock, the beneficial conversion feature (“BCF”) was valued at $2.21 million and the fair value of thewarrant 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: $2.48 market price per share; exercise price of $2.89 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 $600,000. Conditionally Redeemable 6% Preferred Stock In August 2014, the Company designated 2,000 shares of its authorized preferred stock as Conditionally Redeemable 6% Preferred Stock, or the RedeemablePreferred. All 2,000 shares of Redeemable Preferred were issued in September 2014, pursuant to the Settlement Agreement with Hexagon. The RedeemablePreferred has the same par value and stated value characteristics as the Series A Preferred Stock, yet the Conditionally Redeemable 6% Preferred Stock is notconvertible into Common Stock or any other securities of the Company. Except as otherwise required by law, holders of the Redeemable Preferred shall notbe 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 unpaid dividends)at any time at the Company’s option, or at the Holders option upon the Company’s achievement of certain production and reserves thresholds. Thesethresholds 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-10value of its producing developed properties filed with the Securities and Exchange Commission exceeds $50 million. As of December 31, 2015, theCompany has accrued a cumulative dividend of $120,000. The total outstanding Redeemable Preferred was valued at approximately $1.17 million atDecember 31, 2015. Debenture Interest During the year ended December 31, 2014, the Company issued 1,396,129 shares of Common Stock for payment of yearly interest expense on the Debenturesvalued at $1.19 million. The interest option price is calculated using a 10 day VWAP discounted by 5% and applied to the outstanding interest. Warrants A summary of warrant activity for the twelve months ended December 31, 2015 and 2014: Warrants Weighted-AverageExercise Price Outstanding at January 1, 2014 6,773,913 5.24 Warrants issued in connection with conversion of debt 4,500,011 2.50 Warrants issued in connection with January 2014 private placement 2,959,124 2.50 Warrants issued to TR Winston as placement fee in January 2014 private placement 243,000 2.50 Warrants issued with Series A Preferred shares in May 2014 1,556,017 2.89 Warrants issued to Bristol (consultant) 1,000,000 2.00 Warrants issued to MDC (consultant) 100,000 2.00 Warrants issued to MDC (consultant) 250,000 2.33 Exercised, forfeited, or expired (375,000) (2.50)Outstanding at December 31, 2014 17,007,065 $3.59 Warrants issued to consultants 600,000 1.63 Warrants issued to Heartland 225,000 2.50 Warrants issued with Convertible Notes 11,800,008 .25 Exercised, forfeited, or expired (4,848,912) (6.13)Outstanding at December 31, 2015 24,783,161 $1.48 F-33  The aggregate intrinsic value associated with outstanding warrants was zero at December 31, 2015 and 2014, respectively, as the strike price of all warrantsexceeded the market price for Common Stock, based on the Company’s closing Common Stock price of $0.21 and $.72, respectively. The weighted averageremaining contract life was 2.13 years and 1.71 years as of December 31, 2015 and 2014. During the year ended December 31, 2015 and 2014, the Company issued warrants to purchase Common Stock for professional services. The warrants werevalued using a Black -Scholes option pricing model and $425,000 and $678,000 were expensed immediately for the years ended December 31, 2015 and2014, respectively. For a discussion of the assumptions used to value the warrants see Note 6 —Fair Value of Financial Instruments. NOTE 12 - SHARE BASED AND OTHER COMPENSATION Share-Based Compensation In September 2012, the Company adopted the 2012 Equity Incentive Plan (the “EIP”). The EIP was amended by the stockholders June 27, 2013, November13, 2013 and December 29, 2015. As of December 31, 2015, up to 10,000,000 shares of Common Stock are authorized for grant pursuant to the EIP. Eachmember of the Board of Directors and the management team has been periodically awarded stock options and/or restricted stock grants, and in the future maybe awarded such grants under the terms of the EIP. The value of employee services received in exchange for an award of equity instruments are based on the grant-date fair value of the award, recognized overthe period during which an employee is required to provide services in exchange for such award. During the year ended December 31, 2015, the Company granted 1,145,013 shares of restricted Common Stock and 4,800,000 options to purchase shares ofCommon Stock, to employees and directors. Also during the year ended December 31, 2015, the Company forfeited or cancelled 807,414 shares of restrictedCommon Stock and 2,300,000 stock options previously issued in connection with the termination of certain employees and directors. For the year endedDecember 31, 2015, stock based compensation was valued at $2.66 million. As a result, as of December 31, 2015, the Company had 1,009,373 restrictedshares of Common Stock and 6,083,333 options to purchase shares of Common Stock outstanding to employees and directors. Options issued to employeesand directors vest in equal installments over specified time periods during the service period or upon achievement of certain performance based operatingthresholds. During the year ended December 31, 2015, the Company also issued 75,000 shares of Common Stock to consultants for professional serviceswhich was not pursuant to an equity compensation plan. During the year ended December 31, 2014, the Company granted 324,860 shares of restricted Common Stock and 2,150,000 stock options, to employees,directors and consultants. Also during the year ended December 31, 2014, the Company forfeited 390,667 shares of restricted Common Stock and 2,366,667stock options previously issued in connection with the termination of certain employees, directors and consultants. As a result, as of December 31, 2014, theCompany had 1,630,667 restricted shares and 3,583,333 options to purchase common shares outstanding to employees and directors. Options issued toemployees vest in equal installments over specified time periods during the service period or upon achievement of certain performance based operatingthresholds. F-34  Compensation Costs As of December 31, 2015 As of December 31, 2014 (Dollar amounts in thousands) StockOptions Restricted Stock Total StockOptions Restricted Stock Total Stock-based compensation expensed $2,191 $469 $2,660 $1,242 $515 $1,757 Unamortized stock-based compensationcosts $2,091 $266 $2,357 $243 $107 $350 Weighted average amortization periodremaining* 2.18 1.05 2.75 1.01 * Only includes directors and employees which the options vest over time instead of performance criteria which the performance criteria has not been met asof December 31, 2015 and 2014, respectively. As of December 31, Statement of Cash Flows: 2015 2014 Common stock issued to investment bank for fees related to conversion of convertible debentures $- $686,250 Equity instruments issued for services and compensation 3,449,775 2,739,699 Non-equity (derivative) Bristol Warrant - 965,016 Total non-cash compensation in Statement of Cash Flows 3,449,775 4,390,965 Fair value of warrants issued with convertible Bridge financing 1,221,711 - Total non-cash $4,671,486 $4,390,965 Statement of Stockholder’s Equity : Common stock issued for BOD fees $215,002 $- Common stock issued for placement fees in connection with January 2014 conversion of convertible debt - 686,250 Stock based compensation for vesting of restricted stock 468,863 514,804 Stock based compensation for issuance of stock options 2,191,274 1,242,256 Common stock issued for professional services 150,000 305,049 Fair value of warrants issued for professional services 424,636 677,590 Fair value of warrants issued with bridge financing 1,221,711 - Total non-cash compensation in Statement of Stockholders’ Equity 4,671,486 3,425,949 Non-equity (derivative ) Bristol Warrant - 965,016 Total non-cash $4,671,486 $4,390,965 Restricted Stock A summary of restricted stock grant activity for the years ended December 31, 2015 and 2014 is presented below: Number ofShares WeightedAverageGrant DatePrice Outstanding at January 1, 2014 2,024,375 2.30 Granted 324,860 2.66 Issued (327,901) 1.88 Forfeited (390,667) 2.27 Outstanding at December 31, 2014 1,630,667 2.44 Granted 1,145,013 0.90 Issued (778,346) 0.66 Forfeited (128,333) 2.45 Outstanding at December 31, 2015 1,869,000 1.23 F-35  As of December 31, 2015, the Company had 1,519,001 shares vested but unissued and total unrecognized compensation cost related to the 349,999 unvestedshares of restricted stock was approximately $266,000, which is expected to be recognized over a weighted-average remaining service period of 1.05 years. During the year ended December 31, 2015 and 2014, the Company issued restricted stock for professional services. The restricted stock issued was valued atthe fair market value at the date of grant and vested over the useful life of the service contract. During the years ended December 31, 2015 and 2014 theCompany amortized $469,000 and $515,000, respectively relating to these contracts. Stock Options A summary of stock options activity for the years ended December 31, 2015 and 2014 is presented below: Stock Options Outstanding andExercisable Number of Options WeightedAverageExercise Price Numberof OptionsVested/Exercisable WeightedAverageRemaining ContractualLife (Years) Outstanding at January 1, 2014 3,800,000 $2.02 Granted 2,150,000 $2.68 Exercised - - Forfeited or cancelled (2,366,667) (2.39) Outstanding at December 31, 2014 3,583,333 $2.16 1,383,333 $4.24 Granted 4,800,000 $1.26 Exercised - Forfeited or cancelled (2,300,000) $(2.46) Outstanding at December 31, 2015 6,083,333 $1.46 2,966,666 $4.10 As of December 31, 2015, total unrecognized compensation costs relating to the outstanding options was $3.74 million, which is expected to be recognizedover the remaining vesting period of approximately 3.58 years. The outstanding options do not have any intrinsic value at year end, as their weighted average price is greater than the trading price at December 31, 2015.The average life of the options is 3 years and has no intrinsic value as of December 31, 2014. During the year ended December 31, 2015 and 2014, the Company issued options to purchase shares of Common Stock to certain officers and directors. Theoptions are valued using a Black Scholes model and amortized over the life of the option. During the years ended December 31, 2015 and 2014 the Companyamortized $2.19 million and $515,000, respectively relating to options outstanding. Employment and Separation Agreements Mr. Mirman In connection with his appointment as the Company’s President, the Company entered into an Employment Agreement with Mr. Mirman, dated September16, 2013. The agreement provides, among other things, that Mr. Mirman would receive an annual salary of $240,000 which was deferred until the Companysuccessfully consummated a financing of any kind of not less than $2 million in gross proceeds. Additionally, he was granted 100,000 shares of CommonStock, which vested immediately and were fully paid and non-assessable as an inducement for joining the Company. Mr. Mirman was granted an option topurchase 600,000 shares of Common Stock, at a strike price equal to the Company’s closing share price on the September 16, 2013, to become exercisableupon the date the Company achieved certain conditions specified in the agreement. The Board determined in September 2014 that those criteria had beenmet and consequently the options vested. Mr. Mirman was also provided an incentive bonus package and an additional stock option grant contingent on theCompany’s achievement of certain additional performance conditions. The Company engaged a third-party to complete a valuation of this incentive bonusand not having been paid out, has been recorded as a liability and valued at each reporting period. F-36  Effective as of March 30, 2015, the Company entered into an amended and restated employment agreement with Mr. Mirman, which replaced the prioragreement. The agreement has a three year term and provides for a $100,000 cash bonus due upon signing, base compensation of $350,000 per year, plus2,000,000 options to purchase shares of Common Stock where one-third of the options vest immediately and two-thirds vest in two annual installments oneach of the next two anniversaries of the grant date (the “Unvested Shares”). The Unvested Shares were subject to the approval of the stockholders of anincrease in the number of shares available for grant under the Plan, which was approved on December 29, 2015. The agreement also allows for additionalbonuses due based on the Company’s achievement of certain performance thresholds. Mr. Nanke In connection with the appointment of Mr. Nanke as the Company’s Executive Vice President and Chief Financial Officer, the Company entered into anexecutive employment agreement with Mr. Nanke, dated March 6, 2015. Pursuant to the terms of the agreement, Mr. Nanke will serve as the Company’sExecutive Vice President and Chief Financial Officer until his employment is terminated in accordance with the terms of the agreement. The agreementprovides, among other things, that Mr. Nanke will receive an annual salary of $240,000. Additionally, as of the effective date of the agreement, Mr. Nankewas granted (i) 100,000 restricted shares of Common Stock; (ii) paid a cash signing bonus of $100,000; and (iii) an incentive stock option to purchase up to750,000 shares of Common Stock, which vests in equal installments on each of the next three anniversaries of the effective date of the agreement. Mr. Nankewill also receive a cash incentive bonus if certain production thresholds are achieved by the Company and a performance bonus of $100,000 if the Companyachieves certain goals set forth in the agreement. In addition, the agreement provides for the payment of severance to Mr. Nanke in connection withtermination of his employment in certain circumstances, including termination by the Company without “cause” or upon Mr. Nanke’s resignation for “goodreason,” in each case subject to Mr. Nanke’s execution, non-revocation and delivery of a release agreement. Ms. Fuchs In connection with the appointment of Ms. Fuchs as the Company’s General Counsel, the Company entered into an executive employment agreement withMs. Fuchs dated March 16, 2015. Pursuant to the terms of the agreement, Ms. Fuchs will serve as the Company’s General Counsel until her employment isterminated in accordance with the terms of the agreement. The agreement provides, among other things, that Ms. Fuchs will receive an annual salary of$230,000. Additionally, as of the effective date of the agreement, Ms. Fuchs was granted (i) 50,000 restricted shares of Common Stock and (ii) an incentivestock option to purchase up to 300,000 shares of Common Stock, which vests in equal installments on each of the next three anniversaries of the effectivedate if the agreement. Ms. Fuchs will also receive a cash incentive bonus if certain production thresholds are achieved by the Company. In addition, theagreement provides for the payment of severance to Ms. Fuchs in connection with termination of her employment in certain circumstances, includingtermination by the Company without “cause” or upon Ms. Fuchs’s resignation for “good reason,” in each case subject to Ms. Fuchs’s execution, non-revocation and delivery of a release agreement. Mr. Ulwelling In connection with his original position of Principal Accounting Officer and Controller, Mr. Ulwelling entered into an employment agreement, dated as ofJanuary 19, 2012, which provided for a minimum base salary of $110,000 per year, a $15,000 signing bonus in 2012, an automatic increase of $15,000 uponachievement of specified performance targets and a grant of 25,000 shares of Common Stock to vest in equal installments over three years. F-37  Upon his appointment to Interim Chief Financial Officer in May of 2014, Mr. Ulwelling did not immediately enter into a new employment agreement and hisoriginal employment agreement remained in effect until February of 2015, when an executive employment agreement was entered into, dated as of February19, 2015, appointing him as the Company’s Chief Financial Officer. That agreement remained in effect as to his role of Principal Accounting Officer andController through the date of his resignation on October 15, 2015. Pursuant to the terms of the agreement, Mr. Ulwelling served as the Company’s Principal Accounting Officer and Controller until his employment terminated.The agreement provided, among other things, that Mr. Ulwelling would receive an annual salary of $175,000. Additionally, as of the effective date of theagreement, Mr. Ulwelling was (i) granted an option to purchase 400,000 shares of Common Stock, with an exercise price equal to the greater of fair marketvalue on the effective date or $2.50 per share, of which one-fourth of the option vested immediately, and the remainder of the option was to vest in equalinstallments on each of the next three anniversaries of the effective date. Mr. Ulwelling had the opportunity to receive a discretionary annual bonus equal to50% of his base salary, based on achievement of annual target performance goals established by the Company’s compensation committee. In addition, theagreement provided for the payment of severance to Mr. Ulwelling in connection with termination of his employment in certain circumstances, includingtermination by the Company without “cause” or upon Mr. Ulwelling’s resignation for “good reason,” in each case subject to Mr. Ulwelling’s execution, non-revocation and delivery of a release agreement. In October 2015, in connection with his resignation from all positions with the Company, Mr. Ulwelling forfeited 28,333 unvested restricted stock awardsand 300,000 stock option awards. W. Phillip Marcum In April 2014, the Company entered into a separation agreement (the “Marcum Agreement”) with W. Phillip Marcum, its former Chief Executive Officer, inconnection with his resignation from his positions with the Company. The Marcum Agreement provides, among other things, that, consistent with hisresignation for good reason under his Employment Agreement, the Company would pay him 12 months of severance through payroll continuation, in thegross amount of $220,000, less all applicable withholdings and taxes, that all stock options held by Mr. Marcum as of the time of his termination wouldimmediately vest, and that Mr. Marcum would remain eligible to receive any performance bonus granted by the Company to its senior executives withrespect to Company and/or executive performance in 2013. In addition, the Marcum Agreement provides that the Company would pay Mr. Marcum$150,000 in accrued base salary for his service in 2013, less all applicable withholdings and taxes, in exchange for Mr. Marcum’s forfeiture of the 93,750shares of unvested restricted Common Stock of the Company that was issued to Marcum in June 2013 in lieu of such base salary. Mr. Marcum may elect toapply amounts payable under the Marcum Agreement against his commitment to invest $125,000 in the Company’s previously disclosed private offering,upon stockholder approval of the participation of the Company’s officers and directors in that offering. The Marcum Agreement also contains certain mutualnon-disparagement covenants, as well as certain mutual confidentiality, non-solicitation and non-compete covenants. In addition, Mr. Marcum and theCompany each mutually released and discharged all known and unknown claims against the other and their respective representatives that they had orpresently may have, including claims relating to Mr. Marcum’s employment. The Marcum Agreement effectively terminated the previously disclosedEmployment Agreement entered into between Mr. Marcum and the Company, dated as of June 25, 2013, and all items were immediately accrued. In connection with the Marcum Agreement, the Company reversed the 200,000 unvested options previously issued to Mr. Marcum valued at approximately$0.07 million, and reissued fully vested options, which it valued utilizing the Black Scholes option pricing model at $0.42 million. The Company used aBlack Scholes option pricing model to value the 200,000 options which Mr. Marcum retained using the following variables: i) 200,000 options; ii) stockprice $ 3.50; iii) strike price $1.60; volatility 65%; and a total value of approximately $420,000 which was expensed immediately since under the terms ofthe Marcum Agreement, the Company was not to be provided any additional services. F-38  Robert A. Bell On May 1, 2014, Robert A. Bell entered into an employment agreement with the Company, pursuant to which he became the President and Chief OperatingOfficer. On August 1, 2014, the Company entered into a separation agreement with Mr. Bell (the “Separation Agreement”). The Separation Agreementprovides, among other things, that the Company would pay to Mr. Bell an aggregate of $100,000 in cash and issue to Mr. Bell 66,667 shares of CommonStock, in addition to satisfying the Company’s obligation to pay Mr. Bell $100,000 in cash and issue to Mr. Bell 33,333 shares of Common Stock. TheSeparation Agreement also contains certain mutual covenants, and reaffirms the survival of certain confidentiality provisions contained in Mr. Bell’semployment agreement. In addition, Mr. Bell and the Company each mutually released and discharged all known and unknown claims against the other andtheir respective representatives that they had or presently may have, including claims relating to Mr. Bell’s employment. The total amount of $206,000 wasexpensed in 2014. In connection with the termination of his employment, Mr. Bell forfeited the 1,500,000 stock options that were unvested at the time of his termination andthe Company reversed $108,000. A .Bradley Gabbard In May 2014, in connection with his resignation as CFO of the Company, A. Bradley Gabbard forfeited the 200,000 options that were unvested at the time ofhis termination, in accordance with the terms of the EIP. At the date of his resignation, the Company recorded a credit of approximately $0.07 million into thestockholder employee compensation expense account. Additionally, Mr. Gabbard forfeited his 52,084 shares of unvested restricted stock, for which theCompany recorded a reversal of approximately $59,000. Board of Directors For the year ended December 31, 2015, in connection with the execution of amended non-employee director award agreements each non-employee directorwas issued 100,000 shares of restricted Common Stock for a value of $165,000 and a total of 545,013 shares of restricted Common Stock 20were issued asstock in lieu of cash fees and director appointment anniversary awards. For the year ended December 31, 2015, the Company granted 1.35 million options to purchase Common Stock to certain directors, net of 2,000,000 millionoptions granted and forfeited in 2015, described in more detail above. Additionally, the Company cancelled 300,000 options for a certain officer that is nolonger with the Company. For the year ended December 31, 2014, in connection with the execution of amended independent award agreements, each director was issued 31,250 sharesof restricted Common Stock in lieu of a portion of their cash salaries, a total of 93,750 shares for three directors, for a value of $150,000. For the year ended December 31, 2014, the Company granted 650,000 options to purchase Common Stock to certain officer and directors, net of 1,500,000million options granted and forfeited in 2014, described in more detail above. Additionally, the Company cancelled 867,000 options for certain officers anddirectors that are no longer with the Company. NOTE 12 SUBSEQUENT EVENTS Convertible Notes In January, the Company issued an additional $800,000 in Convertible Notes. The aggregate principal amount of Convertible Notes issued from December29, 2015 through January 5, 2016, was $3.75 million. Additionally, on March 18, 2016, the Company issued an additional aggregate principal amount of $500,000 of Convertible Notes, which have the sameterms and conditions as the Convertible Notes with the exception of the maturity date, which is April 1, 2017. The proceeds were used to make advances toBrushy for payment of operating expenses pending completion of the Merger. If the Merger is not completed, these amounts are subject to repayment byBrushy. F-39  Director Fees. In connection with certain of the non-employee director appointment anniversaries and quarterly Board fees pursuant to each non-employee director awardagreement, the Company issued an additional 1,308,335 shares of restricted stock subsequent to year end. NOTE 13- SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) The following table sets forth information for the years ended December 31, 2015 and 2014 with respect to changes in the Company's proved (i.e. proveddeveloped and undeveloped) reserves: Crude Oil (Bbls) Natural Gas(Mcf) December 31, 2013 842,719 2,564,277 Purchase of reserves - - Revisions of previous estimates (127,574) (862,412)Extensions, discoveries 579,991 2,715,870 Sale/conveyance of reserves (361,901) (102,540)Production (33,508) (77,954)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 Proved Developed Reserves, included above: Balance, December 31, 2013 170,531 313,358 Balance, December 31, 2014 50,185 197,146 Balance, December 31, 2015 33,430 141,450 Proved Undeveloped Reserves, included above: Balance, December 31, 2013 672,188 2,250,920 Balance, December 31, 2014 849,542 4,040,095 Balance, December 31, 2015 - - As of December 31, 2015 and December 31, 2014, the Company had estimated proved reserves of 33,430 and 899,727 barrels of oil, respectively and141,450 and 4,237,241 thousand cubic feet ("MCF") of natural gas converted to BOE, respectively. The Company’s reserves are comprised of 59% and 56%crude oil and 41% and 44% natural gas on an energy equivalent basis, as of December 31, 2015 and December 31, 2014, respectively. The following values for the December 31, 2015 and December 31, 2014 oil and gas reserves are based on the 12 month arithmetic average first of monthprice January through December 31; resulting in a natural gas price of $2.79 and $6.70 per MMBtu (NYMEX price), respectively, and crude oil price of$42.59 and $82.77 per barrel (West Texas Intermediate price), respectively. All prices are then further adjusted for transportation, quality and basisdifferentials. F-40  The following summary sets forth the Company's future net cash flows relating to proved oil and gas reserves: For the Year Ended December 31, (in thousands) 2015 2014 Future oil and gas sales $1,819 $96,165 Future production costs (983) (22,895)Future development costs - (28,388)Future income tax expense (1) - - Future net cash flows 836 44,882 10% annual discount (375) (21,628)Standardized measure of discounted future net cash flows $608 $23,254 The principal sources of change in the standardized measure of discounted future net cash flows are (in thousands): 2015 2014 Balance at beginning of period $23,254 $23,342 Sales of oil and gas, net (146) (1,722)Net change in prices and production costs (26,115) (262)Net change in future development costs 20,626 2,781 Extensions and discoveries - 16,137 Acquisition of reserves - - Sale / conveyance of reserves - (11,514)Revisions of previous quantity estimates (19,336) (7,842)Previously estimated development costs incurred - - Net change in income taxes - - Accretion of discount 2,325 2,334 Balance at end of period $608 $23,254 (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. There were no taxes in any year as the tax basis and NOLs exceeded the futurenet revenue. A variety of methodologies are used to determine the Company’s proved reserve estimates. The principal methodologies employed are reservoir simulation,decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination ofthese methods is used to determine reserve estimates in substantially all of our fields. F-41 Exhibit 21.1 Subsidiaries of the Registrant Name of Subsidiary Jurisdiction of IncorporationLilis Merger Sub, Inc. 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 Form S-8 (File No. 333-185122) of our report dated April14, 2016, which includes an explanatory paragraph as to the Company’s ability to continue as a going concern, with respect to our audits of the financialstatements of Lilis Energy, Inc. as of December 31, 2015 and 2014 and for the years ended December 31, 2015 and 2014, which report is included in thisAnnual Report on Form 10-K of Lilis Energy, Inc. for the year ended December 31, 2015. /s/ Marcum llp Marcum llpNew York, NYApril 14, 2016 Exhibit 23.2 Petroleum Engineer Consent and Report Certificate of Qualification Forrest A. Garb & 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 the AnnualReport on Form 10-K of Lilis Energy, Inc. for the year ended December 31, 2015 (the “Annual Report”). We hereby further consent to the inclusion in theAnnual Report of estimates of oil and gas reserves contained in our report dated April 13, 2016, and to the inclusion of our report as an exhibit to the AnnualReport and in all current and future registration statements of the Company that incorporate by reference such Annual Report. /s/ Forrest A. Garb & Associates, Inc. Forrest A. Garb & Associates, Inc. Texas Registered Engineering Firm F-629 April 14, 2016 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 tomaterially affect, the registrant's internal control over financial reporting; and 5.The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which arereasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b)Any fraud, whether or not material, that involved management or other employees who have a significant role in the registrant's internalcontrol over financial reporting. By:/s/Abraham Mirman Abraham Mirman Chief Executive Officer April 14, 2016 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, Kevin K. Nanke, 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 tomaterially affect, the registrant's internal control over financial reporting; and 5.The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which arereasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b)Any fraud, whether or not material, that involved management or other employees who have a significant role in the registrant's internalcontrol over financial reporting. By:/s/ Kevin K. Nanke Kevin K. Nanke Executive Vice President and Chief Financial Officer April 14, 2016 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, 2015, 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 April 14, 2016 Exhibit 32.2 OFFICER'S CERTIFICATIONPURSUANT TOSECTION 906 OF THE SARBANES-OXLEY ACT OF 2002(18 U.S.C 1350) The undersigned, Kevin K. Nanke, the Executive Vice President and Chief Financial Officer of Lilis Energy, Inc., (the "Corporation"), in connection with theCorporation's Yearly Report on Form 10-K for the year ended December 31, 2015, as filed with the Securities and Exchange Commission on the date hereof(the "Report"), does hereby represent, warrant and certify pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, as amended, that, to the best of hisknowledge: 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/ Kevin K. Nanke Kevin K. Nanke Executive Vice President and Chief Financial Officer April 14, 2016 Exhibit 99.1 ESTIMATED RESERVES AND FUTURE NET REVENUE AS OF DECEMBER 31, 2015 ATTRIBUTABLE TO INTERESTS OWNED BY LILIS ENERGY, INC. IN CERTAIN OIL AND GAS PROPERTIES LOCATED IN COLORADO AND WYOMING (SEC PRICING) FFORREST A. GARB & ASSOCIATES, INC.INTERNATIONAL PETROLEUM CONSULTANTS  FORREST A. GARB & ASSOCIATES, INC. INTERNATIONAL PETROLEUM CONSULTANTS5310 HARVEST HILL ROAD, SUITE 275 - LB 152DALLAS, TEXAS 75230 - 5805Phone: (972) 788-1110 Fax: (972) 991-3160E-Mail: forgarb@forgarb.com April 13, 2016 Mr. Kevin NankeChief Financial OfficerLilis Energy, Inc.216 16th Street Suite 1350Denver, CO 80202 Re: SEC Filing Letter Dear Mr. Nanke: At your request, Forrest A. Garb & Associates, Inc. (FGA) has estimated the proved reserves and future net revenues, as of December 31, 2015,attributable to interests owned by Lilis Energy, Inc. (Lilis) in certain oil and gas properties located in Colorado and Wyoming. This evaluation wascompleted on March 28, 2016, and includes proved reserves only. Lilis has represented that these properties account for 100 percent of Lilis’s net provedreserves, as of December 31, 2015. This report has been prepared for Lilis’s filing with the U.S. Securities and Exchange Commission (SEC). This report has been prepared using the definitions and guidelines of the U.S. Securities and Exchange Commission (SEC), and with the exception ofthe exclusion of future income taxes, conforms to the FASB Accounting Standards Codification Topic 932, Extractive Industries – Oil and Gas. The SECguidelines specify the use of a 12-month first-day-of-the-month average benchmark price, a 10 percent per year discount factor, and constant oil and gasprices and costs.The following table summarizes the estimated total net proved reserves and future net revenue for the Lilis properties, as of December 31, 2015. Estimated Net Reserves1 Estimated Future Net Revenue Reserve Category Oil andCondensate(MBbl)2 Gas(MMcf)2 Undiscounted(M$)2 Discounted at10% Per Year3(M$)2 Proved Developed Producing 33.43 141.45 836.39 607.69 Total Proved4 33.43 141.45 836.39 607.69 1The definitions for all reserves incorporated in this study have been set forth in this report.2MBbl = thousands of barrels, MMcf = millions of cubic feet, M$ = thousands of dollars.3The discounted future net revenue is not represented to be the fair market value of these reserves.4The reserves and revenues in the summary table were estimated using the PHDWin economics program. Due to the rounding procedures used in thisprogram, there may be slight differences in the calculated and summed values. 2  ENGINEERING Proved oil and gas reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated withreasonable certainty to be economically producible from a given date forward. The basis for estimating the proved producing reserves was the extrapolationof historical production having an established decline trend. Volumetrics and/or analogy were used for forecasting properties where insufficient data werepresent for production decline extrapolation. Production histories were obtained from published production data and state reporting records purchased fromthe third party provider, Drillinginfo, and supplemented by Lilis where necessary. Lilis provided the available geologic and engineering data for FGA'sreview. Gas volumes are expressed in millions of cubic feet (MMcf) at standard temperature and pressure. Gas sales imbalances have not been taken intoaccount in the reserve estimates. The oil reserves shown in this study include crude oil and/or condensate. Oil volumes are expressed in thousands of barrels(MBbl), with one barrel equivalent to 42 United States gallons. ECONOMIC CONSIDERATIONS The benchmark oil and gas prices used in this study are the preceding 12-month averages of the first-day-of-the-month spot prices for the calendaryear 2015 posted for West Texas Intermediate (WTI) oil and Henry Hub natural gas. Oil prices are based on a benchmark price of $50.16 per barrel (bbl) andhave been adjusted by lease for gravity, transportation fees, and regional price differentials. Gas prices per thousand cubic feet (Mcf) are based on abenchmark price of $2.63 per million British thermal units (MMBtu) and have been adjusted by lease for Btu content, transportation fees, and regional pricedifferentials. Adjustments are based on the differential between historic oil and gas sales and the corresponding benchmark price. Average realized oil andgas prices for the proved properties after adjustments are $42.59/bbl and $2.79/Mcf, respectively. Lease operating expense (LOE) data were provided by Lilis for FGA’s review. All costs have been held constant in this evaluation. Lilis providedownership interests in the properties, and FGA accepted the extent and character of ownership (working interest and net revenue interest) as represented. Ourstaff conducted no independent well tests, property inspections, or audits of completion and operating expenses as part of this study. Existing or potential liabilities stemming from environmental conditions caused by current or past operating practices have not been considered inthis report. No costs are included in the projections of future net revenue or in the economic analyses to restore, repair, or improve the environmentalconditions of the properties studied to meet existing or future local, state, or federal regulations. The estimated future net revenues shown are those which should be realized from the sale of estimated oil and gas reserves after the deduction ofseverance taxes, ad valorem taxes, direct operating costs, and future capital expenditures. No deductions have been made for overhead, federal income taxes,or other indirect costs, such as interest expense and loan repayments. No abandonment costs or surface and well equipment salvage values have beenincluded. The estimated reserves included in the cash flow projections have not been adjusted for risk. The reserves included in this study are estimates onlyand should not be construed as exact quantities. Future conditions may affect recovery of estimated reserves and revenue, and all categories of reserves maybe subject to revision as more performance data become available. 3  The analysis and findings presented in this report represent FGA’s informed judgments based on accepted standards of professional engineeringpractice, but are subject to the generally recognized and unforeseen risks associated with the interpretation of geological, geophysical, and engineering data.The assumptions, data, methods, and procedures used in the preparation of this report are appropriate for the purpose served by the report. Future changes infederal, state, or local regulations may adversely impact the ability to recover the future oil and gas volumes expected. Changes in economic and marketconditions from the assumptions and parameters used in this study may cause the total quantity of future oil or gas recovered, actual production rates, pricesreceived, operating expenses, and capital costs to vary from the results presented in this report. PETROLEUM CONSULTANTS FGA is an independent firm of geologists and petroleum engineers. Neither the firm nor its employees own any interest in the properties studied, norhave we been employed on a contingency basis. FGA has used all necessary methods and procedures in the preparation of this report for the evaluation ofthese properties. This report was prepared under the supervision of Stacy M. Light, P.E. Registered Professional Engineer No. 106726, State of Texas and member ofthe Society of Petroleum Engineers. Ms. Light holds a Bachelor of Science degree in Petroleum Engineering from Texas A&M University and has more than18 years’ experience in oil and gas reservoir studies and reserves evaluations. Any distribution of this report or any part thereof must include this cover letter and the General Comments in their entirety. We appreciate theopportunity to submit this evaluation. Should you have any questions, please do not hesitate to contact us. Yours truly, /s/ Forrest A. Garb & Associates, Inc. Forrest A. Garb & Associates, Inc. Texas Registered Engineering Firm F-629 /s/ Stacy M. Light Stacy M. Light Senior Vice President Forrest A. Garb & Associates, Inc.SML/elt 4  FORREST A. GARB & ASSOCIATES, INC. GENERAL COMMENTS (1)The reserve estimates presented in this report have been calculated using deterministic procedures. The reserves shown in this report are those estimatedto be recoverable under the guidelines of the Securities and Exchange Commission (SEC). The definition for proved oil and gas reserves in accordancewith SEC Regulation S-X are set forth in this report. (2)The estimated future net revenue shown in the cash flow projections is that revenue which should be realized from the sale of the estimated net reserves.Surface and well equipment salvage values have not been considered in the revenue projections. Future net revenue as stated in this report is before thededuction of federal income tax. (3)The discounted future net revenue is not represented to be the fair market value of these reserves. The estimated reserves included in the cash flowprojections have not been adjusted for risk. (4)The reserves included in this study are estimates only and should not be construed as exact quantities. Future conditions may affect recovery ofestimated reserves and revenue, and all categories of reserves may be subject to revision as more performance data become available. (5)Extent and character of ownership, oil and gas prices, production data, direct operating costs, required capital expenditures, and other data furnishedhave been accepted as represented. No independent well tests, property inspections, or audits of operating expenses were conducted by our staff inconjunction with this study. (6)If investments or business decisions are to be made in reliance on these estimates by anyone other than our client, such a person, with the approval ofour client, is invited to visit our offices at his own expense so that he can evaluate the assumptions made and the completeness and extent of the dataavailable on which our estimates are based. (7)Gas contract differences, including take or pay claims, are not considered in this report. (8)Gas sales imbalances have not been taken into account in the reserve estimates. (9)Unless otherwise stated in the text, existing or potential liabilities stemming from environmental conditions caused by current or past operatingpractices have not been considered in this report. No costs are included in the projections of future net revenue or in our economic analyses to restore,repair, or improve the environmental conditions of the properties studied to meet existing or future local, state, or federal regulations. (10)Any distribution of this report or any part thereof must include these general comments and the cover letter in their entirety. (11)This report was prepared under the supervision of Stacy M. Light, Registered Professional Engineer No. 106726, State of Texas. General Comments - 1 FORREST A. GARB & ASSOCIATES, INC. DEFINITIONS FOR OIL AND GAS RESERVES** (1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase orlease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs,and other costs incurred in acquiring properties. (2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth,temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus mayprovide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogousreservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest: (i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) Same environment of deposition; (iii) Similar geological structure; and (iv) Same drive mechanism. (3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur,metals, and other non-hydrocarbons. (4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, whenproduced, is in the liquid phase at surface pressure and temperature. (5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience,engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure. (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. *These Reserves Definitions are those included in the Securities and Exchange Commission Regulation S-X as of January 1, 2010. Definitions - 1 (7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil andgas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs ofdevelopment activities, are costs incurred to: (i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific developmentdrilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developingthe proved reserves. (ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of wellequipment such as casing, tubing, pumping equipment, and the wellhead assembly. (iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, andproduction storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems. (iv) Provide improved recovery systems. (8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. Asexamples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group ofseveral fields and associated facilities with a common ownership may constitute a development project. (9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. (10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or isreasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil andgas producing activities as defined in paragraph (a)(16) of this section. (11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of thatdate. (12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to haveprospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs maybe incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types ofexploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are: (i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and otherexpenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological andgeophysical or G&G costs. Definitions - 2 (ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and themaintenance of land and lease records. (iii) Dry hole contributions and bottom hole contributions. (iv) Costs of drilling and equipping exploratory wells. (v) Costs of drilling exploratory-type stratigraphic test wells. (13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil orgas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test wellas those items are defined in this section. (14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir. (15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/orstratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious, strata, or laterally by localgeologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field.The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms ofbasins, trends, provinces, plays, areas-of-interest, etc. (16) Oil and gas producing activities. (i) Oil and gas producing activities include: (A) The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and originallocations; (B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from suchproperties; (C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition,construction, installation, and maintenance of field gathering and storage systems, such as: ( 1 ) Lifting the oil and gas to the surface; and ( 2 ) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and (D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable naturalresources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction. Definitions - 3 (17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. (i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plusprobable 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 available data areprogressively 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 similarprojects. (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 discontinuitiesand that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known(proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are incommunication with the proved reservoir. (vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potentialexists 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 reasonablecertainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations. (18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together withproved 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 estimated provedplus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered willequal or exceed the proved plus probable reserves estimates. Definitions - 4 (ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data areless certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probablereserves may be 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 hydrocarbons inplace than assumed for proved reserves. (iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section. (19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occurfor each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associatedprobabilities of occurrence. (20) Production costs. (i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operatingcosts of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part ofthe cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are: (A) Costs of labor to operate the wells and related equipment and facilities. (B) Repairs and maintenance. (C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities. (D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities. (E) Severance taxes. (ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, andmarketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation andapplicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization ofcapitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced alongwith production (lifting) costs identified above. (21) Proved area. The part of a property to which proved reserves have been specifically attributed. Definitions - 5 (22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, canbe estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economicconditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidenceindicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract thehydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. (i) The area of the 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 containeconomically producible oil 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 a wellpenetration 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 associated gascap, 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 favorable than in the reservoir as a whole, theoperation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes thereasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities. (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall bethe average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmeticaverage of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excludingescalations based upon future conditions. (23) Proved properties. Properties with proved reserves. Definitions - 6 (24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. Ifprobabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A highdegree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience(geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certainEUR is much more likely to increase or remain constant than to decrease. (25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested andhas been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogousformation. (26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a givendate, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there willexist, 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 allpermits and financing required to implement the project. Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs arepenetrated 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). (27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined byimpermeable rock or water barriers and is individual and separate from other reservoirs. (28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated tobe recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations. (29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gasinjection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion. (30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologiccondition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes testsidentified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if notdrilled in a known area or “development type” if drilled in a known area. Definitions - 7 (31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells onundrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of productionwhen drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they 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 injection orother 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. (32) Unproved properties. Properties with no proved reserves. Definitions - 8 

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