x
2018
| Nevada | 74-3231613 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
300 E. Sonterra Blvd.,
510, Houston, Texas 77057
(817) 585-9001
| Common Stock, $0.0001 par value | NYSE American | |
| Title of class | Name of exchange on which registered | |
Common Stock, $0.0001 par value
| Large accelerated filer | ¨ | Accelerated filer | ý |
| Non-accelerated filer | ¨ | Smaller reporting company | ý |
| Emerging growth company | ¨ | ||
NYSE American.
FORM 10-K ANNUAL REPORT
YEAR ENDED DECEMBER
LILIS ENERGY, INC.
| Page | ||
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. Except as required by law, we do not intend, and undertake no obligation, to update any forward-looking statement.
Many of these factors are beyond our ability to control or predict. These factors are not intended to represent a complete list of the generalrisks or specific factors that may affect us.
uncertainties described in this Annual Report Form occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those in any forward-looking statements.
GLOSSARY
In this Annual Report on Form 10-K,
Bbl. Stock tank barrel, or 42 U.S. gallons liquid volume, usedcontext otherwise requires, all references in this report in reference to crude, condensate“Lilis,” “we,” “us,” “our,” “ours,” or natural gas liquids.
Bcf. Billion cubic feet of natural gas.
Bcfe.Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas“the Company” are to one barrel of crude oil or condensate.
BLM.The Bureau of Land Management of the United States Department of the Interior.
BOE. One barrel of crude oil equivalent, determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.
BOE/d. Barrels of oil equivalent per day.
BO/d. Barrel of oil per day.
BTU or British Thermal Unit. The quantity of heat required to raise the temperature of one pound mass of water by 28.5 to 59.5 degrees Fahrenheit.
Completion. Installation of permanent equipment for production of oil or natural gas.
Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperatureLilis Energy, Inc. and pressure but that, when produced, is in the liquid phase at surface pressure and temperature.
Development well. A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.
Drilling locations. Total gross locations specifically quantified by management to be included in our multi-year drilling activities on existing acreage. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors.
Dry well or dry hole. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
Exploratory well. A well drilled to find a new field or to find a new reservoir. Generally an exploratory well in any well that is not a development well, an extension well, a service well or a stratigraphic well.
FERC.The Federal Energy Regulatory Commission.
Field. An area consisting of either a single reservoir or multiple reservoirs all grouped on or related to the same geological structural feature and/or stratigraphic condition.
Formation. An identifiable layer of subsurface rocks named after its geographical location and dominant rock type.
Gross acres, gross wells, or gross reserves.A well, acre or reserve in which we own a working interest, reported at the 100% or 8/8ths level. For example, the number of gross wells is the total number of wells in which we own a working interest.
Lease. A legal contract that specifies the terms of the business relationship between an energy company and a landowner or mineral rights holder on a particular tract of land.
Leasehold. Mineral rights leased in a certain area to form a project area.
Mbbls. One thousand barrels of crude oil or other liquid hydrocarbons.
Mboe. One thousand barrels of crude oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Mcf. One thousand cubic feet of natural gas.
Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
MMbtu. One million British Thermal Units.
MMcf. One million cubic feet of natural gas.
Net acres or net wells. The sum of fractional ownership working interests in gross acres or gross wells. The number of net acres or wells is the sum of the fractional working interests owned in gross acres or wells expressed as whole numbers and fractions of whole numbers.
NGL.Natural gas liquids, or liquid hydrocarbons found as a by-product of natural gas.
Overriding royalty interest. Is similar to a basic royalty interest except that it is created out of the working interest. For example, an operator possesses a standard lease providing for a basic royalty to the lessor or mineral rights owner of 1/8 of 8/8. This then entitles the operator to retain 7/8 of the total oil and natural gas produced. The 7/8 in this case is the 100% working interest the operator owns. This operator may assign his working interest to another operator subject to a retained 1/8 overriding royalty. This would then result in a basic royalty of 1/8, an overriding royalty of 1/8 and a working interest of 3/4. Overriding royalty interest owners have no financial or other obligation or responsibility for developing and operating the property. The only expenses borne by the overriding royalty owner are a share of the production or severance taxes and sometimes costs incurred to make the oil or gas salable.
Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.
Production. Natural resources, such as oil or gas, flowed or pumped out of the ground.
Productive well. A producing well or a well that is mechanically capable of production.
Proved developed oil and gas reserves. Proved developed oil and gas reserves are proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Proved reserves. Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
Proved undeveloped reserves. Proved undeveloped oil and gas reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
Project. A targeted development area where it is probable that commercial oil and/or gas can be produced from new wells.
Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
PV-10 (Present value of future net cash flow). The present value of estimated future revenues to be generated from the production of estimated proved reserves, 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 general and administrative expenses, debt service, future income tax expenses, depreciation, depletion and amortization or impairment, discounted using an annual discount 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, we believe it provides an indicative representation of the relative value of our company 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/or completing new reservoirs in an attempt to establish new production or increase or re-activate existing production.
Reserves. Estimated remaining quantities of oil, natural gas and gas liquids anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
Reservoir. A subsurface formation containing a natural accumulation of producible natural gas and/or oil that is naturally trapped by impermeable rock or other geologic structures or water barriers and is individual and separate from other reservoirs.
Secondary Recovery. A recovery process that uses mechanisms other than the natural pressure or fluid drive of the reservoir, such as gas injection or water flooding, to produce residual oil and natural gas remaining after the primary recovery phase.
Shut-in. A well suspended from production or injection but not abandoned.
Standardized measure. The present value of estimated future cash flows from proved oil and natural gas reserves, less future development, abandonment, production and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.
Successful. A well is determined to be successful if it is producing oil or natural gas in paying quantities.
Undeveloped acreage. Leased acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas regardless of whether such acreage contains proved reserves.
Water-flood. A method of secondary recovery in which water is injected into the reservoir formation to maintain or increase reservoir pressure and displace residual oil and enhance hydrocarbon recovery.
Working interest.The operating interest that gives the lessees/owners the right to drill, produce and conduct operating activities on the property, and to receive a share of the production revenue, subject to all royalties, overriding royalties and other burdens, all development costs, and all risks in connection therewith.
DJ Basin DJ Basin principles. the Estimating and Auditing of Oil and Natural Gas Reserves Information promulgated by the Society of Petroleum Engineer. Gas Production, Production Prices, and Production Costs amortization: a dry hole. resources. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects. We also compete with other oil and gas companies oil or natural gas under any existing contracts. position: Discharges. Federal and state occupational safety and health laws require us to organize and maintain information about hazardous materials used, released, or produced in our operations. Some of this information must be provided to our employees, state and local governmental authorities, and local citizens. We are also subject to the requirements and reporting framework set forth in the federal workplace standards. Oil and Gas Industry We are subject to the requirements of the OSHA and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes and We face substantial penalties and incur significant costs. Our crude oil sales are affected by the availability, terms and cost of transportation. competitors, as effective interstate and intrastate rates are equally applicable to all comparable shippers. an annual basis. proved reserves over time. ability to grow. detection, which could have a material adverse effect on our business. condition. 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. operations and performance. include: leasehold prospects under which oil and natural gas reserves may be discovered; drilling rigs and related equipment to explore for such reserves; and knowledgeable personnel to conduct all phases of oil and natural gas operations. We must compete for such resources with both major oil and natural gas companies and independent operators. operation. fires, explosions and blowouts; negligence of personnel; inclement weather; equipment or pipeline failure; abnormally pressured formations; and environmental pollution. These events may result in substantial losses or costs to our direct costs associated with incident response. to, the possibility that such third parties may not be available to us as and when needed and the possibility that we may not be able to properly control the timing and quality of work conducted with respect to our projects. If we experience significant delays in obtaining the services of such third parties or poor performance by such parties, our results of operations and stock price could be materially adversely affected. personnel or changes to our Board of Directors. Significant acquisitions and other strategic transactions may involve abandonment bonds; well spacing; unitization and pooling of properties; safety precautions; operational reporting; eminent domain and government takings; and taxation. key management personnel. Consolidated Financial Statements. Resources” for further information. Report. economically attractive terms. We generate the 2018 Compared to Year Ended December 31, 2017 2017: 2017: operation. during the year ended December 31, 2017, to 1,812,106 BOE during the year ended December 31, 2018. the monthly $55,000. During the year ended Changes of Debt Conversion and Warrant Derivatives cash received upon net settlement of commodity derivative instruments. Company’s option will occur on the same terms as conversion at the Lender’s option. the acquisition, exploration and development of oil and gas properties. The 2018. calculation. customer. The two months after the sale has occurred. described above have remediated the material weakness identified at December 31, 2017. Option ($) All Other ($) Total ($) Related XBRL Instance Document In our opinion, the consolidated financial statements . Statements of Operations was incorporated in the State of Nevada and is listed and traded on the American New York Stock Exchange. The Company is an independent oil and natural gas Mexico. Significant Accounting Policies The most significant operations, shareholders’ equity or cash flows. Equivalents stated at cost, which approximates fair value. For the year ended December 31, 2018, the ceiling value of the Company’s reserves was calculated based upon SEC pricing of $65.56 per barrel for oil and $3.10 per MMBtu for natural gas. following: customer. two months after the sale has occurred. The Company recognizes forfeitures as and when the stock awards are forfeited. 2017. DIVESTITURES Bristol/Heartland warrant 2017. The December 31, 2015 under certain conditions. It is never the Company’s intention to enter into derivative contracts for speculative trading purposes. respect to such provision on March 1, 2019. Securities Purchase Agreement occurred on January 31, 2018. satisfy awards under employee stock based payment plans. discounted at a rate of 10%. Energy, Inc. and its consolidated subsidiaries (collectively, “we,” “us,” “our,” “Lilis Energy,” “Lilis,” or the “Company”) is an upstream independent oil and gas company engagedfocused on the exploration, development, production, and acquisition of oil, natural gas and natural gas liquids, or NGLs, from properties in the acquisition, drillingPermian Basin. Our operations are focused in the Delaware Basin of the Permian in Winkler, Loving, and Reeves Counties, Texas and Lea County, New Mexico, where the production is approximately 74% crude oil and NGLs, or Liquids, a relatively high liquid production ratio compared to many of our peers. Over 90% our of revenues are generated from the sale of Liquids.and prospects. We were incorporated in August 2007 in the State of Nevada as Universal Holdings, Inc. Denver-Julesburg (DJ) Basin.October 2009, we changed our name to Recovery Energy, Inc. and in December 2013, we changed our name to Lilis Energy, Inc.On June 23, 2016, we completed thea transformative merger transaction contemplated by the Agreement and Plan of Merger dated as of December 29, 2015, as amended to date (the “Merger Agreement”) by and among us,with Brushy Resources, Inc., a Delaware corporation (“Brushy”) and Lilis Merger Sub, Inc., a Delaware corporation, a wholly-owned subsidiary of ours (“Merger Sub”). Pursuant to the terms of the Merger Agreement, at the effective time (the “Effective Time”Brushy Resources” or “Brushy”), Merger Sub merged with and into Brushy (the “Merger”), with Brushy continuing as the surviving corporation and becoming a wholly-owned subsidiary of ours.The Mergerwhich resulted in the acquisition of a substantial portion of the Company’s current assets in the Permian Basin. Given the stacked-pay opportunities and high rates of return in the Permian Basin, the Company determined that it would focus exclusively on expanding and developing its core Permian Basin assets and completed the divestiture of all of its oil and gas properties located in the DJ Basin in March 2017.propertiesacreage position to increase the value of our stock for our stockholders.as well asthrough strategic acquisitions, acreage exchanges, and organic leasing. We plan to achieve our objectives by implementing a business strategy focused on the majorityfollowing:current operating activity.Additionally,development, leasing and acquisition activity in connection withresponse to commodity prices, access to capital, and the Merger on June 23, 2016,performance of our wells. We recently announced our recapitalization, which allows us to better manage our assets (See "2019 Second Lien Term Loan Conversion and Borrowing Base Redetermination" and "Subsequent Events" for further information regarding our recapitalization).effected a 1-for-10 reverse stock split (the “Reverse Split”). As a result of the Reverse Split, every ten shares of issued and outstanding common stock were automatically converted into one newly issued and outstanding share of common stock, without any change in the par value per share. However, the number of authorized shares of common stock remained unchanged.Shortly after the Merger, we began to develop a drilling program on our properties using hydraulic fracture stimulation techniques. Our primary focus is drilling horizontal wells in the Delaware Basin of West Texas, which we believe will provide attractive returns on a majorityoperated approximately 99% of our acreage positions. Our goal isposition, giving us significant control over the pace of our development and allowing us to earn economicincrease value through operational and cost efficiencies. We intend to obtain the highest possible returns on the capital we expend on our development projects using results from the wells we have completed and the operational expertise of our management team. We will continue to focus on operational efficiencies, including midstream costs, salt water disposal, and capital costs of our development wells in order to maximize returns to our shareholders throughstockholders. We have increased our operational efficiency by entering into various infrastructure transactions, and we have structured our balance sheet with the intent to achieve cash flow neutrality in 2019 and significantly reduce our leverage profile over time. Additionally, we have an active hedging program to provide certainty regarding our cash flow and protect returns from new production of oil, natural gas and NGLs, as well as through derisking theour development profile of our portfolio of properties in order to add overall value. Our drilling program utilizes the development of new horizontal wells across several potentially productive formationsactivity in the Delaware Basin but initially targeting the Wolfcamp formation. We drilled our first horizontal well in late 2016 and completed it in February 2017.Overviewevent of Our Business and StrategyWe are an oil and natural gas company, engageddecreases in the acquisition, developmentprices received for our production.productionDelineating Acreage. We plan to drill and develop our existing acreage base of conventional and unconventional oil and natural gas properties. We have accumulated approximately 6,924 net28,500 gross (20,400 net) acres in the Delaware Basin, which we believe will maximize our resource potential and increase value to our stockholders. Our drilling activity during 2018 was predominantly focused on the horizontal development and delineation of our core acreage position in the Delaware Basin. We increased our net sales production volumes by 215% to 4,965 BOE/d in 2018, as compared to 2017. We averaged 8,081 net BOE/d from December 25 through December 31, 2018, achieving our 2018 year-end exit rate target of 8,000 BOE/d. Additionally, as a result of our development efforts, acreage exchanges and acquisitions, our proved reserves increased 273% from December 31, 2017, to approximately 42,707 MBOE (thousand barrels of oil equivalent) as of December 31, 2018. Our proved reserves were Liquids rich, being comprised of approximately 69% Liquids (50% oil and 19% NGLs) and 31% natural gas.LovingReeves Counties, Texas and Lea County, New Mexico. We believe our properties form part of the core of the Delaware Basin. Based on our drilling to date and results from nearby wells, we have identified approximately 1,175 potential horizontal well locations on our acreage, including approximately 700 longer lateral locations. Our leasehold position is largely contiguous, allowinghas significant stacked-pay potential, which we believe includes at least five to seven productive zones. We believe that our inventory of drilling locations will allow us to maximize development efficiency, manage full-cycle finding costsgrow our reserves and potentially enabling us to generate higher returnsproduction at attractive rates of return based on current expectations for our shareholders. In addition, 66%commodity prices.positions is held by production, and we are the named operator on 100% of our acreage. These characteristics givewhich gives us significant control over the pace of our development and the ability to design a more efficient and profitable drilling program that maximizesto maximize recovery of hydrocarbons.oil and natural gas. Based on our drilling and production results to date and well-established offset operator activity in and around our project areas, we believe there are relatively low geologic risks and ample repeatable drilling opportunities across our core acreage.expectbelieve our financial position is strong and sufficient to fund our drilling and completion operations currently planned for 2019. In October 2018, we announced our entry into a new five-year $500 million senior secured reserve based revolving credit facility (“Revolving Credit Agreement”) with an initial borrowing base of $95 million, that substantially allrefinanced our first-lien term loan with Riverstone Credit Partners, LLC. As of December 7, 2018, the borrowing base of our estimated 2017Revolving Credit Agreement had increased to $108 million. The Company enhanced liquidity through the Revolving Credit Agreement and through a tack-on to the outstanding Series C Preferred Stock (as hereinafter defined). Additionally, the Company converted a portion of its Second Lien Term Loan (as hereinafter defined) to a combination of preferred and common equity, which resulted in a significant paid-in-kind interest expense savings. We have a solid relationship with Värde Partners, Inc. and its affiliates, who have partnered with us since the time of the Brushy Resources transaction and provided us with access to significant capital expenditure budget will be focused on theresources and financing opportunities. The Company had increased its liquidity to $54.1 million as of year-end 2018, including $33 million in availability under its Revolving Credit Agreement and $21.1 million in cash. Additionally, we recently announced our recapitalization, which allows us to better manage our assets (See "2019 Second Lien Term Loan Conversion and Borrowing Base Redetermination" and "Subsequent Events" for further information regarding our recapitalization).expansion ofstrategic acquisitions. We believe that our Delaware Basin acreageteam’s operational expertise and operations. We also planextensive experience through various commodity price cycles position us to continueoperate effectively and efficiently and, in turn, will help increase returns and value to selectivelyour stockholders.opportunistically pursue strategic bolt-on acreage acquisitions.As of March 1, 2017, our net production was 618 Boe/d (44% oil and liquids) of which 522 Boe/d was from our Delaware Basin area and 96 Boe/d from our Denver-Julesburg Basin area. Natural Gas Properties2016, on consolidated basis,2018, we had proved reserves of 1,195 MBoe (46% oil and liquids).Our Delaware Basin PropertiesWe haveowned leasehold acreage in approximately 6,924 net28,500 gross (20,400 net) acres in the Delaware Basin, comprised of 6,424approximately 16,300 net acres in Winkler, Loving, and LovingReeves Counties, Texas and 500approximately 4,100 net acres in Lea County, New Mexico. Average net sales production volumes from our properties increased approximately 215% to 4,965 BOE/d in 2018 from 1,576 BOE/d in 2017. We averaged 8,081 net BOE/d from December 25 through December 31, 2018, achieving our 2018 year-end exit rate target of 8,000 BOE/d.aerial extentfollowing table presents our estimated net proved oil and natural gas reserves as of December 31, 2018, 2017 and 2016, based on the reserve reports prepared by Cawley, Gillespie & Associates, Inc. Each reserve report has been prepared in accordance with the rules and regulations of the SEC. All of our proved reserves included in the reserve reports are located in the Delaware Basin stretches across Ward, Reeves, Loving, Winkler, Pecos,of the Permian Basin:Culberson Counties in Texas and also runs north into Lea and Eddy Counties in New Mexico. The Delaware Basin is comprisedGas Reserves For the Year Ended December 31, 2018 2017 2016 Proved Developed Reserves Oil (MBbls) 6,278 2,531 551 NGLs (MBbls) 2,654 645 3 Total Liquids (MBbls) 8,932 3,176 554 Natural Gas (MMcf) 27,046 6,594 3,872 Total MBOE 13,440 4,275 1,199 Proved Undeveloped Reserves Oil (MBbls) 14,927 4,640 — NGLs (MBbls) 5,723 960 — Total Liquids (MBbls) 20,650 5,600 — Natural Gas (MMcf) 51,703 9,466 — Total MBOE 29,267 7,178 — Total Proved Reserves Oil (MBbls) 21,205 7,171 551 NGLs (MBbls) 8,377 1,605 3 Total Liquids (MBbls) 29,582 8,776 554 Natural Gas (MMcf) 78,749 16,060 3,872 Total MBOE 42,707 11,453 1,199 multiple stacked petroleum systems. Drilling and completion technology has evolved with more modern vintage wells utilizing longer laterals, more numerous fracture stimulation stages, and higher volumesDecember 31, 2018, we had a total of proppant. Our 201729,267 MBOE proved undeveloped reserves. During 2018, we added 22,088 MBOE of proved undeveloped (“PUD”) reserves through the extension of proved acreage, primarily as a result of successful drilling program will primarily target the Wolfcamp formation in up to 10 wells. We are targeting horizontal lateral lengths of 5,000 to 7,500 feet, holding hydraulic fracture stimulation stages per wellbore at each 200 foot increment, and an average of 2,200 pounds of proppant per lateral foot. Considering offset operator activity and our internal estimates, we believe our net average well cost will be between approximately $6.0 million and $8.0 million per well based on the lateral length range of 5,000 to 7,500 feet, with average estimated ultimate recoveries, or EURs, ranging from approximately 738 to 915 MBoe per well, and initial 30-day average production ranging between approximately 1,200 to over 1,750 Boe/d per well.6Our Denver-Julesburg Basin PropertiesIn addition to our core Delaware Basin focus area, we have approximately 14,254 net acres in the Denver-Julesburg Basin (“DJ Basin”) comprised of 280 net acresproperties in the core of the Wattenberg fieldDelaware Basin in WeldWinkler, Loving, and Reeves Counties, Texas and Lea County, Colorado and 13,974 net acresNew Mexico.Laramie County, Wyoming, Nebraska and other partsour PUDs was partially offset by the reclassification of Colorado. Our acreage position has multi-zone potential with producing wells2,470 MBOE, previously included in the Niobrara, Codell, and J Sand. Ouryear-end 2017 capital expenditure budget does not contemplate committing significant capitalPUDs, to our DJ Basin project area, and we are currently reviewing strategic alternatives with respect to these properties.Business Strengths and StrategiesOur primary business objective is to increase our Delaware Basin leasehold position, reserves, production and cash flows at attractive rates of return on invested capital in order to enhance shareholder value. To achieve this objective, key elementsPDPs as a result of our strategy include:·Geographic focus in one of North America’s leading unconventional oil plays. We have accumulated a leasehold position of approximately 6,924 net acres in the Delaware Basin as of March 1, 2017. We believe the Delaware Basin has one of the highest rates of return among such formations in North America based on results of offset operators. In addition to leveraging our technical expertise in this core area, our geographically-concentrated acreage position allows us to capitalize on economies of scale with respect to drilling and production costs. Based on our drilling and production results to date and well-established offset operator activity in and around our project areas, we believe there are relatively low geologic risks and ample repeatable drilling opportunities across our core Delaware Basin operating area. We plan on allocating all of our 2017 capital budget to our Delaware Basin activities.·Develop our Delaware Basin leasehold position. We intend to focus on developing our acreage position in the Delaware Basin in order to maximize the value of our resource potential through utilizing the best-in-class drilling and completion techniques at the lowest possible costs. Through the development of our properties, we will seek to derisk our acreage position and drilling program and substantially increase our production and cash flow, thereby increasing the value of our properties. Our current leasehold position in the Delaware Basin has significant stacked-pay potential. We currently estimate our properties include at least seven productive zones and hold approximately 500 future drilling locations across all of the productive zones within this position. Initially, we intend to focus our horizontal development on the Wolfcamp formation, followed by the Bone Spring and Avalon formations through a combination of re-entering existing vertical wellbores and new drilling locations.·Pursue strategic acquisitions, organic leasing, and other creative structures to continue to develop and grow our production and leasehold position. We continue to identify and seek to acquire additional acreage and producing assets in the Delaware Basin. We believe that we can continue our successful track record of growing our acreage position in and around our core area at attractive costs. Since entering the Delaware Basin in June 2016, we have grown our acreage position 98% from 3,500 net acres to 6,924. We have accomplished this through buying smaller packages that are complementary to our core position and also by acquiring smaller, fragmented working interest positions on existing leaseholds.·Leverage our extensive operational expertise to reduce costs and enhance returns. We are focused on continuously improving our operating costs and metrics. We evaluate our operating metrics against those of other operators in our area in order to measure our performance and optimize our drilling and completion techniques. We utilize this process to make informed decisions about our capital expenditure program and drilling and completion activity. We intend to leverage our contiguous acreage position and our knowledge of the Delaware Basin to capture operational and economic efficiencies.·Employ leading drilling and completion techniques. We intend to employ industry best practices well design drilling and completion techniques by replicating leading Delaware Basin operators. Our contiguous acreage position is offset by RSP Permian, Matador, Devon, Shell, Anadarko, and XTO, among other operators, and we will continue to observe and monitor their drilling activity and well results in the area as we execute on our development plan.·Maintain financial liquidity and flexibility. We intend to utilize cash flow from operations, available working capital, borrowings under our multiple-draw term loan and access the capital markets in order to fund and execute our capital expenditure and development program. We believe this financial liquidity and flexibility will result in steady growth in leasehold, production, cash flow and proved reserves.·Hedging.We intend to opportunistically use commodity price hedging instruments to reduce our exposure to oil and natural gas price fluctuations and to help ensure that we have adequate cash flow to fund our debt service costs and capital programs. We intend to use hedging primarily to manage price risks and returns on certain acquisitions and drilling programs. Our policy is to consider hedging an appropriate portion of our production at commodity prices we deem attractive.
horizontal development of our properties. Costs incurred relating to the development of PUDs were approximately $68.3 million during 2018.7Principal OilGas InterestsAll references to production, sales volumes and$72.1 million in 2022.netlimited by development drilling activity that we intend to undertake during the 2019 to 2022 timeframe. At December 31, 2018, we had no reserves that remained undeveloped for five or more years, and all PUD drilling locations are currently scheduled to be drilled within five years of their initial recording. Forinterest unless otherwise indicated.Asconsolidated financial statements in Item 15 of December 31, 2016, we owned interests in approximately 19,968 net acres, of which 14,994 net acres are classified as undeveloped acreagethis Annual Reportall of which are located in west Texasestimates were compiled and New Mexico within the Delaware Basinprepared internally and Colorado, Wyoming and Nebraska within the DJ Basin. Our primary targets within the Delaware Basin are the Wolfcamp formation as well as the Bone Springs and Avalon Formations.As of December 31, 2016 and March 1, 2017, we had 2 gross (1.2 net) and 1 gross (0.6 net) wells in the process of being drilled, respectively, all in the Delaware Basin.ReservesThe table below presents summary information with respect to the estimates ofaudited by our proved oil and gas reserves for the years ended December 31, 2016 and 2015. We engagedthird-party independent consultants, Cawley, Gillespie & Associates, Inc. (“CG&A”), as described in more detail herein, in compliance with SEC definitions and Forrest A. Garb & Associates to audit internally preparedguidance and in accordance with generally accepted petroleum engineering estimates for all of our proved reserves at year-end 2016 and 2015, respectively.Of these reserves, approximately 50% were classified as Proved Developed Producing (“PDP”). Proved Undeveloped (“PUD”) and Proved Non-Producing (“PNP”) included in this estimate are from 0 vertical well locations and 2 horizontal well locations. As of December 31, 2016, total proved reserves were approximately 46% oil and NGLs and 54% natural gas. As of December 31, 2015, total proved reserves were approximately 59% oil and NGLs and 41% natural gas.The following table provides summary information regarding our proved reserves as of December 31, 2016 and 2015, and production for the years ended December 31, 2016 and 2015. Estimated Total Proved Reserves December 31, 2016 2015 Delaware
Basin Total Delaware
Basin Total Oil (MMBBL) 0.455 0.096 0.551 - 0.033 0.033 Natural Gas (BCF) 3.507 0.365 3.872 - 0.141 0.141 Total (MMBOE) 1.04 0.156 1.196 - 0.057 0.057 % Oil 44 % 61 % - 59 % % Developed 100 % 100 % - 100 % Avg. Net Production (BOE/D) 317 87 404 - 215 215 During the years ended December 31, 2016 and 2015, we recognized an impairment expense of approximately $4.7 million and $24.5 million, respectively. The $4.7 million impairment charge during the year ended December 31, 2016 was primarily due to the lower commodity prices sustained for the majority of 2016 in the DJ Basin and the $24.5 million impairment charge for the year ended December 31, 2015 was attributable to the lack of capital to develop our undeveloped oil and gas properties and lower commodity prices.Securities Exchange Commission (the “SEC”).SEC. Responsibility for compliance in reserve bookings is delegated to our Chief Financial Officer with assistance from our senior geologist consultant and a senior reserve engineering consultant. In 2016, we established a Reserves Committee to provide additional oversightof our reserves estimation and certification process. The members of the Reserves Committee consist of Brennan Short, our Chief Operating Officer, Ron Ormand, our Executive Chairman and Glenn Dawson, a member of our Board of Directors.
reservoir engineer.8reserve engineering consultantreservoir engineer and our senior geologist and other consultants who evaluate all available geological and engineering data, under the guidance of theour Chief Financial Officer. This data, in conjunction with economic data and ownership information, is used in making a determination of estimated proved reserve quantities. The 2016 reserve process was overseen by Chris Cantrell, our senior reservoir engineer, has overseen our reserve engineering consultant.processes since 2016. Mr. Cantrell holdsreceived a Bachelor of Science degree in Petroleum Engineering conferred byfrom Texas A&M University in 1995. He is a registered professional engineer licensed in the State of Texas, license number 90521.Texas. He has been continuously involved in evaluating oil and gas properties since 1997 and is a member of the Society of Petroleum Engineers and the American Petroleum Institute.Third-partyAnstudy as of December 31, 2016, was performed by CG&Astudies using its own engineering assumptions and otherthe economic data provided by us. All of our total calculated proved reserve PV-10 value was audited by CG&A. &A, and all of the information regarding our 2018, 2017, and 2016 reserves in this Annual Report is derived from CG&A’s reports.Senior Vice President of CG&A, who received a Bachelor of Science degree in Petroleum Engineering from the University of Texas and is a registered Professional Engineer in the StatesState of Texas. He is also a member of the Society of Petroleum Engineers.The Mr. Brooker and the other technical persons employed by CG&A report dated January 12, 2017, is filed as Exhibit 99.1engaged in the reserve study met the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to this Annual Report on Form 10-K.and 2015, commodity prices overwe based the prior 12-month period and year end costs were used in estimatingestimated discounted future net cash flows from proved reserves on the 12-month average oil and natural gas index prices, calculated as the un-weighted arithmetic average for the first-day-of-the-month price for each month and costs in accordance with SEC guidelines.In addition to a third-party reserve study, our reserves andeffect on the corresponding report are reviewed by our Chief Financial Officer, geologist and the Audit Committeedate of our Board of Directors. Our Chief Financial Officer is responsible for reviewing and verifying that the estimate, holding the prices and costs constant throughout the life of proved reserves is reasonable, complete,the properties.accurate. The Audit Committee of our Board of Directors reviews the final reserves estimate in conjunction with CG&A’s audit letter. in which we held an interest during the periods indicated,indicated: For the Years Ended December 31, 2018 2017 2016 Production Oil (Bbls)-net production 1,089,724 371,993 61,088 Oil (per Bbl)-average realized price $ 53.26 $ 47.92 $ 39.59 Natural gas liquids (Bbls)-net production 246,425 73,875 11,355 Natural gas liquids (per Bbl)-average realized price $ 28.11 $ 22.49 $ 15.22 Natural Gas (Mcf)-production 2,855,739 776,164 332,643 Natural Gas (per Mcf)-average realized price $ 1.84 $ 2.74 $ 2.54 Barrels of oil equivalent (BOE) 1,812,106 575,229 127,863 Average daily net production (BOE) 4,965 1,576 350 Average Sales Price per BOE $ 38.75 $ 37.57 $ 26.87 production cost per BOE: For the Year Ended
December 31, 2016 2015 Product Oil (Bbl.) 61,088 7,067 Oil (Bbls)-average price $ 39.59 $ 41.36 Natural Gas (MCFE)-volume 400,775 32,291 Natural Gas (MCFE)-average price $ 2.54 $ 2.39 Barrels of oil equivalent (BOE) 127,863 12,449 Average daily net production (BOE) 350 34 Average Price per BOE $ 26.87 $ 29.67 (1)Includes proceeds from the sale ofNatural Gas Production Costs, Production Taxes, Depreciation, Depletion, and Amortization gas liquids (“NGL’s”)9 For the Year Ended
December 31, 2016 2015 Production costs per BOE $ 9.75 $ 15.70 Production taxes per BOE (1.30 ) 2.24 Depreciation, depletion, and amortization per BOE 12.25 46.93 Total operating costs per BOE $ 20.70 $ 64.87 Gross margin per BOE $ 6.17 $ (35.20 ) Gross margin percentage 23 % (119 )% Oil and gas production costs, production taxes, and depreciation, depletion and amortizationDrilling Activity For the Years Ended December 31, 2018 2017 2016 Production costs per BOE $ 9.51 $ 12.21 $ 12.43 Production taxes per BOE 2.05 2.06 (1.30 ) Depreciation, depletion, and amortization per BOE 14.00 12.21 12.25 Total operating costs per BOE $ 25.56 $ 26.48 $ 23.38 Undeveloped Acreage Developed Acreage Total Gross Net Gross Net Gross Net Delaware Basin 14,200 9,000 14,300 11,400 28,500 20,400 2019 2020 2021 Delaware Basin 1,840 6,197 1,350 2016,2018, we have drilled 1.2 net productive wells.As of December 31, 2016 and 2015, we had working interests in 3527.0 gross (21(24.9 net) oil wells and 611.0 gross (1.27(8.1 net) wells, respectively. natural gas wells. A net well is our percentage ownership interest in a gross well.but are currently shut-in.including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Multiple completions in the same wellbore are counted as one well. A well is categorized under state reporting regulations as an oil well or a natural gas well based on the ratio of natural gas to oil produced when it first commenced production, and such designation may not be indicative of current production.Acreage2016, we owned 36 producing2018, 6.0 gross (3.8 net) wells within the Delaware Basin in Texaswere drilled but not yet completed. All of these wells were successful, and New Mexico and in the DJ Basin in Colorado, as well as approximately 34,858 gross (19,968 net) acres, of which 25,752 gross (14,994 net) acresnone were classified as undeveloped acreage. Our primary assets included acreage located in Winkler and Loving Counties in Texas, Lea County in New Mexico; Laramie and Goshen Counties in Wyoming; Banner, Kimball, and Scotts Bluff Counties in Nebraska; and Weld, Arapahoe and Elbert Counties in Colorado.As of December 31, 2015, we owned 8 producing wells in Wyoming, Nebraska and Colorado within the DJ Basin, as well as approximately 18,000 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 Laramie and Goshen Counties in Wyoming; Banner, Kimball, and Scotts Bluff Counties in Nebraska; and Weld, Arapahoe and Elbert Counties in Colorado.our gross and net developed and undeveloped acreage asinformation with respect to the number of December 31, 2016 and 2015: Undeveloped Developed Gross Net Gross Net DJ Basin 16,678 13,576 1,923 678 Delaware Basin 9,074 1,418 7,183 4,295 Total acreage as of December 31, 2016 25,752 14,994 9,106 4,973 DJ Basin 10,000 8,000 8,000 8,000 Total acreage as of December 31, 2015 10,000 8,000 8,000 8,000 Aswells completed during the periods indicated. Each of March 1, 2017, our inventory of developed and undeveloped acreage includes approximately 40,618 gross (21,178 net) acres, of which 9,106 gross (5,248 net) acres that are held by production. We will continue to pursue additional properties, acquire other properties primarily targetedthese wells was drilled in the Delaware Basin but potentially throughout North America,in the Permian Basin. Year Ended December 31, 2018 2017 2016 Gross Net Gross Net Gross Net Exploratory: Productive 9.00 8.7 5.0 4.2 — — Dry — — — — — — Development: Productive 6.0 5.6 — — — — Dry — — — — — — Total: Productive 15.0 14.3 5.0 4.2 — — Dry — — — — — drill wellsshut-in awaiting infrastructure.coreleasehold properties is good, defensible and customary with practices in the oil and natural gas industry, subject to holdsuch exceptions that we believe do not materially detract from the property by production if financing is available to us and theuse of such properties. Our properties are economic.10Titlepotentially subject to PropertiesApproximately 66%customary royalty and other interests, liens for current taxes, and other burdens which we be do not materially interfere with the use of or affect our leasehold interests are held by production, withcarrying value of the properties. The majority of our Delaware Basin leasehold position is also subject to mortgages securing indebtedness under our credit and guarantee agreement. The credit agreement was entered into on September 29, 2016 (the “Credit Agreement”) by and among our wholly-owned subsidiaries, Brushy, ImPetro Operating, LLC, a Delaware limited liability company (“Operating”) and ImPetro Resources, LLC, a Delaware limited liability company (“Resources”, and together with Brushy and Operating, the “Borrowers”), and the lenders party thereto (each a “Lender” and together, the “Lenders”) and T.R. Winston & Company, LLC acting as collateral agent. We believe the security interests granted indoof which we are not materially interferethe record owner, we rely on contracts with the useowner or operator of the property or affectassignment of leases, pursuant to which, among other things, we generally have the value of, such properties.Marketing and PricingWe derive revenue and cash flow principally from the sale of oil and natural gas. As a result,right to have our revenues are determined, to a large degree, by prevailing prices for crude oil and natural gas. We sell our oil and natural gasinterest placed on the open market at prevailing market prices or through forward delivery contracts. The market price for oil and natural gas is dictated by supply and demand, and we cannot accurately predict or control the price we may receive for our oil and natural gas.Our revenues, cash flows, profitability and future rate of growth will depend substantially upon prevailing prices for oil and natural gas. Prices may also affect the amount of cash flow available for capital expenditures and other cash requirements and our ability to borrow money or raise additional capital. Lower prices may also adversely affect the value of our reserves and make it uneconomical for us to commence or continue production levels of natural gas and crude oil. Historically, the prices received for oil and natural gas have fluctuated widely. Among the factors that can cause these fluctuations are:·changes in global supply and demand for oil and natural gas;·the actions of the Organization of Petroleum Exporting Countries;·the price and quantity of imports of foreign oil and natural gas;·acts of war or terrorism;·political conditions and events, including embargoes, affecting oil-producing activity;·the level of global oil and natural gas exploration and production activity;·the level of global oil and natural gas inventories;·weather conditions;·technological advances affecting energy consumption;·transportation options from trucking, rail, and pipeline; and·the price and availability of alternative fuels.Furthermore, regional natural gas, condensate, oil and NGL prices may move independently of broad industry price trends. Because some of our operations are located outside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTI or other major market pricing.From time to time, we may enter into derivative contracts. These contracts economically hedge our exposure to decreases in the prices of oil 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, 2016, we had no hedging agreements in place.
record.11Major CustomersOur major customers for the year ended December 31, 2016 include Noble Energy, Inc., Texican Natural Gas Company, and Energy Transfer Partners, L.P., who accounted for approximately 41%, 38%, and 16% of our revenue for the year ended December 31, 2016, respectively. Our major customers for the year ended December 31, 2015 include, Shell Trading (US) Company, PDC Energy, Inc., and Noble Energy, Inc., who accounted for approximately 43%, 26%, and 21% of our revenue for the year ended December 31, 2015, respectively. We do not believe that the loss of any single customer would materially affect our business because there are numerous other potential purchasers of our production.SeasonalityGenerally, but not always, the demand and price levels for natural gas increase during colder winter months and decrease during warmer summer months. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies, and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity has placed increased demand on storage volumes. Demand for crude oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are much more driven by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. The impact of seasonality on crude oil has been somewhat magnified by overall supply and demand economics attributable to the narrow margin of production capacity in excess of existing worldwide demand for crude oil.Competitionbelieve our leasehold position provides a solid foundation for an economically robust exploration program and our future growth. Our success and growth also depends on our geological, geophysical, and engineering expertise, design and planning, and our financial resources. We believe the location of our acreage, our technical expertise, available technologies, our financial resources and expertise, and the experience and knowledge of our management enables us to compete effectively in our core operating areas. However, we face intense competition from a substantial number of major and independent oil and gas companies, many of which have larger technical staffs and greater financial and operational resources than we do. in attempting to secure drilling rigs and other equipment and services necessary for the drilling, completion, production, processing and maintenance of wells. Consequently,our wells, and we maycould face shortages or delays in securing these services from time to time. time if availability is limited. In addition, we compete to hire and retain professionals, including experienced geologists, geophysicists, engineers, and other professionals and consultants. We believe the location of our acreage, our technical expertise, available technologies, our financial resources, and the experience and knowledge of our management enables us to compete effectively in our core operating areas, but we recognize that many of our competitors have greater financial and operational resources.In addition,competeare directly impacted by regional prices regardless of Henry Hub, WTI or other major market pricing. The market price for people, including experienced geologists, geophysicists, engineers,oil, natural gas and other professionalsNGLs is dictated by supply and consultants. Throughoutdemand; consequently, we cannot accurately predict or control the price we may receive for our oil, natural gas and NGLs.industry,industry. The following table outlines our major customers and their percentage contribution to our total revenues for the needyears ended December 31, 2018 and 2017: Year Ended December 31, 2018 2017 Texican Crude & Hydrocarbons 87 % 85 % ETC Field Services 2 % 14 % Lucid Energy 10 % — % Others below 10% 1 % 1 % 100 % 100 % attract and retain talented people has grown atproviding a time when the numberfixed quantity of talented people available is constrained. We are not insulated from this resource constraint, and we must compete effectively in this market in order to be successful.General. operations covering the exploration, production and sale of oil and natural gas exploration, production, and related operations are subject to various types ofextensive federal, state and local laws and regulations. These laws and regulations, which are under continued review for amendment, include matters relating to drilling and production practices; the disposal of water from operations and the processing, handling and disposal of hazardous materials; bonding, permitting and licensing, and reporting requirements; taxation; and marketing, transportation and pricing practices.cancould result in substantial penalties, including administrative, civil, or criminal penalties. These laws and regulations materially impactincrease our operationscost of doing business and can potentially affect our profitability. However, we do not believe that these laws and regulations affect us in a manner significantly different than our competitors. Matters regulated include, but are not limited to, permits for drilling operations, drilling and abandonment bonds, reports concerning operations, the spacing of wells and 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, the disposal of fluids used or other wastes obtained in connection with operations, the valuation and payment of royalties and taxation of production. At various times, regulatory agencies have imposed price controls and limitations on production. In order to conserve supplies of oil and natural gas, these agencies have restricted the rates of flow of oil and natural gas wells below actual production capacity, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding production. Federal, state and local laws regulate production, handling, storage, transportation and disposal of oil and natural gas, by-products from oil and natural gas and other substances and materials produced or used in connection with oil and natural gas operations. While we believe that we will be able to substantially comply with all applicable laws and regulations through our strict attention to regulatory compliance, the requirements of such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the FERC and the courts. We cannot predict when or whether any such proposals may become effective. We do not believe that we would be affected by any such action materially differently than similarly situated competitors.12. local,federal, state and federal statutes, rules,local laws, orders and regulations. Federal, state and localThese statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. WeThe states in which we own interests inand operate properties located in Texas, which regulates drilling and operating activities by requiring, among other things, permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The laws of Texas also govern a number ofhave regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing or density, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing or density. Moreover, Texas imposes a 4.6% severance tax on oil productionWe believe we are in substantial compliance with these laws and a 7.5% severance tax on natural gas production. The failureregulations; however, should we fail to comply with these ruleslaws and regulations, can result inwe could face substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.Regulations.RegulationsWeThere are committedvarious governmental agencies, including the U.S. Environmental Protection Agency (“EPA”), the U.S. Occupational Safety and Health Administration (“OSHA”) and analogous state agencies that have the authority to strictenforce compliance with these regulationslaws and the utmost attention to EHS issues.regulations. Environmental laws and regulations may require that permits be obtained before drilling commences or facilities are commissioned,commissioned; restrict the types, quantities, and concentration of various substances that can be released into the environment in connection with drilling and production activities,activities; govern the handling and disposal of waste material,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 may substantially increase costs of exploring for, developing, or producing oil and gas and may prevent or delay the commencement or continuation of certain projects. In addition, these laws and regulations may impose substantial clean-up, remediation, and other obligationsindustry. We believe our present activities substantially comply, in the event of any discharges or emissions in violation of theseall material respects, with existing environmental laws and regulations. Further, legislativeNevertheless, environmental laws may result in a curtailment of production or material increases in the cost of production, development or exploration, and regulatory initiativesmay otherwise adversely affect our financial condition and results of operations. Although we maintain liability insurance coverage for liabilities from pollution, environmental risks are generally not fully insurable. We are committed to strict compliance with these regulations. During the years ended December 31, 2018 and 2017, we incurred approximately $38,000 and approximately $32,000, respectively, related to global warming or climate change could have an adverse effect oncompliance with environmental laws for our operations and the demand for oil and natural gas. See “Risk Factors-Risks Relating to the Oil and Gas Industry-Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for oil and natural gas.” gas properties.position. During the years ended December 31, 2016 and 2015, we incurred $182,000 and $130,000, respectively, related to compliance with environmental laws for our DJ Basin. of 1976, as amended (“RCRA”), and the comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. The RCRA imposes stringent operating requirements, 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, theThe RCRA includes an exemption that allows certain oil and natural gas exploration and production waste to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. As a result, we are not required to comply with a substantial portion of RCRA’s hazardous waste requirements. At various times in the past, proposals have been made to amend the RCRA to rescind the exemption that excludes oil and natural gas exploration and production wastes from regulation as hazardous waste. For example, in 2010, a petition was filed by the Natural Resources Defense Council (“NRDC”) with the Environmental Protection Agency (“EPA”) requesting that the agency reassess its prior determination that certain exploration and production wastes are not subject to the RCRA hazardous waste requirements. The EPA has not yet acted on the petition. On May 5,In 2016, moreover, the NRDC, along with other environmental organizations, commenced a lawsuit against the EPA asking the U.S. District Court for the Districtagreed in a consent decree to review its regulation of Columbia to order the agency to “revise” its RCRA regulations as they pertain to oil and gas wastes. On December 28, 2016,waste and has until March 2019 to determine whether revisions are necessary.court signed a consent decree, resolvingevent that we fail to comply with requirements for the lawsuit, under which the EPA agreedhandling of hazardous waste, administrative, civil and criminal penalties can be imposed. We believe that by March 15, 2019, it will either sign a notice of proposed rulemaking for a revision of its RCRA regulations as they pertainwe are in substantial compliance with applicable requirements related to oil and gas wastes (in which case it will take a final action on the proposed rulemaking by July 15, 2021) or sign a determination that no such revision is necessary.hazardous waste handling. Repeal or modification of the RCRA oil and gas exemption, by administrative, legislative or judicial process, or modification of similar exemptions in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us to incur perhaps significantly,potentially significant increased operating expenses.Dischargesalso(also known as the Clean Water Act), the Safe Drinking Water Act, (the “Clean Water Act”) imposesthe Oil Pollution Act and analogous state laws and regulations impose restrictions and controls on the discharge of produced waters and other oil and natural gas wastes into navigable waters of the United States, as well as state waters. Permits must be obtained to discharge pollutants into state and federal waters and to discharge fill and pollutants into regulated waters and wetlands. Uncertainty regarding regulatory jurisdiction over wetlands and other regulated waters of the United States has complicated, and will continue to complicate and increase the cost of, obtaining such permits or other approvals. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the crude oil and natural gas industry into certain coastal and offshore waters. Further, the EPA has adopted regulations requiring certain crude oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. Spill Prevention, Control, and Countermeasure requirements of the Clean Water Act require appropriate secondary containment loadout controls, piping controls, berms and other measures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon spill, rupture or leak. TheIn June 2015, the EPA and the U.S. Army Corps of Engineers released a Connectivity Reportjointly promulgated rules redefining the scope of waters protected under the Clean Water Act, and in September 2013, which determined that virtually all tributary streams, wetlands, open water in floodplains and riparian areas are connected. This report supported the drafting of proposed rules providing updated standards for what will be considered jurisdictional waters of the United States. Those rules were finalized on May 27, 2015. Then, on October 9, 2015, in presiding over a challenge to the rules, the U.S. Court of Appeals for the Sixth Circuit stayed them nationwide. It later determined (in FebruaryThe EPA and U.S. Army Corps of 2016) that it has jurisdiction to adjudicate the challenge. In January of 2017, the U.S. Supreme Court accepted an appeal of that determination. In the meantime, the Sixth Circuit’s stayEngineers have resumed nationwide use of the rules remains in place.agencies’ prior regulations defining the term “waters of the United States.” On February 28, 2017, moreover, President Trump directed the EPA to review the rules and “publish for notice and comment a proposed rule rescinding or revising the rules, as appropriate and consistent with law.” The Clean Water Act and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges of crude oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution.13OPA”Oil Pollution Act”) and regulations thereunder imposeare the primary federal law for oil spill liability. The Oil Pollution Act contains numerous requirements relating to the prevention of and response to petroleum releases into waters in the United States and imposes a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. The OPA assigns strict liability toOil Pollution Act subjects each responsible party to strict liability for oil removal costs and a variety of public and private damages, including, all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters and natural resource damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of federal safety, construction or operating regulations. Few defenses exist to the liability imposed by the OPA. In addition, to the extent we acquire offshore leases and those operations affect state waters, we may be subject to additional state and local clean-up requirements or incur liability under state and local laws. The OPA also imposes ongoing requirements on responsible parties, including proof of financial responsibility to cover at least some costs in a potential spill. We cannot predict whether the financial responsibility requirements under the OPA amendments will adversely restrict our proposed operations or impose substantial additional annual costs to us or otherwise materially adversely affect us. The impact, however, should not be any more adverse to us than it will be to other similarly situated owners or operators.Safe Drinking Water Act of 1974, as amended, establishes a regulatory framework for the underground injection of a variety of wastes, including brine produced and separated from crude oil and natural gas production, with the main goal being the protection of usable aquifers. The primary objective of injection well operating permits and requirements is to ensure the mechanical integrity of the wellbore and to prevent migration of fluids from the injection zone into underground sources of drinking water. Class II underground injection wells, a predominant storage method for crude oil and natural gas wastewater, are strictly controlled, and certain wastes, absent an exemption, cannot be injected into such wells. Failure to abide by our permits could subject us to civil or criminal enforcement. We believe that we are in compliance in all material respects with the requirements of applicable state underground injection control programs and our permits. In Texas, the Texas Railroad Commission (“RRC”) regulates the disposal of produced water by injection well. The RRC requires operators to obtain a permit from the agency for the operation of saltwater disposal wells and establishes minimum standards for injection well operations. some state agencies have begunbeen investigating whether such wells have caused increased seismic activity, and some states have shut down or imposed moratoria on the use of such injection wells. In responseTexas, the Texas Railroad Commission (“RRC”) regulates the disposal of produced water by injection well. The RRC requires operators to these concerns, regulators in some states are considering additional requirements related to seismic safety. For example,obtain a permit for the operation of saltwater disposal wells and establishes minimum standards for injection well operations. The RRC has adopted new permit rules for injection wells to address these seismic activity concerns within the state. Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells, and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. These new rules could impact the availability of injection wells for disposal of wastewater from our operations. Increased costs associated with the transportation and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may reduce our profitability; however, these costs are commonly incurred by all oil and gas producers and we do not believe that the costs associated with the disposal of produced water will have a material adverse effect on our operations. adopted to fulfill its mandate provide a framework for national, state and local efforts to protect air quality. Our operations utilize equipment that emits air pollutants which may be subject to federal and state air pollution control laws. These laws generally require utilization of air emissions control equipment to achieve prescribed emissions limitations and ambient air quality standards, as well as operating permits for existing equipment and construction permits for new and modified equipment. In May 2016, the EPA issued a final rule regarding the criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, which would subject operators to more stringent air permitting processes and requirements. These laws and regulations may increase our costs of compliance, and we may face administrative, civil and criminal penalties if we fail to comply with the requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in compliance in all material respects with the requirements of applicable federal and state air pollution control laws. Over the next several years, we may be required to incur capital expenditures for air pollution control equipment or other air emissions-related issues. The EPA promulgated significant New Source Performance Standards (“NSPS OOOO”) in 2012, as amended in 2013 and 2014, which have added administrative and operational costs. On May 12, 2016, the EPA issued regulations (effective August 2, 2016) that build on the NSPS OOOO standards by directly regulating methane and volatile organic compound (“VOC”) emissions from various types of new and modified oil and gas sources. Some of those sources are already regulated under NSPS OOOO, while others, like hydraulically fractured oil wells, pneumatic pumps, and certain equipment and components at compressor stations, are covered for the first time. On March 10, 2016, moreover, the EPA announced that it is moving towards issuing performance standards for methane emissions from existing oil and gas sources. The agency said that it will “begin with a formal process (i.e., an Information Collection Request) to require companies operating existing oil and gas sources to provide information to assist in the development of comprehensive regulations to reduce methane emissions.” On November 10, 2016, the EPA issued the Information Collection Request (“ICR”) and explained that “[r]ecipients of the operator survey (also referred to as Part 1) will have 60 days after receiving the ICR to complete the survey and submit it to EPA….Recipients of the more detailed facility survey (also referred to as Part 2) will have 180 days after receiving the ICR to complete that survey and submit it to the agency.” 14On October 1, 2015, under the Clean Air Act, the EPA lowered the national ambient air quality standard for ozone from 75 ppb to 70 ppb. This change could result in an expansion of ozone nonattainment areas across the United States, including areas in which we operate. Oil and natural gas operations in ozone nonattainment areas would likely be subject to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements, and increased permitting delays and costs.Along these lines, on October 20, 2016, the EPA finalized Control Techniques Guidelines to reduce emissions from a number of existing oil and gas sources that are located in certain ozone nonattainment areas and states in the Ozone Transport Region (which is comprised of Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Pennsylvania, Rhode Island, Vermont, the District of Columbia, and Northern Virginia). These guidelines will lead to direct regulation of VOC emissions and have the incidental effect of reducing methane emissions. The regulations will take the form of reasonably available control technology requirements.In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the under the Clean Air Act, has adopted regulations that, among other things, establish Prevention of Significant Deterioration (“PSD”), construction, and Title V operating permit requirements for certain new and modified large stationary sources.sources to address findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment. Facilities required to comply with PSD requirements for their GHG emissions will be required to meet “best available control technology” standards for those emissions, which will be established on a case-by-case basis. EPA rulemakings related to GHG emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, theThe EPA has adoptedalso issued rules requiring the monitoring and reporting of GHG emissions, from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certainthe reporting of our operations. In October 2015, the EPA finalized rules (effective January 1, 2016) that added new sources to the scope of the greenhouse gases monitoring and reporting rule. These new sources includeGHG emissions from gathering and boosting facilities as well assystems, completions and workovers from hydraulically fracturedof oil wells. The revisions also include the additionwells using hydraulic fracturing, and blowdowns of well identification reporting requirements for certain facilities. In addition, as noted above, the EPA has finalized new source performance standards related to methane emissions from the oil and natural gas industry.
transmission pipelines.15 at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional cap and trade programs have emerged that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. In addition, substantial limitationsdemandour operations and restrict or delay our ability to obtain air permits for the oil and natural gas we produce. Finally, it should be noted that some scientists have concluded that increasing concentrationsnew or modified sources, as well as increase our costs of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our exploration and production operations.an important anda common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight unconventional formations. For additional information about hydraulic fracturing and related regulatory matters, see “Risk Factors-Risks Relating to the Oil and Gas Industry.” Federal and state legislation and regulatory initiatives related to hydraulic fracturing could result in increased costs and additional operating restrictions or delays /cancellations in the completion of oil and gas wells.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 to incur costs to remedy discharges. Natural gas, oil or other pollutants, including salt water brine, may be discharged in many ways, including from a well or drilling equipment at a drill site, leakage from pipelines or other gathering and transportation facilities, leakage from storage tanks and sudden discharges from damage or explosion at natural gas facilities of oil and gas wells. Discharged hydrocarbons may migrate through soil to fresh water aquifers or adjoining property, giving rise to additional liabilities. including Texas, and local jurisdictions have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, the Texas Legislature adopted legislation effective September 1, 2011, requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process. The RRC adopted rules and regulations implementing this legislation that apply to all wells for which the RRC issues an initial drilling permit after February 1, 2012.permit. The law requires that the well operator disclose the list of chemical ingredients subject to the requirements of OSHA for disclosure on an internet website and also file the list of chemicals with the RRC with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the RRC.Further, in May 2013, the The RRC also adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular. In addition, the Texas Legislature adopted new legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. The RRC has adopted rules and regulations implementing this legislation that apply to all wells for which the RRC issues an initial drilling permit after February 1, 2012. The new law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) for disclosure on an internet web site and also file the list of chemicals with the RRC with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the RRC.activities. Nonetheless,activities; however, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps16A variety of federal For additional information about hydraulic fracturing and state laws and regulations govern the environmental aspects of natural gas and oil production, transportation and processing. These laws and regulations may impose liability in the event of discharges, including for accidental discharges, failure to notify the proper authorities of a discharge, and other noncompliance. Compliance with such laws and regulations may increase the cost of oil and gas exploration, development and production; although we do not anticipate that compliance will have a material adverse effect on our capital expenditures or earnings. Failure to comply with the requirements of the applicable laws and regulations could subject us to substantial civil and/or criminal penalties andrelated regulatory matters, see “Risk Factors-Risks Relating to the temporary or permanent curtailment or cessation of all or a portion of our operations. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We could be subject to liability under CERCLA, including for jointly-owned drilling and production activities that generate relatively small amounts of liquid and solid waste that may be subject to classification as hazardous substances under CERCLA.nonetheless handle other hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.operations. In addition, we currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration, production and processing for many years.years and some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state and local laws. Under suchthese laws, we could be required to undertake investigatory, response, or corrective measures, which could include soil and groundwater sampling, the removal of previously disposed substances and wastes, the cleanup of contaminated property, or performance of remedial plugging or pit closure operations to prevent future contamination, the costs of which could be substantial. (“FWS”) may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. As a result of a pair of 2011 settlement agreements, the FWS is required to make determinations on whether more than 250 species should be listed as endangered or threatened under the FSA. It must make the determinations by no later than completion of the agency’s 2017 fiscal year. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The federal government has issued indictments under the Migratory Bird Treaty Act to several oil and gas companies after dead migratory birds were found near reserve pits associated with drilling activities. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.17NEPAAdditionally, significant federal decisions, such as the issuance of federal permits or authorizations for certain oil and gas exploration and production activities may be subject to the National Environmental Policy Act (“NEPA”)The NEPA requires federal agencies, including the Department of Interior, to evaluate major federal agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. This process has the potential to delay oil and gas development projects.OSHA any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.In General do not believe that ourwe are in substantial compliance with all state laws governing environmental risks will be materially different from those of comparable companiesmatters and all permitting requirements; however, in the oil and gas industry. We believe our present activities substantiallyevent that we fail to comply in all material respects, with existing environmentalsuch laws, and regulations. Nevertheless, environmental laws may result in a curtailment of production or material increase in the cost of production, development or exploration and may otherwise adversely affect our financial condition and results of operations. Although we maintain liability insurance coverage for liabilities from pollution, environmental risks, 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 for environmental damage, including historical contamination, caused by such former operators. Additional liabilities could also arise from continuing violations or contamination not discovered during our assessment of the acquired properties.Transportation.Transportationcompanies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. companies.Commencing in 1985, FERC has also promulgated a series of orders, regulations and rule makings that significantly fosteredrules to foster competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.Transportation.Transportationnatural gas liquidsNGLs are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, weWe believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.18. and State Severance TaxesLeases. For those operationsLeases such operations must comply with numerouscertain regulatory restrictions, including various non-discrimination statutes, and certain of such operations must be conducted pursuant to certain on-site security regulations and other permits issued by various federal agencies. In addition, on federal lands in the United States, the Office of Natural Resources Revenue (“ONRR”) prescribes, or severelyand in some cases limits, the types of costs that are deductible transportation costs for purposes of royalty valuation of production sold off the lease. In particular, ONRR prohibitslease, including the deduction of costs associated with marketer fees, cash out and other pipeline imbalance penalties, or long-term storage fees. Further, theThe ONRR has also been engaged in a process of promulgating new rules and procedures for determining the value of crude oil produced from federal lands for purposes of calculating royalties owed to the government. The natural gas and crude oil industry as a whole has resisted the proposed rules under an assumption that royalty burdens will substantially increase. We cannot predict what, if any, effect any new rule will have on our operations.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 to leasing oil and natural gas resources, increased public engagement in the development of master leasing and development plans prior to leasing areas where intensive new oil and gas development is anticipated, and a comprehensive parcel review process. These changes have increased the amount of time and regulatory costs necessary to obtain oil and gas leases administered by the BLM. In addition, the BLM, on March 20, 2015, issued its final regulations for hydraulic fracturing on federal and tribal lands. The new regulations require, among other things, disclosure of chemicals, annulus pressure monitoring, flow back and produced water management and storage, and more stringent well integrity measures associated with hydraulic fracturing operations on 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 and flaring of natural gas from oil and gas operations on public land. These hydraulic fracturing-related rulemakings may adversely affect our operations conducted on federal lands.. including maintenance of certain gas/oil ratios, rates of production and other matters. The effect of these laws and regulations, as well as other regulations that could be promulgated byin the jurisdictions in which we have production, could be to limit the number of wells that could be drilled on our properties and to limit the allowable production from the successful wells completed on our properties, thereby limiting our revenues.To datehavecould be required to pay amounts due to injury; loss of life; damage or destruction to property, natural resources and equipment; pollution or environmental damage; regulatory investigation; and penalties and suspension of operations.experienced any material adverse effectall, of the operating risks to which our business is exposed. We evaluate the purchase of insurance, coverage limits and deductibles on our operations from obligations under environmental, health, and safety laws and regulations. We believe that we are in substantial compliance with currently applicable environmental, health, and safety laws and regulations, and that continued compliance with existing requirements will not have a materially adverse impact on us.2016,2018, we had nineteen39 employees, all of whom were full-time employees, and two part-time employees, andwe intend to continue to add additional personnel as our operational requirements grow. Our employees are not represented by any labor union or covered by any collective bargaining agreements.plan to continue to leverage the use ofalso retain certain independent consultants and contractors to provide various professional services, including additional land, legal, engineering, geology, environmental and tax services.
services on a contract or fee basis as necessary for our operations.19Available InformationWe have closed ourDenver, Colorado on February 28, 2017 and moved our corporate headquarter to 300 E. Sonterra Blvd.,leased office space located at 1800 Bering Drive, Suite No. 1220, San Antonio,510, Houston, Texas 78258,77057, and our telephone number is (210) 999-5400. (817) 585-9001. We also maintain offices in leased office space in Fort Worth, Texas and San Antonio, Texas.web site is www.lilisenergy.com. Additional information that may be obtained through our web site does not constitute part of this Annual Report on Form 10-K. Our Annual Reportsannual reports on Form 10-K, Quarterly Reportsquarterly reports on Form 10-Q, Current Reportscurrent reports on Form 8-K and amendments to those reports are accessible freefiled or furnished pursuant to Section 13(a) or 15(d) of chargethe Exchange Act of 1934 will be available through our Internet website at https://www.lilisenergy.com as soon as reasonably practical after we electronically file such material with, or furnish it to, the SEC. The information on, or that can be accessed through, our website. The SEC also maintains an internet site that contains reports, proxywebsite is not incorporated by reference into this Annual Report and information statements and other information regarding our filings at www.sec.gov.should not be considered part of this Annual Report.shares.common stock. You should carefully consider all of the risks described in this Annual Report, on Form 10-K, in addition to the other information contained in this Annual Report, on Form 10-K, before you make an investment in our common stock. Additional risks not presently known to us or that we currently deem immaterial may also adversely affect our business. In addition to other matters identified or described by us from time to time in filings with the SEC, there are several important factors that could cause our future results to differ materially from historical results or trends, results anticipated or planned by us, or results that are reflected from time to time in any forward-looking statement. Some of these important factors, but not necessarily all important factors include the following:not ableunable to access additional capital, it could negatively impact our production, our income and ultimately our ability to retain our leases.significant amounts, we may not be able to develop our current prospectsdecreased production and properties, or we may forfeit our interest in certain prospects and we may not be able to continue to operate our business.need significant additional capital to continue to operate our properties and continue operations. Currently, a significant portion of our revenue after field level operating expenses is required to be paid to our lenders as debt service.In the near term, we intendplan to finance our capital expenditures with cash on hand, cash flow from operations sales of non-core property assets,and future issuanceissuances of debt and/or equity securities and entry into a new credit facility.securities. Our cash flow from operations and access to capital is subject to a number of variables,factors, including:·our estimated proved oil and natural gas reserves;·the amount of oil and natural gas we produce from existing wells;·the prices at which we sell our production;·the costs of developing and producing our oil and natural gas reserves;·our ability to acquire, locate and produce new reserves;·the ability and willingness of banks to lend to us; and·our ability to access the equity and debt capital markets. other capital resources may not provide cash in sufficient amountsfunds to maintain planned or future levels of capital expenditures. Further, our actual capital expenditures in 20172019 could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount of capital we have available, we could be required to seek additional sources of capital, which may include refinancing existing debt, joint venture partnerships, production payment financings, sales of non-core property assets, offerings of debt or equity securities or other means. We may not be able to obtain debt or equity financing on terms favorable, or at all.If we are unable to fund our capital requirements, we may be required to curtail our operations relating to the exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil andreserves, or may be otherwise unable to implement their development plan, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations. In addition, a delay in or the failure to complete proposed or future infrastructure projects could delay or eliminate potential efficiencies and related cost savings. The occurrence of such events may prevent us from continuing to operate our business and our common stock and preferred stock may not have any value.20We have substantial liquidity needs and may be required to seek additional financing to fund our 2017 capital budget. If we are unable to obtain financing on satisfactory terms or maintain adequate liquidity, our ability to fund our capital budget, replace our proved reserves or to maintain production levels and generate revenue will be limited.Our principal sources of liquidity historically have been equity contributions, borrowings under our credit facilities, net cash provided by operating activities, and net proceeds from the issuance of Series A preferred and Series B preferred notes. Our capital program will require additional financing above the level of cash generated by our operations to fund growth. If our expected cash flow from operations decreases as a result of lower commodity prices or otherwise, our ability to expend the capital necessary to replace our proved reserves, maintain our leasehold acreage or maintain production may be limited, resulting in decreased production and proved reserves over time.We face uncertainty regarding the adequacy of our liquidity and capital resources to fund our 2017 capital budget. Our liquidity, including our ability to meet our ongoing operational obligations, is dependent upon, among other things: (i) our ability to maintain adequate cash on hand, including our ability to access additional financing, and (ii) our ability to generate cash flow from operations. Our ability to maintain adequate liquidity depends in part upon industry conditions and general economic, financial, competitive, regulatory and other factors beyond our control. We can provide no assurance that additional financing will be available or, if available, offered to us on acceptable terms. Given our existing debt and the estimated value of our proved reserves on December 31, 2016, we do not expect to have access to reserve-based revolving debt capacity during 2017. As a result, our access to additional financing is, and for the foreseeable future will likely continue to be, dependent up our access to new equity and equity-linked capital. As a result, the adequacy of our capital resources is difficult to predict at this timeOil, NGL and natural gas prices are volatile and have declined significantly from levels experienced in recent years.highly volatile. If commodity prices experience a further, substantial decline, our operations, financial condition, and level of expenditures for the development of our oil, NGL,natural gas and natural gasNGL reserves may be materially and adversely affected.NGLs,natural gas, and natural gasNGL production heavily influence our revenue, operating results, profitability, access to capital, future rate of growth and carrying value of our properties. Oil, NGLs,natural gas, and natural gasNGLs are commodities, and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand.NGLs, and natural gas and NGLs experience a further, substantial decline, our operations, financial condition and level of expenditures for the development of our oil, NGLs,natural gas and natural gasNGL reserves may be materially and adversely affected. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control, including:include demand for oil and natural gas;following:·actions of the Organization of Petroleum Exporting Countries, or OPEC; production;·the level of global inventories;·the ability and willingness of members of the Organization of the Petroleum Exporting Countries to agree to and maintain oil price and production controls;·worldwide and regional economic conditions affecting the global supply and demand for oil, NGLs and natural gas;·the price and quantity of imports of foreign oil, NGLs and natural gas;·political and economic conditions in or affecting other producing countries, including conflicts in the Middle East, Africa, South America and Russia;·prevailing prices on local price indexes in the areas in which we operate and expectations about future commodity prices;·the proximity, capacity, cost and availability of gathering and transportation facilities, and other factors that result in differentials to benchmark prices;·localized and global supply and demand fundamentals and transportation availability; the cost of exploring for, developing, producing and transporting reserves;
weather conditions and other natural disasters;
technological advances affecting energy consumption;21·the price and availability of alternative fuels;
expectations about future commodity prices; and
domestic, local and foreign governmental regulation and taxes.Lower commodity prices may reduce our cash flows and borrowing ability. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our reserves as existing reserves are depleted. Lower commodity prices may also reduce the amount of oil, NGLs, andlesser extent, natural gas that we can produce economically,sell. Prices also affect the amount of cash flow available for capital expenditures and a significant portion of our exploitation, development and exploration projects could become uneconomic. This may result in our having to make significant downward adjustments to our estimated proved reserves. As a result, if commodity prices remain depressed for a lengthy period of time or experience a further substantial or extended decline, our future business, financial condition, results of operations, liquidity, or ability to finance planned capital expendituresborrow money or raise additional capital. In addition, we may be materiallyrequired to record asset carrying value write-downs if prices fall. A significant decline in the prices of natural gas or oil could adversely affect our financial position, financial results, cash flows, access to capital and adversely affected.On September 29, 2016, wethat provides for a three-year senior secured term loan with an aggregate principal amount of $31.0 million outstanding asin 2017 and the Revolving Credit Agreement in 2018 (hereinafter defined and described in more detail). As of December 31, 2016,2018, $75.0 million was outstanding under our Revolving Credit Agreement and $38.1$111.6 million was outstanding as of March 1, 2017. We may borrow up to an aggregate principal amount of $50 million under theour Second Lien Credit Agreement. Our degree of leverage could have important consequences, including the following:·it may limit our ability to obtain additional debt or equity financing for working capital, capital expenditures, further exploration, debt service requirements, acquisitions and general corporate or other purposes;·a substantial portion of our cash flows from operations will be dedicated to the payment of principal and interest on our indebtedness and will not be available for other purposes, including our operations, capital expenditures and future business opportunities;·the debt service requirements of other indebtedness in the future could make it more difficult for us to satisfy our financial obligations;·we could be vulnerable to any downturn in general economic conditions and in our business, and we could be unable to carry out capital spending and exploration activities that are currently planned; and·we may from time to time be out of compliance with covenants under our debt agreements, which will require us to seek waivers from our lenders, which may be difficult to obtain. Our abilitymeetcontribute to LIBOR, as it has done to date. Borrowings under our debt obligations andRevolving Credit Agreement bear interest at a floating rate of either LIBOR or a specified base rate plus a margin determined based upon the usage of the borrowing base. In the event LIBOR becomes unavailable prior to reducethe maturity of our levelRevolving Credit Agreement, the rate of indebtedness dependsinterest payable on our Revolving Credit Agreement may change. Uncertainty regarding the future performance. General economic conditions, natural gas and oil prices and financial, business and other factorsof or changes to LIBOR or the unavailability of LIBOR could adversely affect our operationsfinancial condition.our future performance. Many of these factors are beyond our control. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets, the number of shares of capital stock we have authorized, unissued and unreserved and our performance at the time we need capital.TheSecond Lien Credit Agreement, guaranteed and further secured by substantially all our assets, containscontain restrictive covenants that may limit our ability to respond to changes in market conditions or pursue business opportunities.Thecontainsand Second Lien Credit Agreement contain restrictive covenants that limit our ability to, among other things:·incur additional indebtedness;·create additional liens;·sell certain of our assets;·merge or consolidate with another entity;·pay dividends or make other distributions;·engage in transactions with affiliates; and·enter into certain swap agreements.materially adversely affecthave a material adverse effect on our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.22covenant restrictionsrestrictive covenants that 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 take other actions to reduce indebtedness to meet such covenants, and mayor make it difficult for us to successfully execute our business strategy or effectively compete with companies that are not similarly restricted. management does not expect that our disclosure controls and procedures and internal controls willmay not prevent all possible errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable not absolute, assurance that the objectives of the controlThe design of any system of controls is based in part upon the likelihood of future events, and any design may not succeed in achieving its intended goals under all potential future conditions. Over time, a control may become inadequate because of changes in conditions, or the degree of compliance with our 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.theour Chief Executive Officer and theour Chief Financial Officer, we are required to conduct an evaluation of the effectiveness of our internal control over financial reporting based on framework of internal control issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Because of its inherent limitations, internal controls over financial reporting may not prevent or detect misstatements. In addition, projections of any evaluation effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.Through September 30, 2016, management had concludeditsa weakness in internal controlcontrols over financial reporting was not effective. Duringmay go undetected. Therefore, even effective internal controls can provide only reasonable assurance with respect to the fourth quarterpreparation and fair presentation of 2016, we completed our remediation efforts, but we may discover additional areas offinancial statements.in the future which may require improvement.could adversely impact our ability to provide timely and accurate financial information. If we are unable to assert that our internal control overreport financial reporting isinformation timely and accurately or to maintain effective indisclosure controls and procedures, we could be subject to, among other things, regulatory or enforcement actions by the SEC and the NYSE American, including a delisting from the NYSE American, securities litigation, debt rating agency downgrades or rating withdrawals, any future period, or if our auditors are unable to express an opinion onone of which could adversely affect the effectivenessvaluation of our internal controls, wecommon stock and could lose investor confidenceadversely affect our business prospects.the accuracyoil and completeness of our financial reports, which could have an adverse effect on our stock price.If oil or natural gas prices decrease or explorationmay require us to take write-downs of the carrying values of our oil and natural gas properties, potentially requiring earlier than anticipated debt repayment and negatively impacting the trading value of our securities.efforts are unsuccessful, wells in progress are deemed unsuccessful, or major tracts of undeveloped acreage expire, orplans, production data, economics and other similar adverse events occur,factors, we may be required to write-downwrite 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 a single cost center referred to as a full cost pool. These costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling 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. Underproperties. full cost method 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. This ceiling test is performed at least quarterly. Shouldquarterly and, in the event capitalized costs of the full cost pool exceed this ceiling, we would recognize an impairment expense. We did not incur an impairment expense for the year ended December 31, 2018. We recognized an impairment expense of approximately $4.7 million and $24.5$10.5 million for the yearsyear ended December 31, 2016 and 2015, respectively. At December 31, 2016, the Company’s estimates of undiscounted future cash flows indicated that the carrying amounts were not expected to be recovered due to a decrease in proved reserves. During 2016, commodity prices continued to trade in a low range. With low commodity prices sustained for the majority of 2016 in the DJ Basin, some of our properties became uneconomic triggering impairment charge of $4.7 million at December 31, 2016. The impairment charge of $24.5 million in 2015 was due to the lower commodity prices and lack of capital to develop our undeveloped oil and gas properties. 2017.values; asvalues. As such, these situations could result in future additional impairment expenses.23If commodity prices stay at current levels or decline further, we could incur full cost ceiling impairmentsexpenses in future quarters. Because the ceiling calculation uses rolling 12-month average commodity prices, the effect of lower quarter-over-quarter prices in 2016 compared to 2015 is a lower ceiling value each quarter. This may result in ongoing impairments each quarter until prices stabilize or improve.future. Impairment charges would not affect cash flow from operating activities but would adversely affectcould have a material adverse effect on our net income and stockholders’ equity.theseour reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.No one can measure underground accumulations of oil and natural gas in an exact way. willcould materially affect the quantities and present value of our reserves which could adversely affect our business, results of operations, and financial condition and our ability to make cash distributions to shareholders.In accordance with SEC requirements, we based the estimated discounted future net cash flows from proved reserves on the 12-month average oil and gas index prices, calculated as the un-weighted arithmetic average for the first-day-of-the-month price for each month and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties.Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present valueIf our reserve estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we used when calculating discounted future net cash flows for reporting requirements in compliance with the FASB in Accounting Standards Codification, which is referred to as ASC 932 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oilunderlying assumptions prove inaccurate, it could have a negative impact on our earnings and natural gas industry in general.Oil and natural gas prices are highly volatile, and our revenue, profitability, cash flow, future growth and ability to borrow funds or obtain additional capital,net income, as well as the carrying valuetrading price 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 for our production and the levels of our production depend on numerous factors beyond our control. These factors include the following:·changes in global supply and demand for oil and natural gas;·the actions of the Organization of Petroleum Exporting Countries;·the price and quantity of imports of foreign oil and natural gas;·acts of war or terrorism;·political conditions and events, including embargoes, affecting oil-producing activity;·the level of global oil and natural gas exploration and production activity;·the level of global oil and natural gas inventories;·weather conditions;·technological advances affecting energy consumption;·the price and availability of alternative fuels; and·market concerns about global warming or changes in governmental policies and regulations due to climate change initiatives.
securities.24Volatile oil and natural gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market for oil and natural gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects.Our revenues, operating results, profitability and future rate of growth depend primarily upon the prices we receive for oil and, to a lesser extent, natural gas that we sell. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. In addition, we may need to record asset carrying value write-downs if prices fall. A significant decline in the prices of natural gas or oil could adversely affect our financial position, financial results, cash flows, access to capital and ability to grow.from time to time, we may enterhave entered into derivative contracts that economically hedge our oil and gas price on a portion of our production. These contracts may limit our potential gains if oil and natural gas prices were to rise substantially over the price established by the contract. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:·there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received;·our production and/or sales of oil or natural gas are less than expected;·payments owed under derivative hedging contracts come due prior to receipt of the hedged month’s production revenue; or·the other party to the hedging contract defaults on its contract obligations.anyour current or future derivatives contracts may fail to fulfill their contractual obligations to us. As of December 31, 2016, we had no hedging agreements in place.outto be drilled over a period of several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of our drilling.approvals and other factors.approvals. Because of these uncertainties, we do not know if the potential drilling locations previously identified will ever be drilled or if we will be able to produce oil or natural gas from these or any otherour potential drilling locations. As such, actual drilling activities may materially differ from those presently identified, which could adversely affect our business.quantities. Analogies drawn from available data from other wells, more fully explored prospects or producing fields may not be applicable to current drilling prospects.The budgeted costs of planning, drilling, completing and operating wellsquantities as such studies are often exceeded and such costs can increase significantly due to various complications that may arise during the drilling and operating processes. Before a well is spud, we may incur significant geological and geophysical (seismic) costs, which are incurred whether a well eventually produces commercial quantities of hydrocarbons, or is drilled at all. Exploration wells endure a much greater risk of loss than development wells. If actual drilling and development costs are significantly more than the current estimated costs, we may not be able to continue operations as proposed and could be forced to modify drilling plans accordingly. merely an interpretive tool.25·unexpected or adverse drilling conditions;·elevated pressure or irregularities in geologic formations;·equipment failures or accidents;·adverse weather conditions;·compliance with governmental requirements; and·shortages or delays in the availability of drilling rigs, crews, and equipment.we decide to drill a certain location, there is a risk that (i) no commercially productive oil or natural gas reservoirs will be found or produced, or (ii)actual drilling and development costs are significantly more than the current estimated costs, we may drill or participate in new wells that are not productive or drill wells that are productive, but that do not produce sufficient net revenuesbe able to return a profit aftercontinue operations as proposed and could be forced to modify our drilling operating and other costs.plans. A productive well may become uneconomical if water or other deleterious substances are encountered which impair or prevent the production of oil and/or natural gas from the well. Our overall drilling success rate or drilling success rate for activity within a particular project area may decline. Unsuccessful drilling activities could result in a significant decline in production and revenues and materially harmaffect our operations and financial condition by reducing available cash and resources. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production and reserves from the well or abandonment of the well.third partythird-party operators or other third parties could decrease cash flow from operations and adversely affect our exploration and development activities.and natural gas and NGLs to unaffiliated third partythird-party purchasers, independent marketing companies and mid-streammidstream companies. Any delays in payments from such purchasers caused by their financial problems encountered by them will have an immediate negative effect on our results of operations and cash flows.LiquidityProspects in which we decide to participate may not yield oil or natural gas in commercially viable quantities or quantities sufficient to meet our targeted rate 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 be indications 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 prospect that will require substantial additional technical assessment, data acquisition and/or seismic data processing and interpretation. There is no definitive method to predict in advance of drilling and testing and wider-scale development whether any particular prospect will yield oil or natural gas in sufficient quantities to be economically viable. The use of reservoir, geologic and seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. The analysis we perform using data from other wells, more fully explored prospects or producing fields may not be useful in predicting the characteristics and potential reserves associated with our drilling prospects.performance, including our ability to participate in ready to drill prospects in our core areas.are:·leasehold prospects under which oil and natural gas reserves may be discovered;·drilling rigs and related equipment to explore for such reserves; and·knowledge personnel to conduct all phases of oil and natural gas operations. Virtually alltheseour competitors have financial and other resources substantially greater than ours. SuchThe capital, materials and resources needed for our operations may not be available when needed. If we are unable to access capital, material and resources when needed, we risk suffering numerousmay face various consequences, including:
including the breach of our obligations under our oil and natural gas leases and the potential loss of those leasehold interests; damage to our reputation in the oil and gas community; inability to retain personnel or attract capital; a slowdown in our operations and decline in revenue; and a decline in the market price of our common stock.26·the breach of our obligations under the oil and gas leases by which we hold our prospects and the potential loss of those leasehold interests;·loss of reputation in the oil and gas community;·inability to retain staff or attract capital;·a general slowdown in our operations and decline in revenue; and·decline in market price of our common stock.Seismic studies do not guarantee that hydrocarbons are present or, if present, will produce in economic quantities.We may use seismic studies to assist with assessing prospective drilling opportunities on current properties, as well as on properties that we may acquire. Such seismic studies are merely an interpretive tool and do not necessarily guarantee that hydrocarbons are present or if present will produce in economic quantities.properties; however,properties. However, these reviews are inherently incomplete as they are based on the quality, availability and interpretation of the reviewed data and the acumen and the assumptions of the evaluation personnel. Generally, it is not feasible to review in depth every individual property, well, facility and/or file involved in eachan acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. We may not perform an inspection on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we may not be able to obtain effective contractual protection against all or part of those problems, and we may assume environmental and other risks and liabilities in connection with the acquired properties. If we acquire properties with risks or liabilities that were unknown or not assessed correctly, our financial condition, results of operations and cash flows could be adversely affected as claims are settled and cleanup costs related to thesethe liabilities are incurred.If an examination of the title history of a property that we purchased reveals an oil and natural gas lease has been purchased in error from a person who is not the owner of the mineral interest desired, our interest would be worthless. In such an instance, the amount paid for such oil and natural gas lease as well as any royalties paid pursuant to the terms of the lease prior to the discovery of the title defect would be lost.however, it is the normalcustomary practice in the oil and natural gas industry for the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed oil and natural gas well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and such curative work entails expense. Failure to cure any title defects may adversely impact our ability in the future to increase production and reserves. In the future, we may suffer a monetary loss from title defects or title failure. Additionally, unproved and unevaluated acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest or acquire, we will suffer a financial loss which could adversely affect our financial condition, results of operations and cash flows.and operations are all located in a limited numberthe Delaware Basin, making us vulnerable to risks associated with operating in one major geographic area.geographic areas, which exposes us to various risks, including the risk of damage or business interruptions from natural disasters or weather events.AllDecember 31, 2018, all of our estimated proved reserves at December 31, 2016, all of our 2016 and 2015 sales were generatedlocated in the Delaware Basin in Winkler, Loving, and LovingReeves Counties, West Texas and Lea County, New Mexico and the DJ Basin in southeastern Wyoming, northeastern Colorado and southwestern Nebraska.Although these areas are well-established oilfield infrastructures,Mexico. As a result of this concentration, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil or natural gas produced from the wells in this area.27Our operational risk is concentrated due to our reliance on a small number of wells, operators and oil and gas purchasers.have concentrated operational risks both in terms of producing oil and gas properties, the operators we use and in the purchasers of our oil and gas production. An operational failure by an operator, the decline of production from a property and the termination of a contractual agreement with an operator or purchaser could have a material negative impact on our company. Our properties are located in areas where we have multiple markets for our oil and gas. As such, the loss of any single purchaser will not have a material impact with our ability to sell our oil and gas.We willmay not be the operator on all of our drilling locations, and, therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated assets.Delaware assets, but do not control all our DJ Basin development.acreage. As we carry out our exploration and development programs, we may enter into arrangements with respect to existing or future drilling locations that result in a greater proportion of locationswells being operated by others. As a result, we may have limited ability to exercise influence over the operations of the drilling locations operated by our partners. Dependence on the operator could prevent us from realizing target returns for those locations. The success and timing of exploration and development activities operated by our partners will depend on a number of factors that will be largely outside of our control including:·the timingand may adversely affect our financial condition and amount of capital expenditures;·the operator’s expertise and financial resources;·approval of other participants in drilling wells;·selection of technology; and·the rate of production of reserves, if any.This limited ability to exercise control over the operations of some of drilling locations may cause a material adverse effect on results of operations and financial condition.produced from these areas through trucking, gathering systems and pipelines, some of which we do not own.pipelines. The lack of availability of capacity on third-party systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of our development plans for properties. plans. some contractual control over the transportation of our production through firm transportation arrangements, third-party systems and facilities may be temporarily unavailable due to market conditions, or mechanical reliabilityissues, adverse weather conditions, work-loads, or other reasons including adverse weather conditions or work-loads. Activist or other efforts may delay or halt the constructionoutside of additional pipelines or facilities. Third-party systems and facilities may not be availableour control. Additionally, if our natural gas contains levels of hydrogen sulfide that require treatment prior to ustransportation, it could cause delays in the future at a price that is acceptable to us.transportation and marketing of our production. Any significant change in market factors or other conditionschanges affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities, could delay our production, thereby harming our business and, in turn,which could negatively impact our results of operations, cash flows, and financial condition.success is influenced byproduction depends, in part, upon our wells that are capable of commercial production not being shut-in (i.e., suspended from production). The lack of availability of capacity on third-party systems and facilities or the shut-in of an oil natural gas, and NGL pricesfield’s production could result in the specific areas where we operate, and these prices may be lower than prices at major markets.Regional natural gas, condensate, oil and NGLs prices may move independently of broad industry price trends. Because someshut-in of our operations are located outside major markets,wells. As of December 31, 2018, we are directly impacted by regional prices regardlesshad 3 gross (2.60 net) wells shut-in.Henry Hub, WTIwhich could have an adverse effect on our results of operations.major market pricing.
mechanical failures or interruptions, it would impact our ability to generate cash flows from operations and we could experience a reduction in our available liquidity. A decrease in our liquidity could adversely affect our ability to meet our anticipated working capital, debt service, and other liquidity needs.28pressures and other factors. Thus, ourpressures. Our future oil and natural gas reserves and production and, therefore, our cash flow and revenue are highly dependent on our success in efficiently obtaining additional reserves. We may not be able to develop, find or acquire reserves to replace our current and future production at costs or other terms acceptable to us, or at all, in which case our business, financial condition and results of operations would be materially and adversely affected.Part of our strategy involves drilling in existing or emerging unconventional shale plays using available horizontal drilling and completion techniques. in these plays are subject to drilling and completion execution risks, and drilling results may not meet our economic expectations for reserves or production. As a result, we may incur material write-downs and the value of our undeveloped acreage could decline if drilling results are unsuccessful.during completion operations, properimproper design and engineering versusfor the reservoir parameters, and successfullyunsuccessfully cleaning out the wellbore after completion of the final fracture stimulation stage.Our experience with horizontal well applications utilizing the latest drilling and completion techniques specifically in the formations where we are currently operating is limited; however, we contract with local experts in the area to design, plan and conduct our drilling and completion operations. Ultimately, thetheseour drilling and completion techniques can only be developed over time as more wells are drilled and production profiles are established over a sufficiently long time period.established. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and limited takeaway capacity or otherwise, and/or natural gas and oil prices decline, the return on our investment in these areas may not be as attractive as we anticipate and we could incur material write-downs of undeveloped properties and the value of our undeveloped acreage could decline in the future.The higher prices of oil and gas during the last several years have increased activity which has resulted in shortages of drilling rigs, equipment and personnel, which have resulted in increased costs and delays in the areas where we operate. If drilling rigs, equipment, supplies or qualified personnel are unavailable to us due to excessive costs or demand or otherwise, our ability to execute our exploration and development plans could be materially and adversely affected and, as a result, our financial condition and results of operations could be materially and adversely affected.29operationsoil and natural gas exploration and production activities are subject to the operating risks inherent in theand hazards associated with drilling for and producing oil and natural gas, industry, including the risks of:·fire, explosions and blowouts;·negligence of personnel;·inclement weather;·pipe or equipment failure;·abnormally pressured formations; and·environmental accidents such as oil spills, natural gas environment (including groundwater contamination).company from:·injury or loss of life;·significantly increased costs;·severe damage to or destruction of property, natural resources and equipment;·pollution or other environmental damage;·clean-up responsibilities;·regulatory investigation;·penalties and suspension of operations; or·attorney’s fees and other expenses incurred in the prosecution or defense of litigation.WeCompany, including losses and costs resulting from injury or loss of life; severe damage to or destruction of property, natural resources or equipment; pollution or environmental damage; clean-up responsibilities; regulatory investigations; penalties and/or suspension of operations; or fees and other expenses incurred in the prosecution or defense of litigation relating to such events.theseall losses or liabilities. We do not carry business interruption insurance. Lossesinsurance, and liabilities arising from uninsured or underinsured events may have a material adverse effect on our financial conditionwe cannot fully insure against pollution and operations.The producing wells in which we have an interest occasionally experience reduced or terminated production. These curtailments can result from mechanical failures, contract terms, pipeline and processing plant interruptions, market conditions, operator priorities, and weather conditions. These curtailments can last from a few days to many months, any of which could have an adverse effect on our results of operations.We may not have enough insurance to cover all of the risks faced and operators of prospects in which we participate may not maintain or may fail to obtain adequate insurance.In accordance with customary industry practices, we maintain insurance coverage against some, but not all, potential losses in order to protect against the risks faced. We do not carry business interruption insurance.environmental risks. We may elect not to carry certain types of insurance if our management believes that the cost of available insurance is excessive relative to the risks presented. In addition, we cannot insure fully against pollution and environmental risks. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial condition and results of operations. The impact of natural disasters or weather events in the areas where we operate has resulted in escalating insurance costs and less favorable coverage terms.Oil Losses and natural gasliabilities arising from uninsured or underinsured events may have a material adverse effect on our financial condition and operations, are subject to particular hazards incident to the drilling and production of oil and natural gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, natural gas or well fluids, fires and pollution and other environmental risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operation. We do not operate all of the properties in which we hold an interest. In the projects in which we own a non-operating interest directly, the operator for the prospect maintains insurance of various types to cover operations with policy limits and retention liability customary in the industry. We believe the coverage and types of insurance are adequate. The occurrence of a significant adverse event that is not fully covered by insurance could result inincluding the loss of our total investment in a particular prospectprospect.adverse effectnegative impact on financial conditionour operations or business reputation and results of operations.Failuresubject us to adequately protect critical dataconsequences such as litigation and technology systems could materially affect our operations.and breaches of data security and cyberattacks could disrupt our operations by causing delays, or cancellation of customer orders, impeding processing of transactions and reporting financial results, resulting in the unintentional disclosure of customer, employee or our information, or damage to our reputation. A system failure, or data security breach or cyberattack could have a material adverse effect on our financial condition, results of operations or cash flows.
In the past, we have experienced data security breaches resulting from unauthorized access to our e-mail systems, which to date have not had a30may in the future, may allow them to implement new technologies before we are in a position to do so. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies used now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, the business, financial condition, and results of operations could be materially adversely affected.willmay be dependent upon partnering arrangements.2016,2018, we had nineteen39 full-time employees and two part-time employees. We leverage the services of independent consultants and contractors to perform various professional services, including engineering, oil and natural gas well planning and supervision, and land, legal, environmental, accounting and tax services. We also pursue alliances with partners in the areas of geological and geophysical services and prospect generation, evaluation and prospect leasing.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.personnel. including Abraham Mirman, our Chief Executive Officer and other executive officers and key employees. These individuals have extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties, marketing oil and natural gas production and developing and executing financing and hedging strategies. The loss of any of these individuals could have a material adverse effect on operations. We do not maintain key-man life insurance with respect to any of our employees. Our success will be dependent on our ability to continue to employ and retain skilled technical personnel.The successful acquisition of producing properties requires an assessment of several factors, including:·recoverable reserves;·future oil and natural gas prices and their appropriate differentials;·well and facility integrity;·development and operating cost;·regulatory constraints and plans; and·potential environmental and other liabilities.31The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against 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.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 of ours while carrying on our ongoing business;·difficulty associated with coordinating geographically separate organizations;·challenge of attracting and retaining capable personnel associated with acquired operations; and·failure to realize the full benefit that we expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition, or to realize these benefits within the expected time frame.thisthe integration process, which will decrease the time they will have to manage our business. If our senior management and staff are not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.We may 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. The failure to continue to upgrade our technical, administrative, operating and financial staff and control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, geologists, engineers and other professionals in the oil and gas industry could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.recentcontinued growth in oil and natural gas exploration in the United States has drawn intense scrutiny from environmental and community interest groups, regulatory agencies and other governmental entities. As a result, we may face significant opposition to, or increased regulation of, our operations, that may make it difficult or impossible to obtain permits and other needed authorizations to drill, complete or operate, which could result in operational delays or otherwise make oil and natural gas exploration more costly or difficult than in other countries.Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with operating in one major geographic area.Most of our producing properties are geographically concentrated in the Permian Basin of West Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of oil, natural gas or natural gas liquids. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.
difficult.32We operate in areas of high industry activity, which may affect our ability to hire, train or retain qualified personnel needed to manage and operate our assets.Our operations and drilling activity are concentrated in the Permian Basin in West Texas, an area in which industry activity has remained relatively steady despite the recent downturn in commodity prices. As a result, demand for qualified personnel in this area, and the cost to attract and retain such personnel, has continued to be competitive, and would be expected to increase substantially in the future if commodity prices rebound. Moreover, our competitors may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer.Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development activities could result in oil and gas production volumes being below our forecasted volumes. In addition, any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our results of operations, liquidity and financial condition.Risks Relating to the Oil and Gas IndustryIn December 2009, thegases” present an endangerment togases,” or “GHGs,” endanger public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA, under the Clean Air Act, has begun adoptingadopted and implementingimplemented regulations to restrict emissions of greenhouse gases. Relatively recently, the EPA adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States on an annual basis, including petroleum refineries, as well as certain onshore oil and natural gas production facilities.Also, on May 12, 2016, EPA issued regulations (effective August 2, 2016) that build on the 40 C.F.R. Part 60, Subpart OOOO (NSPS OOOO) standards by directly regulating methane and VOC emissions from various types of new and modified oil and gas sources. Some of those sources are already regulated under NSPS OOOO, while others, like hydraulically fractured oil wells, pneumatic pumps, and certain equipment and components at compressor stations, are covered for the first time. On March 10, 2016, moreover, the EPA announced that it is moving towards issuing performance standards for methane emissions from existing oil and gas sources. The agency said that it will “begin with a formal process (i.e., an Information Collection Request) to require companies operating existing oil and gas sources to provide information to assist in the development of comprehensive regulations to reduce methane emissions.” On November 10, 2016, the EPA issued the Information Collection Request (“ICR”) and explained that “[r]ecipients of the operator survey (also referred to as Part 1) will have 60 days after receiving the ICR to complete the survey and submit it to EPA….Recipients of the more detailed facility survey (also referred to as Part 2) will have 180 days after receiving the ICR to complete that survey and submit it to the agency.”In June 2014, the United States Supreme Court’s holding inUtility Air Regulatory Group v. EPAupheld 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 of Significant Deterioration (“PSD”) or Title V permitting programs for non-GHG criteria pollutants remain subject to GHG Best Available Control Technology and major source permitting requirements, but ruled that sources cannot be subject to the PSD or Title V major source permitting programs based solely on GHG 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 the PSD or Title V programs based solely on GHG emission levels. The EPA likewise said that it will “further revise the PSD and Title V regulations in a separate rulemaking to fully implement” theUtility Air Regulatory Groupjudgment. On October 3, 2016, EPA published a proposed rulemaking for that purpose. TheUtility Air Regulatory Group judgment does not prevent states from considering and adopting state-only major source permitting requirements based solely on GHG emission levels.33NGLs,natural gas and natural gasNGLs we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHG in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.Federal and state legislativebusiness.formations. The process involves the injection of water, sandformations, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production by providing and linking up induced flow paths for the oil and/or gas contained in the rocks. Wewe routinely useimplement hydraulic fracturing techniques in many of our drilling and completion programs. The process is typically regulated by state oil and natural gas commissions, but the EPA, under the federal Safe Drinking Water Act (“SDWA”), has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel.The Bureau of Land Management (“BLM”), on March 20, 2015, issued its final regulations for hydraulic fracturing on federal and tribal lands. The new regulations require, among other things, disclosure of chemicals, annulus pressure monitoring, flow back and produced water management and storage, and more stringent well integrity measures associated with hydraulic fracturing operations on public land. On June 21, 2016, however, the U.S. District Court for the District of Wyoming enjoined BLM from enforcing the regulations, concluding that the agency lacked the authority to issue them. BLM appealed that decision to the U.S. Court of Appeals for the Tenth Circuit. The appeal is pending.In addition, on June 13, 2016, under the Clean Water Act, the EPA finalized a rule (effective August 29, 2016) that prohibits the discharge of oil and gas wastewaters to publicly-owned treatment works.For example in May 2013, the RRC adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. LocalAdditionally, local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.While these state and local land use restrictions generally cover areas with little recent or ongoing oil and gas development, they could lead opponents of hydraulic fracturing to push for similar statewide regimes. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit ofour exploration, development, or production activities, and perhaps even be precluded from drilling wells.A The EPA, for example, recently completed a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. In June of 2015, the EPA released an “external review draft” of the study and, in it, said that shale development had not led to “widespread, systemic” problems with groundwater. On August 11, 2016, however, the EPA Science Advisory Board issued comments on the external review draft, finding that “the EPA did not support quantitatively its conclusion about lack of evidence for widespread, systemic impacts of hydraulic fracturing on drinking water resources, and did not clearly describe the system(s) of interest (e.g., groundwater, surface water), the scale of impacts (i.e., local or regional), nor the definitions of ‘systemic’ and ‘widespread.’” In December of 2016, the EPA released the final version of the study, finding, among other things, that there are “certain conditions under which impacts from hydraulic fracturing activities can be more frequent or severe,” including “[i]njection of hydraulic fracturing fluids into wells with inadequate mechanical integrity, allowing gases or liquids to move to groundwater resources.” These types of studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.34The EPA also issued an advance notice of proposed rulemaking and undertook a public participation process under the Toxic Substances Control Act to seek comment on the information that should be reported or disclosed for hydraulic fracturing chemical substances and mixtures and the mechanisms for obtaining this information. Additionally, on January 7, 2015, several national environmental advocacy groups filed a lawsuit requesting that the EPA add the oil and gas extraction industry to the list of industries required to report releases of certain “toxic chemicals” under the Emergency Planning and Community Right-to-Know Act’s Toxics Release Inventory, or TRI, program. On October 22, 2015, the EPA took action on the Environmental Integrity Project’s October 24, 2012 petition to impose TRI reporting requirements on various oil and gas facilities. The EPA granted the petition in part, by agreeing to propose to add natural gas processing facilities to the scope of the TRI program, but rejected the rest of the petition. On December 15, 2015, in light of that decision, the environmental advocacy groups that had commenced the lawsuit opted to voluntarily dismiss it. On January 6, 2017, EPA issued a proposed rulemaking that would add natural gas processing facilities to the scope of the TRI program. uses large amounts of water. It can require between three to five million gallons of water per horizontal well. We may face regulatory concerns in both the sourcing and the discharge of water used in hydraulic fracturing. In addition, hydraulic fracturing produces water discharges that must be treated and disposed of in accordance with applicable regulatory requirements.First, as to sourcing water for hydraulic fracturing, we will need to secure water from the local water supply or make alternative arrangements. Second,gas and oil.Future legislation may result in the elimination of certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and production. Additionally, future federal or state legislation may impose new or increased taxes or fees on oil and natural gas extraction.Potential legislation, if enacted into law, could make significant changes to U.S. federal and state income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any other similar changes in U.S. federal and state income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could negatively affect our financial condition and results of operations. Additionally, legislation could be enacted that increases the taxes states impose on oil and natural gas extraction.
gas.35Moreover, as part of the Budget of the United States Government for Fiscal Year 2017, there was a proposal to impose an “oil fee” of $10.25 on a per barrel equivalent of crude oil. This fee would be collected on domestically produced and imported petroleum products. The fee would be phased in evenly over five years, beginning October 1, 2016. The adoption of this, or similar proposals, could result in increased operating costs and/or reduced consumer demand for petroleum products, which in turn could affect the prices we receive for our oil. Any of these tax changes could have a material impact on our financial performance. U.S. federal, state, local and other laws and regulations that can adversely affect the cost, manner or feasibility of doing business.gas, and operating safety.gas. Future laws or regulations, any adverse change in the interpretation of existing laws and regulations or our failure to comply with existing legal requirements may result in substantial penalties and harm to our business and could affect our results of operations and financial condition. We may be required to make large and unanticipated capital expenditures to comply with applicable laws and governmental regulations, including regulations governing land use restrictions; lease permit restrictions; drilling bonds and other financial responsibility in connection with operations, such as:·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. It is also possible that a portion of our oil and gas properties could be subject to eminent domain proceedings or other government takings for which we may not be adequately compensated. See “Business—Regulation of the Oil and Natural Gas Industry” for a more detailed description of regulatory laws covering our business.Our operationsfromto ensure our operations are in compliance with environmental laws and regulations.orand disposal of materials into the environment or otherwise relating to environmental protection.environment. These laws and regulations:·regulations, among other things, 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 production and processing activities, including environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells;·limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and·impose substantial liabilities for pollution resulting from our operations.Failure to comply with these lawsbe obtained before drilling or facility mobilization 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.
commissioning, or injection or disposal commences; limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and impose substantial liabilities for pollution resulting from our operations.36 Our permits require that we report any incidents that cause or could cause environmental damages. See “Business— Regulation of the Oil and Natural Gas Industry” for a more detailed description of the environmental laws covering our business.Should we fail to comply with all applicable regulatory agency administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.Under the Domenici-Barton Energy Policy Act of 2005, the FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting requirements. We also must comply with the anti-market manipulation rules enforced by FERC. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Additionally, the Federal Trade Commission has regulations intended to prohibit market manipulation in the petroleum industry with authority to fine violators of the regulations civil penalties of up to $1 million per day, and the CFTC prohibits market manipulation in the markets regulated by the CFTC, including similar anti-manipulation authority with respect to crude oil swaps and futures contracts as that granted to the CFTC with respect to crude oil purchases and sales. The CFTC rules subject violators to a civil penalty of up to the greater of $1 million or triple the monetary gain to the person for each violation. Failure to comply with those regulations in the future could subject us to civil penalty liability, as described in “Business-Regulation of the Oil and Natural Gas Industry.”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 disclosures by broker-dealers and satisfaction of other administrative requirements. As a result, broker-dealers may be less willing to execute transactions in securities subject to the “penny stock” rules. This may make it more difficult for investors to dispose of our common stock and cause a decline in the market value of our stock.There is a limited public market for our common stock and an active trading market or a specific share price may not be established or maintained.On May 26, 2016, our common stock was suspended from trading on the Nasdaq and immediately began trading on the OTCQB Venture Marketplace, or the OTCQB. On July 29, 2016, the Nasdaq announced that it will delist our common stock and file a Form 25 with the Securities and Exchange Commission. The Form 25 was subsequently filed on August 1, 2016, and the delisting became effective on August 11, 2016. We have applied for relisting on the Nasdaq and are working to show full compliance with all applicable Nasdaq initial listing criteria.While our common stock trades on the OTCQB, trading activity in our common stock generally occurs in small volumes each day. The value of our common stock could be affected by:·actual or anticipated variations in our operating results;·the market price for crude oil;·changes in the market valuations of other oil and gas companies;·announcements by us or our competitors of significant acquisitions, strategic partnerships, joint ventures or capital commitments;·adoption of new accounting standards affecting our industry;·additions or departures of key personnel;·sales of our common stock or other securities in the open market;·actions taken by our lenders or the holders of our convertible debentures;·changes in financial estimates by securities analysts;·conditions or trends in the market in which we operate;·changes in earnings estimates and recommendations by financial analysts;·our failure to meet financial analysts’ performance expectations; and·other events or factors, many of which are beyond our control.37In a volatile market, you may experience wide fluctuations in thestock. These fluctuations may have an extremely negative effect on the market price of our common stock and may prevent you from obtaining a market price equal to your purchase price when you attempt to sell our common stock in the open market. In these situations, you may be required either to sell at a market price which is lower than your purchase price, or to hold our common stock for a longer period of time than you planned. An inactive market may also impair our ability to raise capital by selling shares of capital stock and may impair our ability to acquire other companies or oil and gas properties by using our common stock as consideration.If an orderly and active trading market for our securities does not develop or is not sustained, the value and liquidity of your investment in our securities could be adversely affected.An active or liquid market in our common stock or securities exercisable or convertible for our common stock does not currently exist and might not develop or, if it does develop, it might not be sustainable. The last reported sale price of our common stock on the OTCQB on March 1, 2017 was $4.00 per share. The historic bid and ask quotations for our common stock, however, should not be viewed as an indicator of the current or historical market price for our common stock nor as an indicator of the market price for our common stock if our common stock were to be listed on a national securities exchange. The offering price for our securities as issued by us from time to time is determined through discussions between us and the prospective investor(s), with reference to the most recent closing price of our common stock on the OTCQB, and may vary from the market price of our securities following any offering. Further, our trading volume on the OTCQB has been generally very limited.If an active public market for our common stock develops, we expect the market price may be volatile, which may depress the market price of our securities and result in substantial losses to investors if they are unable to sell their securities at or above their purchase price.If an active public market for our common stock develops, we expect thetomay fluctuate substantially for the foreseeable future, primarily due to a number of factors, including:· in the event of negative news or lack of progress;·announcements of technological innovations or new products by us or our existing or future competitors;·the timing and development of our products;·general and industry-specific economic conditions;·actual or anticipated fluctuations in our operating results;·liquidity;·actions by our stockholders;·changes in our cash flow from operations or earnings estimates;·changes in market valuations of similar companies;·our capital commitments; and·the loss of any of our key management personnel.In addition, market prices of the securities of energy companies, particularly companies like ours without consistent revenues and earnings, have been highly volatile and may continue to be highly volatile in the event of negative news or lack of progress;somecompetitors;which may be unrelated to the operating performance of particular companies. Further, our common stock is currently quoted on the OTCQB, which is often characterized by low trading volumeproducts;by wideindustry-specific economic conditions;trading prices due to many factors that may have little to do with our operating results;business prospects. The availabilityearnings estimates;buyers and sellers represented by this volatility could lead to a market price for similar companies;common stock that is unrelated to operating performance. Moreover, the OTCQB is not a stock exchange, and trading of securities quoted on the OTCQB is often more sporadic than the trading of securities listed on a national securities exchange like The NASDAQ Stock Market or the New York Stock Exchange. While we are currently seeking to list our securities on a national securities exchange, there is no assurance we will be able to do so, and if we do so, many of these same forces and limitations may still impact our trading volumes and market price in the near term. Additionally, capital commitments;ofor a large amount of common stock into the market may also have a significant impact on market; andtrading priceloss of any of our common stock. In the past, securities class action litigation has often been brought against companies that experience high volatility in the market price of their securities. Whether or not meritorious, litigation brought against us could result in substantial costs, divert management’s attention and resources and harm our financial condition and results of operations. 38shareholders.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, bothwhich ranks senior to our common stock with respect to dividends and rights on the liquidation, dissolution or winding up of which provide its holders with a liquidation preference and prohibit the payment of dividends on junior securities, including our Common Stock,Company, amongst other preferences and rights.dilution. For example, the conversiondilution of the remaining Series B preferred stock in full could result in the issuance of 15,454,545 shares of common stock, and the exercise of outstanding warrants could result in the issuance of 15,915,511 shares ofour common stock. To the extent outstanding restricted stock units, warrants or options to purchase our common stock under our employee and director stock option plans2016 Omnibus Incentive Plan or our 2012 Equity Incentive Plan are exercised, the price vesting triggers under the performance shares granted to our executive officers are satisfied, or additional shares of restricted stock are issued to our employees, holders of our Common Stockcommon stock will experience dilution. Furthermore, if we sellthe sale of additional equity or convertible debt securities such sales could result in further dilution to our existing stockholders and cause the price of our outstanding securities to decline.Credit Agreement prohibitscredit facilities and preferred stock prohibit us from paying any dividends and the indenture governing our senior notes restricts our ability to pay dividends. In the future, we may agree to further restrictions. Any return to shareholdersstockholders will therefore be limited to the appreciation of their stock.company.Company. If securities analysts do not cover our company, thisCompany, the lack of coverage may adversely affect the trading price of our shares. The trading market for our shares will rely in part on the research and reports that securities analysts publish about us and our business. If one or more of the analysts who cover our companyCompany downgrades our shares, the trading price of our shares may decline. If one or more of these analysts ceases to cover our company,Company, we could lose visibility in the market, which, in turn, could also cause the trading price of our shares to decline. Further, because of our small market capitalization, it may be difficult for us to attract securities analysts to cover our company,Company, which could significantly and adversely affect the trading price of our shares.Our Series B preferred stock accrues a dividend, and we may be required to issue additional shares of Series B preferred stock upon the occurrence of certain events.The Series B preferred stock accrues a dividend, payable quarterly in arrears (based on calendar quarters), in the amount of 6% per annum of the original issuance price of the Series B preferred stock. The dividend is payable by an increase to the stated value of the Series B preferred stock or in-kind in Series B preferred stock or in cash, at our election.We may not have sufficient available cash to pay the dividends as it accrues. The payment of the dividends, or our failure to timely pay the dividends when due, could reduce our available cash on hand, have a material adverse effect on our results of operations and cause the value of our stock to decline in value. Additionally, any increase in stated value, which would result in the issuance of additional shares of Series B preferred stock in lieu of cash dividends (and the subsequent conversion of such Series B preferred stock into common stock pursuant to the terms of such Series B preferred stock) could cause substantial dilution to the then holders of our common stock.The issuance and sale of common stock upon conversion of the Series B Preferred Stock and the exercise of warrants received in those transactions, may depress the market price of our common stock.If conversions of the Series B preferred stock and exercises of warrants received in those transactions, sales of such converted securities take place, the price of our common stock may decline. In addition, the common stock issuable upon conversion of such securities may represent overhang that may also adversely affect the market price of our common stock. Overhang occurs when there is a greater supply of a company’s stock in the market than there is demand for that stock. When this happens the price of our company’s stock will decrease, and any additional shares which shareholders attempt to sell in the market will only further decrease the share price. If the share volume of our common stock cannot absorb converted shares sold by the Series B preferred stock holders, then the value of our common stock will likely decrease.39company.Though not now,Company.the future we may become subject to Nevada’s control share law. A corporation is subject to Nevada’s control share law if it has more than 200 stockholders, at least 100 of whom are stockholders of record and residents of Nevada, and it does business in Nevada or through an affiliated corporation. The law focuses on the acquisition of a “controlling interest” which means the ownership of outstanding voting shares sufficient, but for the control share law, to enable the acquiring person to exercise the following proportions of the voting powerCompany, which could adversely affect the price of the corporation in the electionour common stock. Additionally, Nevada law imposes certain restrictions on mergers and other business combinations between us and any holder of directors: (i) one-fifth or more but less than one-third, (ii) one-third or more but less than a majority, or (iii) a majority or more. The ability to exercise such voting power may be direct or indirect, as well as individual or in association with others.The effect of the control share law is that the acquiring person, and those acting in association with it, obtains only such voting rights in the control shares as are conferred by a resolution of the stockholders of the corporation, approved at a special or annual meeting of stockholders. The control share law contemplates that voting rights will be considered only once by the other stockholders. Thus, there is no authority to strip voting rights from the control shares of an acquiring person once those rights have been approved. If the stockholders do not grant voting rights to the control shares acquired by an acquiring person, those shares do not become permanent non-voting shares. The acquiring person is free to sell its shares to others. If the buyers of those shares themselves do not acquire a controlling interest, their shares do not become governed by the control share law. If control shares are accorded full voting rights and the acquiring person has acquired control shares with a majority10% or more of the voting power, any stockholder of record, other than an acquiring person, who has not voted in favor of approval of voting rights is entitled to demand fair value for such stockholder’s shares. Nevada’s control share law may have the effect of discouraging takeovers of the corporation.In addition to the control share law, Nevada has a business combination law which prohibits certain business combinations between Nevada corporations and “interested stockholders” for three years after the “interested stockholder” first becomes an “interested stockholder,” unless the corporation’s board of directors approves the combination in advance. For purposes of Nevada law, an “interested stockholder” is any person who is (i) the beneficial owner, directly or indirectly, of ten percent or more of the voting power of theour outstanding voting shares of the corporation, or (ii) an affiliate or associate of the corporation and at any time within the three previous years was the beneficial owner, directly or indirectly, of ten percent or more of the voting power of the then outstanding shares of the corporation. The definition of the term “business combination” is sufficiently broad to cover virtually any kind of transaction that would allow a potential acquirer to use the corporation’s assets to finance the acquisition or otherwise to benefit its own interests rather than the interests of the corporation and its other stockholders. The effect of Nevada’s business combination law is to potentially discourage parties interested in taking control of our company from doing so if it cannot obtain the approval of our Board of Directors.Not applicable.40Recent PricesWe began tradingInformationOTCQB Venture Marketplace under the symbol “LLEX” on May 27, 2016. From February 11, 2016 to May 26, 2016, our common stock traded on The Nasdaq Capital Market (“Nasdaq”)NYSE American under the symbol “LLEX.” Prior February 11, 2016, our common stock traded on the Nasdaq Global Market under the symbol “LLEX.” We have applied for relisting on the Nasdaq and are working to show full compliance with all applicable Nasdaq initial listing criteria.The following table shows the high and low reported sales prices of our common stock for the periods indicated. The prices reported in this table have been adjusted to reflect the 1-for-10 reverse split of our issued and outstanding common stock, which took effect on June 23, 2016. High Low 2016 Fourth Quarter $ 3.75 $ 2.10 Third Quarter $ 3.51 $ 1.08 Second Quarter $ 2.33 $ 0.50 First Quarter $ 3.70 $ 1.00 2015 Fourth Quarter $ 7.00 $ 0.70 Third Quarter $ 31.50 $ 4.80 Second Quarter $ 19.00 $ 7.40 First Quarter $ 12.60 $ 6.00 1, 2017,5, 2019, there were 135 owners147 holders of record of our common stock. We estimate that thereapproximately 1,833 beneficial holdersentitled to receive cumulative preferential dividends, payable and compounded quarterly in arrears. Dividends on our preferred stock are payable, at the Company’s option, (i) in cash, (ii) in kind, or (iii) in a combination thereof. In 2018, we did not pay cash dividends on our outstanding preferred stock. As of December 31, 2018, the Company accrued a cumulative balance of $10.7 million of paid-in-kinds dividends. See Note 13 to our common stockDividend Policy any cash dividends on our common stock and do not anticipate paying any dividends in the foreseeable future. Our current business plan is to retain any future earnings to finance the expansion and development of our business. Any future determination to pay cash dividends will be at the discretion of our Board of Directors, and will be dependent upon our financial condition, results of operations, capital requirements and other factors as our boardBoard of Directors may deem relevant at that time. In addition, we any dividends pursuant to the terms of our Second Lien Credit Agreement and outstanding preferred stock. Our Revolving Credit Agreement also includes customary limitations on our ability to pay dividends. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—“LiquidityOperations - “Liquidity and Capital Resources.”We have previously disclosed by wayQuarterly Reports on Form 10-Q and Current Reports on Form 8-K filed with the SEC all sales by usshares of our unregistered securities during the year ended December 31, 2016.Equity Compensation PlansInformation regardingcommon stock that are available for issuance under all of our existing equity compensation plans is set forthas of December 31, 2018:Plan Category Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights
(a) Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights
(b) Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (excluding securities reflected in column (a))
(c)Equity compensation plans approved by security holders 5,031,578 $ 2.67 6,692,285 Equity compensation plans not approved by security holders — — — Total 5,031,578 $ 2.67 6,692,285 Item 12 of this Annual Report on Form 10-K and is incorporated herein by reference.Notes to Consolidated Financial Statements.Not applicable.41 of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes included elsewhere in “Part II, Item 8. Financial Statements and Supplementary Data.”this Annual Report. The following discussion and analysis containsincludes forward-looking statements, including, without limitation, statements relating to our plans, strategies, objectives, expectations, intentions and resources. Please see “Cautionary Statement Concerning Forward-Looking Statements”Our actual results could differ materially from those discussed in these forward-looking statements as a result of many factors, including those discussed under “Risk Factors” and “Part I, Item 1A. Risk Factors”elsewhere in this Annual Report on Form 10-K.Generalan independent oil and gasa focused Permian Basin company engaged in the exploration, production, development, and acquisition of oil, natural gas, and NGLs, with all of our properties and operations in the Delaware Basin, with a focus on Liquids. In each of the past two years, over 90% of our revenues have been generated from the sale of Liquids (crude oil and NGLs). We have a highly contiguous acreage position with significant stacked-pay potential, which we believe includes at least five to seven productive zones and approximately 1,175 future drilling locations.productioncompleting additional prospective benches within our acreage position.prospects. We were incorporated in August of 2007 in the State of Nevada as Universal Holdings, Inc. In October 2009, we changed our name to Recovery Energy, Inc. and in December 2013, we changed our name to Lilis Energy, Inc.On June 23, 2016, we completed a merger (the “Merger”) with Brushy Resources, Inc. (“Brushy”), which resulted in the acquisition of our propertiesrelated assets in the Delaware Basin in Lea County, New Mexico, from OneEnergy Partners Operating, LLC, for stock and cash consideration valued at approximately $64.9 million, before acquisition costs and customary purchase price adjustments;well ascontract operator of SCM Water’s salt water disposal wells (SWD). We have sold to SCM Water for cash consideration of up to $20 million, with $15 million upfront, an option to acquire our existing water infrastructure, a system which is comprised of approximately 14 miles of pipeline and one SWD. We anticipate that the majority of our current operating activity.Additionally, in connectionwater will be disposed through the future SCM Water system at a competitive gathering rate under the agreement.Merger on June 23, 2016, we effected a 1-for-10 reverse stock split. As a resultGulf Coast. Under the terms of the reverse split, every ten sharesagreement, 6,000 Bbl/d of issued and outstanding common stock were automatically converted intofirm capacity will be delivered to the Gulf Coast for one newly issued and outstanding shareyear, beginning on July 1, 2019. During the next four years, from July 1, 2020 through June 30, 2024, firm capacity will adjust to 5,000 Bbl/d. All volumes will have Gulf Coast pricing based on Magellan East Houston pricing throughout the 5-year term. We also have the ability to expand our capacity during the term of common stock, without any changethe agreement as we believe having flexibility with barrels in the par value per share. However, the number of authorized shares of common stock remained unchanged.Shortly after the Merger,future is desirable.began to develop a drilling program onentered into our properties using hydraulic fracture stimulation techniques across multiple productive horizons. Our primary focus is drilling horizontal wells in the Delaware Basin of West Texas, which we believe will provide attractive returns on a majority of our acreage position. Our goal is to earn economic returns to our shareholders through cash flow from new production of oil, naturallong-term gas gathering and NGLs, as well as through derisking the development profile of our portfolio of properties in order to add overall value. Our drilling program utilizes the development of new horizontal wells across several potentially productive formations in the Delaware Basin,processing agreement with an initial focus on targeting the Wolfcamp formation. We drilledaffiliate of Lucid Energy Group (“Lucid”) to support our first horizontal well in late 2016drilling program. Lucid has commenced receiving, gathering, and completed it in 2017.Overview of Our Business and StrategyWe are an oil and naturalprocessing our gas company, engaged in the acquisition, development and production of unconventional oil and natural gas properties. We have accumulated approximately 6,924 net acres in what we believe to be the core of the Delaware Basinfor certain areas in Winkler and Loving Counties, Texas and Lea County, New Mexico. Our leaseholdagreement with Lucid secures sufficient term and capacity in the production areas committed to the agreement. Pursuant to our agreements with Lucid, there are no minimum volume commitments and all gas transported via Lucid is sent to Lucid’s 310 million cubic feet per day Red Hills Natural Gas Process Complex located in Lea County, New Mexico, where it is treated and processed then transported pursuant to transportation contracts through various long-haul pipelines with access to west coast markets, gulf coast markets, Permian markets and MidCon markets. Lucid is responsible for all capital costs in New Mexico and Texas, other than gathering lines from wellhead to various Lucid receipt points.is largely contiguous, allowingthrough several transactions in 2018, which we believe puts us in a financial position to maximize development efficiency, manage full cycle finding costsfund our drilling and potentially enabling uscompletion operations for 2019. On October 10, 2018, we announced our entry into the Revolving Credit Agreement, a new five-year senior secured reserve based revolving credit facility with an initial borrowing base of $95 million, that refinanced our first-lien term loan with Riverstone Credit Partners, LLC. The Company enhanced liquidity by $60 million, including $35 million in initial capacity under the Revolving Credit Agreement and $25 million raised through a tack-on to generate higher returnsthe outstanding Series C preferred stock. The Company reduced interest expense associated with the Riverstone First Lien Loans by 4.00%, from LIBOR plus 6.75% to LIBOR plus 2.75%. On December 7, 2018, the Company’s borrowing base under the Revolving Credit Agreement was increased to $108 million as a result of its regularly scheduled fall redetermination process.our shareholders. In addition, 68% of our acreage position is held by production,2019, and we are currently targeting cash flow neutrality in 2019.named operatorCompany agreed to convert the remaining Second Lien Loans with a face value of approximately $133.6 million for a combination of preferred stock and common stock, of which $60.0 million was converted into a new class of convertible preferred stock (Series E Preferred Stock), $55.0 million was converted into a new class of non-convertible preferred stock (Series F Preferred Stock), and $18.6 million was converted into common stock based on 100%a $1.88 per share issuance price. The conversion of the Second Lien Loans in their entirety substantially improves our capital structure, resulting in the elimination of debt repayments and quarterly interest obligations on the Second Lien Loans. Subsequent to the conversion, our long-term debt consists solely of our acreage. These two characteristics give us control overRevolving Credit Agreement with no scheduled principle requirements until maturity in 2021.paceconversion features and voting rights on the existing Series C Preferred Stock and Series D Preferred Stock were eliminated in exchange for the issuance of developmentapproximately 7.8 million shares of our common stock. The potential dilution of our common stockholders resulting from the conversion of the Second Lien Loans, the Series C Preferred Stock and Series D Preferred Stock was reduced from approximately 53.5 million shares of common stock to approximately 41.6 million shares of common stock, including the issuance of approximately 17.6 million shares of common stock and the effect of the possible conversion of the Series E Preferred Stock. The newly created Series E Preferred Stock is the only potentially dilutive instrument outstanding.design a more efficient and profitable drilling program that maximizes recovery of hydrocarbons. We expect that substantially all ofmarket our estimated 2017 capital expenditure budget will be focusedproduction on the development and expansion of our Delaware Basin acreage and operations. We also plan to continue to selectively and opportunistically pursue strategic bolt-on acreage acquisitions in the Delaware Basin. vast majority of our revenues from sales of Liquids and, to a lesser extent, the sale of oil for our producing wells.natural gas. The prices of oil and natural gasthese products are critical factors to our success. Volatilitysuccess and volatility in thethese prices of oil and natural gas could be detrimental toimpact our results of operations. OurIn addition, our business requires substantial capital to acquire producing properties and develop our non-producing properties. AsDeclines in the priceprices of oil, declinesnatural gas and causesNGLs would reduce our revenues to decrease, we generate lessand result in lower cash to acquire new properties or develop our existing properties and the price decline may alsoinflow which would make it more difficult for us to pursue our plans to acquire new properties and develop our existing properties. Declines in oil, natural gas, and NGL prices may also adversely affect our ability to obtain any debt or equity financingadditional funding on favorable terms.supplementmanage the challenges presented in a lower pricing environment, and we can execute our planned 2019 development program and capital expenditures with our current cash on hand.Our Board has approved a drilling program of up to 10 gross Delaware Basin wells (6 net) that is contingent upon our access to sufficient capital to fully execute. In the first quarter of 2017, we completed two wells, and we have begun drilling a third well. We expect our 2017 horizontal drilling program will be focused almost exclusively on the Wolfcamp zone of the Delaware Basin, with lateral lengths ranging from approximately 5,000’ laterals to 7,000’ laterals. 42Based upon current commodity price expectations for 2017, we believe that our cash flowhand, proceeds from operations combined with the proceeds of our recently completed equity offering, proceedsand draws from the conversionexisting revolving credit facility as required.in-the-money warrants to equity, and availability under our Credit Facility, will be sufficient to fund our operations for 2017, including working capital requirements. However, future cash flows are subject to a number of variables, including uncertainty in forecasted production volumes and commodity prices. We are the operator for 100% of our 2017 operational capital program and, as a result, the amount and timing of a substantial portion of our capital expenditures is discretionary. Accordingly, we may determine it prudent to curtail drilling and completion operations due to capital constraints or reduced returns on investment as a result of commodity price weakness.The results of operations of Brushy are included with those of ours from June 23, 2016 through December 31, 2016. As a result, results of operations forOperations2016 are not necessarily comparable2018, we worked actively to increase our natural gas transportation, processing, and sales capacity for our expanding production. We successfully brought online our fourth Wolfcamp horizontal well. This well is our most geologically eastern well and is the closest well to the resultsCentral Basin Platform in our current acreage position. As of operations for prior periods. Additionally, all discussion related to historical representations of common stock, unless otherwise noted, give retroactive effect to the reverse split for all periods presented.Results of OperationsResults of operations for the year ended December 31, 2016 compared to the year ended2018, we have production flowing from our 24 horizontal wells and 14 legacy vertical wells.2015table compares operatingsets forth selected revenue and sales data for the years endedDecember 31, 20162018 and 2015 (in thousands): Years Ended December 31, 2016 2015 Variance % (In Thousands) Revenue: Oil $ 2,418 $ 292 $ 2,126 728 % Gas 1,012 77 935 1214 % Other 5 27 (22 ) -81 % $ 3,435 $ 396 $ 3,039 767 % Total Revenue 2018 2017 Change Net sales volumes: Oil (Bbls) 1,089,724 371,993 717,731 193 % Natural gas (Mcf) 2,855,739 776,164 2,079,575 268 % NGL (Bbls) 246,425 73,875 172,550 234 % Total (BOE) 1,812,106 575,229 1,236,877 215 % Average daily sales volume (BOE/d) 4,965 1,576 3,389 215 % Average realized sales price: Oil (per Bbl) $ 53.26 $ 47.92 $ 5.34 11 % Natural gas (per Mcf) 1.84 2.74 (0.90 ) (33 )% NGL (per Bbl) 28.11 22.49 5.62 25 % Total (per BOE) $ 38.75 $ 37.57 $ 1.18 3 % Oil revenue $ 58,042 $ 17,826 $ 40,216 226 % Natural gas revenue 5,246 2,125 3,121 147 % NGL revenue 6,928 1,661 5,267 317 % Total $ 70,216 $ 21,612 $ 48,604 225 % was approximately $3.4increased $48.6 million ($1.8 million from Brushy) for the year ended December 31, 2016 as compared to $0.4$70.2 million for the year ended December 31, 2015,2018, as compared to $21.6 million for the year ended December 31, 2017, representing a 225% increase. Our significant increase in total revenue in 2018 is primarily attributable to an additional 15 wells being placed on production in the Delaware Basin during 2018. Total sales volume climbed 215% to 1,812,106 BOE during 2018, compared to 575,229 BOE in 2017, an increase of approximately $3.0 million or 767%. 1,236,877 BOE.revenuerevenues in 2018 was primarily attributable to approximately $1.8 million in revenues from Brushy’s operations during the second half of 2016 and increase of approximately $1.2 million in revenuespartially offset by increased crude transportation costs, which are deducted from the DJ Basin due to increase in production volumes.The following table compares production volumes and average pricesCompany’s gross revenue for crude oil sales. For the yearsyear ended December 31, 20162018, transportation costs related to crude oil sales increased by $3.7 million to $4.7 million, compared to $1.0 million for the same period in 2017. The Company expects to lower its crude transportation and 2015: For the Year Ended
December 31, 2016 2015 Product Oil (Bbl.) 61,088 7,067 Oil (Bbls)-average price $ 39.59 $ 41.36 Natural Gas (MCFE)-volume 400,775 32,291 Natural Gas (MCFE)-average price $ 2.54 $ 2.39 Barrels of oil equivalent (BOE) 127,863 12,449 Average daily net production (BOE) 350 34 Average Price per BOE $ 26.87 $ 29.67
gathering costs in 2019 as a result of increased pipeline transportation of the Company’s crude oil under the Gathering Agreement with SCM. The Company anticipates savings of approximately $4.50 per Bbl, equal to a decrease of approximately 87.4% in transportation costs utilizing pipe gathering as opposed to trucking.43tables compares oil and gastable shows a comparison of production costs production taxes, depreciation, depletion, and amortization for the years ended December 31, 20162018 and 2015: For the Year Ended
December 31, 2016 2015 Production costs per BOE $ 9.75 $ 15.70 Production taxes per BOE (1.30 ) 2.24 Depreciation, depletion, and amortization per BOE 12.25 46.93 Total operating costs per BOE $ 20.70 $ 64.87 Gross margin per BOE $ 6.17 $ (35.20 ) Gross margin percentage 23 % (119 )% Years Ended December 31, 2016 2015 Variance % (In Thousands) Costs and expenses: Production costs $ 1,247 $ 195 $ 1,052 539 % Production taxes (167 ) 28 (195 ) -696 % General and administrative 14,570 7,930 6,640 84 % Depreciation, depletion and amortization 1,566 574 992 173 % Accretion of asset retirement obligations 132 10 122 1220 % Impairment of evaluated oil and gas properties 4,718 24,478 (19,760 ) -81 % Total operating expenses 22,066 33,215 (11,149 ) -34 % Loss from operations $ (18,631 ) $ (32,819 ) $ 14,188 -43 % Production Costs 2018 2017 Change Operating Expenses per BOE: $ 7.64 $ 10.14 $ (2.50 ) (25 )% Gathering, processing and transportation 1.87 2.07 (0.20 ) (10 )% Production taxes 2.05 2.06 (0.01 ) (1 )% General and administrative 18.35 86.66 (68.31 ) (79 )% Depreciation, depletion, amortization and accretion 14.00 12.21 1.79 15 % Impairment of evaluated oil and natural gas properties — 18.27 (18.27 ) (100 )% Total (BOE) $ 43.91 $ 131.41 $ (87.50 ) (67 )% Operating Expenses Production costs $ 13,843 $ 5,832 $ 8,011 137 % Gathering, processing and transportation 3,392 1,191 2,201 185 % Production taxes 3,709 1,187 2,522 212 % General and administrative 33,251 49,851 (16,600 ) (33 )% Depreciation, depletion, amortization and accretion 25,367 7,025 18,342 261 % Impairment of evaluated oil and natural gas properties — 10,505 (10,505 ) (100 )% Total Operating Expenses $ 79,562 $ 75,591 $ 3,971 5 % 2016, compared2017, due to $0.2 millionthe increase in sales volumes. Our production taxes of $2.05 per BOE for the year ended December 31, 2015, an increase of $1 million or 539%. The increase is primarily attributable to Brushy’s operations. Production costs2018, had no material variance from the $2.06 per BOE decreased to $9.75 for the year ended December 31, 2016 from $15.702017, which is a reflection of stable taxation rates in 2015, a decreaseour areas of $5.95 per BOE, or 38%, primarily due to Brushy’s lower production costs. The Company anticipates that its production costs in the near term would be closer to the level of Brushy’s historical production costs.Production TaxesProduction taxes were $(0.2) million for the year ended December 31, 2016, compared to $0.03 million for the year ended December 31, 2015, a decrease of $(0.2) million or -696%. Currently, ad valorem, severance and conservation taxes range from 1% to 13% based on the state and county from which production is derived. Production taxes per BOE decreased to $(1.30) during the year ended December 31, 2016 from $2.24 in 2015, a decrease of $(3.54) or -158%. Subsequent to the issuance of our consolidated financial statements for the year ended December 31, 2016, we determined that certain ad valorem and severance tax estimates were higher than the actual amount billed, resulting in a tax benefit to us.$14.5$33.3 million during the year ended December 31, 2016,2018, compared to $7.9$49.9 million during the year ended December 31, 2015,2017, a decrease of $16.6 million or 33%. The decrease in G&A was primarily due to a decrease of $8.3 million in bonuses paid in 2018 offset by an increase of $6.6 million, or 84%. The increase of $6.6$4.1 million in generalprofessional and administrative expenses was attributable to an increaselegal fees plus a significant decrease of $3.9 million to $7.1$12.4 million in non-cash stock-basedstock based compensation expense, a $0.6expense. The decrease of $12.4 million increase in legal feesstock based compensation was primarily attributed to $2.8 million in restricted stock bonuses granted to executive officers that vested at grant date, $6.2 million in restricted stock granted to employees and non-employee directors in October 2017, $1.6 million in incremental expense associated with the Merger, an increasemodification of $1.5stock options awarded to former Chief Executive Officer in 2017 and $1.8 million in payrollrestricted stock and stock options granted to three new executive officers hired during the year ended December 31, 2017.due to the addition$5.4 million of 18 former Brushy employees, bonuses paid to officers at the completionamortized expense recognized on stock awards granted in prior years and $3.6 million of the Merger and an increase of $0.6 millionexpense recognized on vested stock awards granted in other administrative office expenses.
2018.44$1.6$25.3 million during the year ended December 31, 2016,2018, compared to $0.6$7.0 million during the year ended December 31, 2015,2017, an increase of $1.0$18.3 million, or 173%261%. The increase in DD&A was the result of the increase in production associated with the acquisition of the oil and gas properties in the Delaware Basin, New Mexico and Winkler County, Texas after the Merger. As a result of the Merger, ourOur DD&A rate decreasedincreased to $12.25$14.00 per BOE in 2016during the year ended December 31, 2018, from $46.93$12.21 per BOE in 2015. Theduring the year ended December 31, 2017. DD&A rate decreased primarilyexpense increased due to the volumesa sales volume increase of 115,414 barrels,1,236,877 BOE or 927%215% from 12,449575,229 BOE in 2015.Totalof $4.7 million were recorded duringfor the year ended December 31, 2016 as compared to $24.52018. We recorded impairment charges of $10.5 million during the year ended December 31, 2015,2017. Under the full cost method of accounting, we are required on a decreasequarterly basis to determine whether the book value of $19.8our oil and natural gas properties is less than or equal to the “ceiling,” based upon the expected after-tax present value of the future net cash flows discounted at 10% from our proved reserves. Any excess of the net book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense. For the year ended December 31, 2017, higher capital expenditures with slower than expected development of proved reserves contributed to the excess of net book value of our oil and natural gas properties over the ceiling resulting in the recognition of an impairment charge of $10.5 million. Years Ended December 31, 2018 2017 Variance % (In Thousands) Other income (expense): Other income $ 2 $ 18 $ (16 ) (89 )% Loss on early extinguishment of debt (20,370 ) — (20,370 ) (100 )% Gain (loss) from commodity derivatives 55 (1,063 ) 1,118 (105 )% Gain (loss) from embedded derivatives 58,343 (6,260 ) 64,603 (1,032 )% Loss from conditionally redeemable preferred stock — (41 ) 41 (100 )% Interest expense (32,827 ) (18,757 ) (14,070 ) 75 % Total other income (expense) $ 5,203 $ (26,103 ) $ 31,306 (120 )% 81%. The decrease105% during the year ended December 31, 2018, which primarily resulted from the function of $19.8 million was primarily due to full cost limitations recognizedfluctuations in the first and third quarter of 2015. The impairment expense of $24.5 million in 2015 was attributable to the write off of our proved undeveloped oil and gas properties in the DJ Basin due to lack of available capital to fund development coupled with significant decrease in oilunderlying commodity prices versus fixed hedge prices and to a lesser extent, natural gas prices, that started in late 2014 and continued throughout 2015. Years Ended December 31, 2016 2015 Variance % (In Thousands) Other income (expenses): Other income 90 3 87 2900 % Debt conversion inducement expense (8,307 ) - (8,307 ) -% Gain on extinguishment of debt 250 - 250 -% Gain (loss) in fair value of derivative instruments (1,222 ) 1,638 (2,860 ) -175 % Gain (loss) in fair value of conditionally redeemable 6% preferred stock (701 ) 514 (1,215 ) -236 % Gain on modification of convertible debts 602 - 602 -% Interest expense (4,924 ) (1,697 ) (3,227 ) 190 % Total other income (expenses) (14,212 ) 458 (14,670 ) -3203 % Net loss (32,843 ) (32,361 ) (482 ) 1 % Inducement Expense2016, an inducement expense2018, we had unrealized net gains of approximately $8.3$1.9 million was incurred ason mark-to-market adjustments on unsettled positions, which were partially offset by net losses of $1.9 million on cash settlement and resulted in a resultnet gain of debt and equity restructuring associated with the Merger. The inducement expense resulted from the repricing of our warrants to induce conversion of our convertible debt and our Series A preferred stock into common stock.Gain on Extinguishment of DebtDecember 31, 2016, we recognized a gain2017, our net loss from commodity derivatives consisted primarily of approximately $0.3net losses of $0.2 million attributed to a discounton cash settlements and $0.9 million on mark-to-market adjustments on unsettled position. Heartland Bank to settle the outstanding balance we owed under the Heartland Credit Agreement.Change in Fair Value in Derivative Instrumentscomprisedconsisted of a lossgain of approximately $1.2$58.3 million during the year ended December 31, 2016,2018, as compared to an approximately $1.6a loss of $6.3 million gain during the year ended December 31, 2015, is as follows:·Bristol Warrant Liabilities.On September 2, 2014, we entered into a Consulting Agreement with Bristol Capital, LLC (“Bristol”), pursuant to which we issued to Bristol a warrant to purchase up to 100,000 shares of our common2017. The $58.3 million gain was primarily attributed to the change in fair value of embedded derivatives resulting from the decrease of the Company’s stock price to $1.37 per share at an exercise price of $20.00 per share (or, in the alternative, 100,000 options, but in no case both). The agreement has a price protection feature that will automatically reduce the exercise price if we enter into another consulting agreement pursuant to which warrants are issued with a lower exercise price, which triggered in year 2016 and accordingly, the Company agreed to issue additional warrants/options to purchase 541,026 shares of common stock at a revised exercise price of $3.12. The change in fair value of this warrant provision was a loss of $1.2 million and a gain of $0.4 million for the years ended December 31, 2016 and 2015, respectively.45·Heartland Warrant Liability.On January 8, 2015, we entered into the Heartland Credit Agreement. In connection with the Heartland Credit Agreement, we issued to Heartland a warrant to purchase up to 22,500 shares of our common stock at an exercise price of $25.00. The warrant contains a price protection feature that will automatically reduce the exercise price if we enter into another agreement pursuant to which warrants are issued with a lower exercise price. The change in fair value valuation from issuance was $0.03 million and $0.01 million for the year ended December 31, 2016 and 2015, respectively.·SOSV Investments LLC Warrant Liability. On June 23, 2016, in conjunction with the Merger, we issued to SOSV Investments LLC (“SOS”) a warrant to purchase up to 200,000 shares of our common stock at an exercise price of $25.00. The warrant contains a price protection feature that will automatically reduce the exercise price if we enter into another agreement pursuant to which warrants are issued with a lower exercise price. For the year ended December 31, 2016, we incurred a change in the fair value of the derivative liability related to the warrant of approximately $0.1 million.Interest ExpenseFor the years ended December 31, 2016 and 2015, we incurred an interest expense of approximately $4.9 million and $1.7 million, respectively, of which approximately $4.2 million and $1.3 million was classified2018, as non-cash interest expense in 2016 and 2015, respectively. The detailscompared to $5.11 per share at December 31, 2017, net of the non-cash interestembedded derivatives associated with the partial conversion of the Second Lien Loans on October 10, 2018.2016 are as follows: (i) accretion of $3.92018, compared to $18.8 million of discount associated with bridge loans, convertible notes, the credit facility and term loan and (ii) amortization of the deferred financing costs of $0.3 million. The non-cash interest expense for the year ended December 31, 2015 was primarily attributable to the amortization of the deferred financing costs of approximately $0.1 million.At the current levels of net oil and gas production, cash balances, interest rates, and oil and gas prices, our revenue is unlikely to exceed our expenses. Unless and until we invest a substantial portion of our cash balances in interests in producing oil and gas wells or in one or more other ventures that produce revenue and net income, we are likely to experience net losses. With the exception of unanticipated environmental expenses and possible changes in interest rates and oil and gas prices, we are not aware of any other trends, events, or uncertainties that have had or that are reasonably expected to have a material impact on net sales or revenues or income from continuing operations.Liquidity and Capital ResourcesHistorically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions and investors, the sale of equity derivative securities and asset dispositions. Our primary uses of capital have been for the acquisition, development, exploration and exploitation of oil and natural gas properties, in addition to refinancing of debt instruments. In 2016, we entered into a new Credit Agreement and completed a preferred stock offering to raise additional capital. We regularly evaluate alternative sources of capital to complement our cash flow from operations and other sources of capital as we pursue our long-term growth plans in the Delaware Basin. In order to fully fund our 2017 capital budget, we may be required to access to new capital through one or more offerings of equity.We have reported net operating losses during the year ended December 31, 2016 and for the past five years. As a result, we funded our operations in 2016 and the merger with Brushy Resources, Inc. through additional debt and equity financing. On September 29, 2016, we entered into a new Credit and Guaranty Agreement (the “Credit Agreement”) that provides for a three-year, senior, secured term loan with initial aggregate principal commitments of $31 million and a maximum facility size of $50 million. The initial commitment on the term loan was funded with $25 million collected as of September 30, 2016 and the additional $6 million collected as of November 11, 2016.As of December 31, 2016, the Company had a working capital balance and a cash balance of approximately $5.7 million and $11.5 million, respectively. As of March 1, 2017, after giving effect to a drawdown of $7.1 million in additional term loan debt under the Credit Agreement on February 7, 2017, but excluding, the commitments entered into in connection with the March 2017 Private Placement (defined below) our cash balance was approximately $9.0 million. We believe that we will have sufficient capital to operate over the next 12 months. However, it is possible that we will seek to raise additional debt and equity capital depending on the pace of our drilling and leasing activity.46Information about our year-end cash flows are presented in the following table (in thousands): Year ended
December 31, 2016 2015 Cash provided by (used in): Operating activities $ (6,309 ) $ (3,951 ) Investing activities (19,130 ) (1,703 ) Financing activities 37,067 5,254 Net change in cash $ 11,628 $ (400 ) Operating activities.2017. For the year ended December 31, 2016,2018, we incurred interest expense of $3.0 million for quarterly interest payments and amortized debt issuance costs on the Riverstone First Lien Loans and the incremental bridge loans under the First Lien Credit Agreement, $12.2 million of paid-in-kind (“PIK”) interest, $14.4 million related to amortized debt discount on our Second Lien Term Loan and $3.2 million of amortized debt issuance costs. During the year ended December 31, 2017, we incurred $18.8 million of interest expense relating to amortized debt issuance costs on debentures, convertible notes and non-convertible notes. Year ended December 31, 2018 2017 (in thousands) Operating activities $ 92,132 $ (7,243 ) Investing activities (242,935 ) (147,502 ) Financing activities 154,478 160,469 Net change in cash $ 3,675 $ 5,724 activities was $6.3 million, compared to $4.0of $7.2 million for the same period in 2015.year ended December 31, 2017. The increase of $2.3$99.4 million in cash used in operating activities was primarily attributable to $35.0 million received from SCM and its affiliates for upfront fees associated with option to provide future gas midstream services. The increase is also the result of a significant increase in operating costsrevenue production and changes in working capital.activitiesActivities. For the year ended December 31, 2016,2018, net cash used in investing activities was $19.1$242.9 million compared to $1.7$147.5 million for the same period in 2015.year ended December 31, 2017. The $17.4$242.9 million increase in cash used in investing activities was primarily attributable to the following:·a $7.5 million increase in drilling and completion costs on the Grizzly and Bison wells;·a $4.2 million increase in oil and gas lease extension fees;·a $2.3 million cash consideration for the Merger, net of cash acquired; and·a $3.4 million increase on other capital expenditures relating to the DJ Basin and the Delaware Basin properties.activities.Activities. For the year ended December 31, 2016,2018, net cash provided by financing activities was $37.1$154.5 million compared to cash provided by financing activities of $5.3$160.5 million during the same period of 2015.year ended December 31, 2017. The increase of $31.8$154.5 million in net cash provided by financing activities was primarily attributable toincluded the following:·an $18.2 increase in net proceeds from the issuance of the Series B preferred stock;·a $30.0 million increase in net proceeds from the term loan facility executed during the third quarter of 2016;·a $0.3 million increase in proceeds received from the exercise of stock warrants;·offset by a $3.1 million decrease in net proceeds from the Bridge Loans; and·offset by an increase of $13.6 million in repayment of principal balances due to the Heartland Bank and Independent Bank.Merger with BrushyWe paid deposits and operating expenses of Brushy toward completion of the Merger of approximately $3.0 million, net of $0.7 million cash acquired, which is recorded as additional consideration.In connection with the closing of the Merger, we entered into the following financing transactions:Series A Preferred Stock ConversionOn June 23, 2016, after receiving the requisite shareholder approval and upon consummation of the Merger, each outstanding share of our Series A preferred stock automatically converted into common stock at a conversion price of $5.00 resulting in the issuance of 1,500,000Series C-1 and C-2 Preferred Stock, respectively; andcommon stock. In exchange for the reduction in price to convert into our common stock, all accrued, but unpaid dividends were forfeited.stock.2018 2017 Debt (in thousands) Revolving Credit Agreement $ 75,000 $ — Second Lien Credit Agreement 82,804 96,431 Bridge Loans associated with amended First Lien Term Loan — 30,363 Other notes payable — 1,011 Total debt 157,804 127,805 Mezzanine Equity Series C-1 Preferred Stock 106,774 — Series C-2 Preferred Stock 25,522 — Series D Preferred Stock 40,729 — Total mezzanine equity 173,025 — Stockholders' Equity Common stock 7 5 Additional paid-in capital 321,753 272,335 Treasury stock (997 ) — Accumulative deficit (307,431 ) (303,288 ) Total stockholders' equity (deficit) 13,332 (30,948 ) Total $ 344,161 $ 96,857 47(1) See Notes 9, 13 and 14 in the Notes to Consolidated Financial Statements for additional information about the Company’s outstanding debt and equity. Series B 6% Preferred StockJune 15, 2016,October 10, 2018, we entered into a private placement to sell 20,000 shares of our Series B 6% convertible preferred stock (the “Series B Preferred Stock”) with a conversion price of $1.10five-year, $500 million senior secured revolving credit agreement by and warrants to purchase up to 9,090,926 shares of common stock at an exercise price of $2.50, exercisable immediately for a period of two years underamong the Company, as borrower, certain circumstances, for gross proceeds of $20 million. For a more detailed descriptionsubsidiaries of the terms of the Series B Preferred Stock see Note 13-Shareholders Equity.In connection with the Series B Preferred Stock offering, we also paid a fee of $350,000 and $900,000 to T.R. Winston & Company, LLC (“TRW”) and KES 7 Capital Inc. (“KES 7”as guarantors (the “Guarantors”), respectively, who acted as co-placement agents with TRW also acting as administrative agent. Each of TRW and KES 7 also received fee warrants to purchase up to 452,724 and 820,000 shares of common stock, respectively, at an exercise price of $1.30, exercisable on or after September 17, 2016, for a period of two years. In addition, TRW received 150 shares of Series B Preferred Stock and the related warrants to purchase 68,182 shares of common stock at an exercise price of $2.50.DebenturesOn June 23, 2016, pursuant to the terms of the Debenture Conversion Agreement, dated as of December 29, 2015, our remaining outstanding 8% Convertible Debentures converted automatically upon consummation of the Merger at $5.00 per share, resulting in the issuance of 1,369,293 shares of common stock. In exchange for the lowering the conversion price, all accrued but unpaid interest was forfeited. The modification of such conversion rate resulted in an immaterial gain. The Convertible Debentures and associated derivative liability was then reclassified to additional paid-in capital.HeartlandBMO Harris Bank,On January 8, 2015, we entered into the Credit Agreement with Heartland Bank (the “Heartland Credit Agreement”) N.A., as administrative agent, and the Lenderslenders party thereto. The HeartlandRevolving Credit Agreement providedprovides for a three-year senior secured term loanreserve based revolving credit facility with an initial borrowing base of $95 million. The borrowing base is subject to semiannual redetermination in May and November of each year. On December 7, 2018, the Company’s borrowing base under the Revolving Credit Agreement was increased to $108 million as a result of its regularly scheduled fall redetermination process. We accelerated our May Revolving Credit borrowing base redetermination resulting in an initial aggregate principal amountincrease in our borrowing base to $125 million as of $3,000,000 (the “Heartland Term Loan”).In connection withMarch 1, 2019. We added an additional borrowing base redetermination in July that will include results of our 2019 drilling activity. Subsequent redeterminations are scheduled in November and May of each year.consummationRevolving Credit Agreement bear interest at a floating rate of either LIBOR or a specified base rate plus a margin determined based upon the usage of the Merger, on June 22, 2016, we repaid the balance of our outstanding indebtedness with Heartland at a discount of $250,000, resulting in the elimination of $2.75 million in senior secured debt and the extinguishment of Heartland’s security interest in our assets.Independent Bank and Promissory NoteOn June 22, 2016, in connection with the completion of the Merger, we entered into an amendment with Brushy and its senior secured lender, Independent Bank (the “Lender”), to Brushy’s Forbearance Agreement with the Lender (the “Fourth Amendment”), which, among other things, provided for a pay-down of $6.0 million of the principal amount outstanding on the loan (the “Loan”), plus fees and other expenses incurred in connection with the Loan, in exchange for an extension of the maturity date through December 15, 2016, at an interest rate of 6.5%, payable monthly. Additionally, we agreed to (i) guaranty the approximately $5.4 million aggregate principal amount of the Loan, (ii) grant a lien in favor of the Lender on all of our real and personal property, (iii) restrict the incurrence of additional debt and (iv) maintain certain deposit accounts with various restrictions with the Lender.As a condition of the Fourth Amendment and pursuant to the Merger Agreement, Brushy also completed the divestiture of certain of its assets in South Texas to its subordinated lender, SOS Ventures (“SOS”), in exchange for the extinguishment of $20.5 million of subordinated debt, a cash payment of $500,000, the issuance of the SOS Note, and the issuance of the SOS Warrant.On September 29, 2016, we repaid the Independent Bank debt in full, resulting in the extinguishment of Independent Bank’s security interest.Convertible NotesIn a series of transactions from December 29, 2015 to May 6, 2016, we issued an aggregate of approximately $5.8 million Convertible Notes maturing on June 30, 2016 and April 1, 2017, at a conversion price of $5.00. In connection with the December 2015 and March 2016 financing transactions, we issued warrants to purchase an aggregate of approximately 1.7 million shares of common stock with an exercise price of $2.50 per share and in connection with the May 2016 transaction, we issued warrants to purchase an aggregate of approximately 625,000 shares of common stock with an exercise price of $0.10 per share. Subsequently, as an inducement to participate in the May Convertible Notes offering, warrants to purchase up to 620,000 shares of common stock issued between December 2015 and March 2016 were amended and restated to reduce the exercise price to $0.10. As such, we recorded in other expense an inducement expense of $1.72 million.borrowing base. The proceeds of $5.8 million from these financing transactions were usedCompany is required to pay a $2.0 million refundable deposit in connection with the Merger, to fund certain operating expensescommitment fee of Brushy in an aggregate amount of $508,000, to fund approximately $1.3 million of interest payments to Heartland and to fund approximately $2.0 million in working capital and accounts payables.48In connection with the closing0.5% per annum on any unused portion of the Merger,borrowing base. The Company’s obligations under the Revolving Credit Agreement are secured by first priority liens on June 23, 2016, we entered into a Conversion Agreement with certain holders of Convertible Notes in an aggregate principal amount of approximately $4.0 million (the “Note Conversion Agreement”). The termssubstantially all of the Note Conversion Agreement provided thatCompany’s and the Convertible Notes were automatically converted into common stock upon the closingGuarantors’ assets and are unconditionally guaranteed by each of the Merger. PursuantGuarantors.the terms of the Note Conversion Agreement, in exchange for immediate conversion upon closing, the conversion price of the Convertible Notes was reduced to $1.10, which resulted in the issuance of 3,636,366 shares of common stock. The modification of such conversion rate resulted in a $3.4 million inducement charge recorded in other expense. Holders of these Convertible Notes waived and forfeited approximately $198,000 rights to receive accrued but unpaid interest.��On August 3, 2016, we entered into the first amendment to the Convertible Notes with the remaining holders of approximately $1.8 million of Convertible Notes. Pursuant to the first amendment: (i) the maturity date was changed to January 2, 2017, (ii) the conversion price was adjusted to $1.10 and (iii) the coupon rate was increased to 15% per annum. All accrued and unpaid interest on the Convertible Notes would have also been convertible in certain circumstances at the conversion price. Additionally, if the aggregate principal amount outstanding on the Convertible Notes was not either converted by the holder or repaidrepay in full on or beforeand retire the maturity date, we agreed to pay a 25% premium on the maturity date. We accounted for the reduction in the conversion price of remaining outstanding convertible notes as an inducement expense and recognized approximately $1.6Company’s previously existing $50 million in other income (expense). In exchange for the holders’ willingness to enter into the first amendment, we issued to the holders of additional warrants to purchase up to approximately 1.65 million shares of common stock. The warrants issued were valued using the following variables: (a) stock price of $1.15, (b) exercise price of $2.50, (c) contractual life of 3 years, (d) volatility of 203%, and (e) risk free rate of 0.76% for a total value of approximately $1.63 million. This amount was recorded as an inducement expense and an offset to additional paid-in capital.On September 29, 2016, in connection with our entry into theRiverstone First Lien Credit Agreement, the remaining holders of the Convertible Notes converted the outstanding principal amount of approximately $1.8 million and accrued and unpaid interest in an amount of approximately $138,000 into 1,772,456 shares of common stock.Credit Agreement and Warrant RepricingCredit AgreementOn September 29, 2016, we entered into the Credit Agreement which provides for a three-year senior secured term loan with initial commitments of $31 million in aggregate principal amount, of which $25 million was collected as of September 30, 2016 and the additional $6 million was collected as of November 11, 2016. The initial aggregate principal amount may be increased to a maximum principal amount of $50,000,000 at our request, but at the discretion of the Lenders, pursuant to an accordion advance provision in the Credit Agreement (the “Term Loan”).As discussed above, in connection with our entry into the Credit Agreement, on September 29, 2016, we used part of the proceeds of the Term Loan to repay the balance of Brushy’s outstanding indebtedness with Independent Bank, resulting in the elimination of approximately $5.4 million in senior secured debt, including accrued interest fees and expenses,a prepayment premium, and to pay transaction expenses. (See Note 9 for additional information regarding the extinguishment of Independent Bank’s security interest in the assets of the Initial Guarantors and of our guaranty to Independent Bank in full.Funds borrowedRiverstone First Lien Credit Agreement). Future borrowings under the Revolving Credit Agreement may be used by us to (i) fund drillingworking capital requirements, including for the acquisition, exploration and development projects, (ii) purchaseof oil and gas assetsproperties, and other acquisition targets, (iii) pay all costs and expenses arising in connection with the negotiation and execution of thefor general corporate purposes. The Revolving Credit Agreement and (iv) fund our general working capital needs.In connection with our entry into the Credit Agreement, we paid advisory fees to KES 7 and TRWalso provides for issuance of letters of credit in an amount of $420,000 and $200,000, respectively and a commitment fee to each of the Lenders equal to 2.0% of their respective initial loan advances. As partial consideration given to the lenders, we also amended certain warrants issued in the Series B preferred stock offering held by the lenders during the third and fourth quarters of the year ended December 31, 2016, to purchase up to an aggregate amount of approximately 2,840,000 and 681,822 shares of common stock, respectively, such that the exercise price per share was lowered from $2.50up to $0.01 on such warrants. $5 million.portion repriced in the fourth quarter was due to certain delayed funding that occurred after the initial commitment. The number of warrants amended for each Lender was basedRevolving Credit Agreement matures on the amountearlier of each Lender’s respective participation in the initial Term Loan relativefifth anniversary of the closing date and the date that is 180 days prior to the amount invested in the June 2016 Series B Preferred Stock private placement. Allmaturity date of the amended warrantsSecond Lien Credit Agreement (as defined below). Borrowings under the Revolving Credit Agreement are immediately exercisable from the original issuance date, for a period of two years, subject to mandatory repayment with the net proceeds of certain conditions. We accounted forasset sales and debt incurrences or if a borrowing base deficiency occurs. The Company also may voluntarily repay borrowings from time to time and, subject to the reduction in the conversion price as a deferred financing cost of $714,000borrowing base limitation and other customary conditions, may re-borrow amounts that are voluntarily repaid. Mandatory and voluntary repayments generally will be amortized over the length of the loan.
made without premium or penalty.49Term Loan bears interest at a rate of 6.0% per annum and matures on September 30, 2019. We have the right to prepay the Term Loan, in whole or in part, at any time at a prepayment premium equal to 6.0% of the amount repaid. Such prepayment premium must also be paid if the Term Loan is repaid prior to maturity as a result of a change in control. In certain situations, the Credit Agreement requires mandatory prepayments of the Term Loans at the request of the Lenders, including in the event of certain non-ordinary course asset sales, the incurrence of certain debt and our receipt of proceeds in connection with insurance claims.TheRevolving Credit Agreement contains certain customary representations and warranties and affirmative and negative covenants, including covenants relating toto: maintenance of books and records, financial reporting and notification, compliance with laws, maintenance of properties and insurance,insurance; and limitations on guaranties,incurrence of indebtedness, liens, fundamental changes, international operations, asset sales, certain debt payments and amendments, restrictive agreements, investments, issuancedividends and other restricted payments and hedging. It also requires the Company to maintain a ratio of debt, lease obligationsTotal Debt to EBITDAX of not more than 4.00 to 1.00 and capital expenditures. Thea ratio of current assets to current liabilities of not less than 1.00 to 1.00 (each as defined in the Revolving Credit Agreement). also provideseventsat least 20 of default, including failurethe 30 trading days immediately preceding the prepayment. The Company is required to pay a make-whole premium in connection with any mandatory or voluntary prepayment of the Second Lien Loans.oramount of each tranche of the Second Lien Loans, together with accrued and unpaid interest when due, failureand the make-whole premium on such principal amount (the “Conversion Sum”), will convert into a number of newly issued shares of common stock determined by dividing the total of such principal amount, accrued and unpaid interest and make-whole premium by $5.50 (subject to perform or observe covenants, cross-defaultcertain customary adjustments, the “Conversion Price”); andcertain outstanding debt obligations,a dollar for dollar basis into a new term loan (the “Take Back Loans”).failure of a Guarantor to comply withTake Back Loans will be substantially the provisions of its Guaranty, and bankruptcy or insolvency events. The amounts under the Credit Agreement could be accelerated and be due and payable upon an event of default.Subsequent EventsCredit Agreement DrawdownOn February 7, 2017, pursuant tosame as the terms of the Credit Agreement, we exercisedSecond Lien Loans, except that the accordion advance feature, increasingTake Back Loans will not be convertible and will bear interest payable in cash at a rate of LIBOR plus 9% (subject to a 1% LIBOR floor).aggregate principal amount outstanding underCompany has the term loan from $31 millionoption to $38.1 million. The total availability for borrowing remaining underconvert the Credit Agreement is $11.9 million. We intend to use the proceeds to fund its drilling and development program, for working capital and for general corporate purposes.As partial consideration, we also amended certain warrants issuedSecond Lien Loans, in the June 2016 private placement held by the Lenders to purchase up to an aggregate amount of approximately 738,638whole or in part, into shares of common stock such thatat any time or from time to time if, at the time of exercise of the Company’s conversion option, the closing price per share was lowered from $2.50 to $0.01 on such warrants The number of warrants amended for each Lender was basedthe common stock on the amount of each Lender’s respective participation in the initial Term Loan relative to the amount invested in the June 2016 private placement. Allprincipal exchange on which it is traded has been at least 150% of the amended warrants areConversion Price then in effect for at least 20 of the 30 immediately exercisable frompreceding trading days. Conversion at the original issuance date, for a period of two years, subject to certain conditions.March 2017 Private PlacementFebruary 28, 2017, weJanuary 31, 2018, the Company entered into a fourth amendment to the Second Lien Credit Agreement (“Amendment No. 4 to the Second Lien Credit Agreement”). The purpose of Amendment No. 4 to the Second Lien Credit Agreement was to, among other matters: permit us to enter the Riverstone First Lien Credit Agreement and incur the Riverstone First Lien Loans and related liens; permit us to issue the Series C Preferred Stock; and after the issuance of the Series C Preferred Stock pursuant to the Securities SubscriptionPurchase Agreement, (the “Subscriptionreduce from two to one the maximum number of members of the Board the lenders under the Second Lien Credit Agreement will have the right to appoint following the conversion of the convertible loans under the Second Lien Credit Agreement.certain institutionalAmendment No. 1 to the Riverstone First Lien Credit Agreement. Pursuant to such amendments and accredited investorsa consent letter received from the Purchasers (as defined in connection with a private placement (the “March 2017 Private Placement”)Note 9 of the Notes to sell 5.2 million units, consistingConsolidated Financial Statements), in their capacity as the holders of approximately 5.2 millionall of the issued and outstanding shares of common stock and warrantsSeries C Preferred Stock, the Company was granted the right to purchase approximately an additional 2.6 millionrepurchase shares of its common stock for an aggregate purchase price up to $10 million (subject to certain exceptions and conditions).approximately $20] million. Each unit consists of one share of common stockthe Second Lien Term Loan under the Second Lien Credit Agreement pursuant to the Transaction Agreement (as defined and described below).warrantSecurities Purchase Agreement (the “Securities Purchase Agreement”) with certain private funds affiliated with Värde Partners, Inc. (the “Purchasers”), pursuant to which we agreed to issue and sell to the Purchasers, and the Purchasers agreed to purchase 0.50from us, 100,000 shares of commona newly created series of preferred stock (each,of the Company, designated as “Series C 9.75% Convertible Participating Preferred Stock” (the “Series C Preferred Stock”), for a “Unit”), at a price per unit of $3.85. Each warrant has an exercisepurchase price of $4.50 and may be subject to redemption by$1,000 per share, or an aggregate of $100 million.upon prior written notice, ifentered into a Transaction Agreement (the “Transaction Agreement”) by and among the priceCompany and certain private funds affiliated with Värde Partners, Inc. (the “Värde Parties”), pursuant to which the Company agreed to:closespar value $0.0001 per share, which includes 5,802,763 shares of common stock at or above $6.30 for twenty trading days duringan exchange price of $5.00 per share of common stock plus an additional 150,000 shares of common stock, and (ii) 39,254 shares of a consecutive thirty trading day period. The closingnewly created series of preferred stock of the Offering is subjectCompany, designated as “Series D 8.25% Convertible Participating Preferred Stock” (the “Series D Preferred Stock”), as consideration for the reduction by approximately $56.3 million of the outstanding principal amount of the Second Lien Term Loan under the Second Lien Credit Agreement, together with accrued and unpaid interest and the make-whole amount thereon totaling approximately $11.9 million;satisfactionVärde Parties 25,000 shares of customary closing conditions.We expecta newly created subseries of the Company’s Series C 9.75% Convertible Participating Preferred Stock, designated as “Series C-2 9.75% Convertible Participating Preferred Stock” (the Offering to support our planned 2017 capital budget, andsale of the shares of Series C-2 Preferred Stock for general corporate purposes, including working capital.securities to be soldSeries D Preferred Stock and the Series C-2 Preferred Stock are recorded at fair value of $40.0 million and $25.0 million, respectively, as mezzanine equity as of December 31, 2018.private placement have not been registeredNotes to Consolidated Financial Statements for additional information about the Company’s Preferred Stock.Securities Act or any state securities lawsSRA are recorded as treasury stock. For the year ended December 31, 2018 the Company purchased 253,598 shares of the Company’s common stock for approximately $1.0 million.may not be offered or soldother oil and gas assets in Loving and Winkler Counties, Texas from VPD Texas, L.P. (“VPD”) for cash consideration of $10.6 million including $0.5 million of related acquisition costs (the “VPD Acquisition”). The VPD Acquisition was recorded at fair value which was the total cash consideration and related acquisition costs of approximately $10.7 million. VPD is an affiliate of Värde Partners, Inc. (“Värde”). Värde participated as lead lender in the United States absent registrationCompany’s Second Lien Term Loan transaction in 2017 and as investor of the Company’s Series C Preferred Stock transaction in January 2018. As a result, the VPD Acquisition is considered a related party transaction. See Note 11 - Related Party Transactions in the Notes to Consolidated Financial Statements.applicable exemption from registration. However,aggregate of (i) 9,891,638 shares of the Company’s common stock, par value $0.0001 per share (the “Term Loan Exchanged Common Stock”), (ii) 60,000 shares of a newly created series of preferred stock of the Company, designated as “Series E 8.25% Convertible Participating Preferred Stock” (the “Series E Preferred Stock” or the “Exchanged Series E Shares”), and (iii) 55,000 shares of a newly created series of preferred stock of the Company, designated as “Series F 9.00% Participating Preferred Stock” (the “Series F Preferred Stock” or the “Exchanged Series F Shares” and, together with the Exchanged Series E Shares, the “Exchanged Preferred Shares”), as consideration forconjunctionthe 2019 Transaction Agreement) and the satisfaction in full, in lieu of repayment in full in cash, of $133.6 million (the “Term Loan Exchange Amount”) pursuant to the Payoff Letter (as defined in the 2019 Transaction Agreement);March 2017 Private Placement, we have alsoissuance of shares of Common Stock, Series E Preferred Stock and Series F Preferred Stock pursuant to the 2019 Transaction Agreement, the Company entered into aan Amended and Restated Registration Rights Agreement (the “Amended and Restated Registration Rights Agreement”) to amend its existing registration rights agreement, whereby we agreeddated October 10, 2018 (the “October Registration Rights Agreement”), by and between the Company and the Värde Parties. Among other matters, the Amended and Restated Registration Rights Agreement amended the October Registration Rights agreement to use our reasonable best effortsrequire the Company to register, on behalf offile with the investors,SEC a registration statement under the Securities Act registering for resale the shares of common stock underlyingCommon Stock issued pursuant to the Units2019 Transaction Agreement and the shares of common stock underlyingCommon Stock issuable upon conversion of the warrants no later than April 1, 2017.Our 2017shares of Series E Preferred Stock issued pursuant to the Transaction Agreement. The Amended and Restated Registration Rights Agreement also provides that the Company may satisfy its obligation to file a registration statement by filing an amendment to the October Shelf Registration Statement (as defined in the Amended and Restated Registration Rights Agreement).budget may require additional financing aboveborrow money and retain personnel. We anticipate business costs will vary in accordance with commodity prices for oil and natural gas, and the level of cash generated by our operationsassociated increase or decrease in demand for services related to production and proceeds from recent financing activities. We can provide no assurance that additional financing would be available to us on acceptable terms, if at all.
exploration.50We doUS GAAP”) requires our management to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities at the date of our financial statements and the reported amounts of revenues and expenses during the reporting period. The following is a summary of the significant accounting policies and related estimates that affect our financial disclosures. US GAAP requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ significantly from those estimates. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment.Common Stock, options and warrants, inducement transactions, and estimated derivative liabilities.2016,2018, using the average, first-day-of-the-month price during the 12-month period ended December 31, 2016.gasoil and oilnatural gas is complex and is not exact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as gasoil and oilnatural gas 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; the interpretation of that data,data; the accuracy of various mandated economic assumptions; and the judgment of the persons preparing the estimate.company,Company, are used in comparative financial analysis ratios, and are used as the basis for the most significant accounting estimates in our financial statements, including the quarterly calculation of depletion, depreciation and impairment of our proved oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquidsNGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. We determine anticipated future cash inflows and future production and development costs by applying benchmark prices and costs, including transportation, quality and basis differentials, in effect at the end of each quarter to the estimated quantities of oil and natural gas remaining to be produced as of the end of that quarter. We reduce expected cash flows to present value using a discount rate that depends upon the purpose for which the reserve estimates will be used. For example, the standardized measure calculation requires us to apply a 10% discount rate. Although reserve estimates are inherently imprecise and estimates of new discoveries and undeveloped locations are more imprecise than those of established proved producing oil and natural gas properties, we make considerable effort to estimate our reserves, including through the use of independent reserves engineering consultants. We expect that quarterly reserve estimates will change in the future as additional information becomes available or as oil and natural gas prices and operating and capital costs change. We evaluate and estimate51full cost poolamortization base and becomes subject to the depletion calculations.whenin the amount that reflects the consideration it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidenceexpects to receive in exchange for transferring control of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller's pricethose goods to the buyer is fixed or determinable and (iv) collectability is reasonably assured.Company uses the entitlements method of accounting for oil, NGLs and gas revenues. Sales proceeds in excess of the Company's entitlement are included in other liabilities and the Company's share of sales taken by others is included in other assetscontract consideration in the accompanying consolidated balance sheets. The Company had no material oil, NGLCompany’s variable price contracts is typically allocated to specific performance obligations in the contract according to the price stated in the contract. Payment is generally received one or gas entitlement assets or liabilities as of December 31, 2016 or 2015.1 –2 - Summary of Significant Accounting Policies” to our consolidated financial statementsConsolidated Financial Statements in Item 816 of this Annual Report on Form 10-K.Report.Item 7A.Not applicable.52Item 8.Financial Statements and Supplementary Dataon Form 10-K, whichand are incorporated herein by reference. See “Index to Financial Statements” included in this Annual Report on Form 10-K.Report.Item 9.Changes in and Disagreements with Accountants on Accounting and Financial DisclosureNot applicableItem 9A.Controls and ProceduresAs required by Rule 13a-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), at the end of the period we carried out an evaluation, under the supervision andeffectivenesstime periods specified in the rules and forms of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act).SEC. Based upon thattheir evaluation, our Chief Executive Officer and Chief Financial Officer concluded that ourthe Company’s disclosure controls and procedures were effective as of December 31, 2016 at the reasonable assurance level.Changes in Internal Control over Financial ReportingManagement implemented internal audit activities to improve the Company’s governance and risk management based on assessment of systems and business processes. Management has conducted an assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2016. The assessment was based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 COSO Framework).Management’s assessment sufficiently addresses the risks of misstatements in financial reporting including risk of fraud2018.within key business processes. As a result, management has concluded that, as of December 31, 2016, the Company's internal control over financial reporting was effective and that the previously identified material weakness in the Company’s Form 10-K filed forinternal controls over financial reporting relating to our full cost ceiling test calculation during the year ended December 31, 20152017. The Company has been fully remediated.Remediationworked diligently to remediate the material weakness, including implementing measures to remediate the underlying causes that gave rise to the material weaknesses through implementation of Material Weaknessprocesses and controls ensuring compliance with GAAP. The Company has specifically enhanced review procedures and provided additional documentation, analysis and governance over the ceiling test calculation to ensure that these procedures are performed and recorded in Internal ControlContinuing intoaccordance with Company’s policies and GAAP. We took the fourth quarter of 2016, a number of remedialfollowing actions were takenwith respect to our full cost ceiling test calculation to address the previously existing material weaknesses. Management’s efforts included performing a top-down risk assessmentweakness:identify riskperform enhanced detailed reviews and analytical analysis on our current and projected tax position with respect to the impact of financial misstatementprojected income taxes on the ceiling test; and fraud risks relatedkey processes and activities, including identification of relevant assertions for each significant account and disclosure. Additionalvalidate the ceiling test calculation with the reserve report.included:1)Management identified the risk of fraud for significant accounts and disclosures.2)Management identified key risks within each business process and implemented controls to address each risk.3)Management conducted walkthroughs for key processes.4)Management assessed operating effectiveness by performing test procedures on samples of transactions.In addition, starting in 2016, management augmented and high-graded key staff with more experience and expertise, supplemented with outside consultants, to put into place an effective mechanism for monitoring our system of internal control.reporting.reporting (as defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Exchange Act). Our internal control over financial reportingstructure is a process designed by or under the supervision of our Chief Executive Officer and Chief Financial Officer and effected by our Board of Directors, management and other personnel to provide reasonable assurance to our management and board of directors regarding the reliability of our financial reporting and the preparation and fairness of our financial statements for external purposesstatement preparation in accordance with U.S. generally accepted accounting principles.2016,2018, based on the criteria for effective internalwe maintainedour internal control over financial reporting was effective as of December 31, 2018.2016.2018, and issued an attestation report set forth under the caption “Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting.”None.53The following table sets forthnames, ages and positionsdefinitive Proxy Statement of the persons who are our directors and executive officers as of March 1, 2016:NameAgePositionAbraham “Avi” Mirman47Chief Executive Officer, DirectorRonald D. Ormand58Executive Chairman of the Board of DirectorsNuno Brandolini63DirectorR. Glenn Dawson60DirectorGeneral Merrill McPeak81DirectorPeter Benz56DirectorJoseph C. Daches50Executive Vice President, Chief Financial Officer and TreasurerBrennan Short42Chief Operating OfficerAriella Fuchs35Executive Vice President, General Counsel and SecretarySeth Blackwell29Executive Vice President of Land and Business Development Abraham Mirman: Chief Executive Officer, Director. Mr. Mirman joined our Board of Directors (the “Board” or the “Board of Directors”) 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 of Chief 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 BMA Securities. Lastly, from 2006 to 2011, Mr. Mirman served as Chairman of the Board of Cresta Capital Strategies LLC. During Mr. Mirman’s service as Chief Executive 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 of Investment 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 our company.Ronald D. Ormand: Executive Chairman of the Board of Directors. Mr. Ormand joined Lilis’s Board of Directors in February, 2015, bringing with him more than 33 years of experience as a senior executive and investment banker in energy, including extensive financing and mergers and acquisitions expertise in the oil and gas industry. During his career, he has completed more than $25 billion of capital markets and financial advisory transactions, both as a principal and as a banker. Prior to joining Lilis, Mr. Ormand served as the Chairman and Head of the Investment Banking Group at MLV & Co. (“MLV”), which is now owned by FBR & Co., after it acquired MLV in September of 2015. After the acquisition, Mr. Ormand served as Senior Managing Director and Senior Advisor at FBR & Co. until May 2016, where he focused on investment banking and principal investments in the energy sector. Prior to joining MLV in November 2013, from 2009 to 2013, Mr. Ormand was a senior executive at Magnum Hunter Resources Corporation, or MHR (NYSE:MHR), an exploration and production company engaged in unconventional resource plays, as well as midstream and oilfield services operations. He was part of the management team that took over 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 Officer and 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 internal controls for financial reporting. Specifically, Mr. Ormand agreed to cease and desist from violating Sections 13(a) and 13(b)(2)(A) and (B) of the Exchange Act and Rules 13a-1, 13a-13 and 13-15(a) thereunder. He has also paid a penalty of $25,000. The SEC did not allege any anti-fraud violations, intentional misrepresentations 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 and Gas 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. Ormand has previously served as a Director of Greenhunter Resources, Inc. (2011-2013), Tremisis (2007-2009), and Eureka Hunter Holdings, Inc., a private midstream company (2010-2013). Mr. Ormand holds a B.A. in Economics, an M.B.A. in Finance and Accounting from UCLA and studied Economics at Cambridge University, England.54Director Qualifications:·Leadership Experience - Senior executive at Magnum Hunter Resources Corporation, Chairman and Head of Investment Banking at MLV and Head of US Oil and Gas for CIBC and investment banker.·Industry Experience - Extensive experience in oil and gas development and services industries at the entities and in the capacities described aboveNuno 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 Scorpion Capital Partners, L.P., a private equity firm organized as a small business investment company until June 2014. Prior to forming Scorpion Capital and its predecessor firm, Scorpion Holding, Inc., in 1995, Mr. Brandolini served as managing director of Rosecliff, Inc., a leveraged buyout fund co-founded by Mr. Brandolini in 1993. Mr. Brandolini served previously as a vice president in the investment banking department of Salomon Brothers, Inc., and a principal with the Batheus Group and Logic Capital, two venture capital firms. Mr. Brandolini began his career as an investment banker with Lazard Freres & Co. Mr. Brandolini is a director of Cheniere Energy, Inc. (NYSE MKT: LNG), a Houston-based company primarily engaged in LNG related businesses. Mr. Brandolini received a law degree from the University of Paris and an M.B.A. from the Wharton School.Director Qualifications:·Leadership Experience - Executive positions with several private equity firms, and Board position with Cheniere Energy, Inc.·Industry Experience - Service on the Board of Cheniere Energy, Inc., as well as personal investments in the oil and gas industry.R. Glenn Dawson: Director. Mr. Dawson joined our Board of Directors on January 13, 2016. Mr. Dawson has over 30 years of experience in oil and gas exploration in North America and is currently President and Chief Executive Officer of Cuda Energy, Inc., a private Canadian-based exploration and production company. Mr. Dawson’s career includes serving as President of Bakken Hunter, a division of MHR, where he managed operations and development of Bakken assets in the United States and Canada, from 2011 to 2014. His principal responsibilities have involved the generation and evaluation of drilling prospects and production acquisition opportunities. In the early stages of his career, Mr. Dawson was employed as an exploration geologist by Sundance Oil and Gas, Inc., a public company located in Denver, Colorado, concentrating on their Canadian operations. From December 1985 to September 1998, Mr. Dawson held a variety of managerial and technical positions with Summit Resources, a then-public Canadian oil and gas exploration and production company, including Vice President of Exploration, Exploration Manager and Chief Geologist. He served as Vice President of Exploration with PanAtlas Energy Inc., a then-public Canadian oil and gas exploration and production company, from 1999 until its acquisition by Velvet Exploration 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 gas exploration company, from 2001 to 2005, until it was acquired by Enerplus Resources Fund. As a result of the sale of TriLoch Resources Inc. to Enerplus Resources Fund, Mr. Dawson founded NuLoch Resources, Inc. in 2005. Mr. Dawson graduated in 1980 from Weber State University of Utah with a Bachelor’s degree in Geology and attended the University of Calgary from 1980 to 1982 in the Masters Program for Geology. As a result of these professional experiences, Mr. Dawson possesses particular knowledge and experience in the operations of oil and gas companies that strengthen the Board’s collective qualifications, skills, and experience.55Director 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. Air Force and flew 269 combat missions in Vietnam during his distinguished 37-year military career. Following retirement from active service in 1994, General McPeak launched a second career in business. He was a founding investor and chairman of Ethics Point, an ethics and compliance software and services company, which was subsequently restyled as industry leader Navex Global, and acquired in 2011 by a private equity firm. General McPeak co-invested and remained a board member of Nava Global, which was sold again in 2014. From 2012 to 2014, General McPeak was Chairman of Coast Plating, Inc., a Los Angeles-based, privately held provider of metal processing and finishing services, primarily to the aerospace industry, which was also acquired in a private equity buyout. He remains a director of that company, now called Valence Surface Technologies. He also currently serves as a director of Aerojet Rocketdyne, 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. Since 2010, General McPeak has been Chairman of the American Battle Monuments Commission, an agency of the executive branch of the federal government, responsible for operating and maintaining American cemeteries in foreign countries holding the remains of 125,000 US servicemen. General McPeak has a B.A. degree in Economics from San Diego State College and an M.S. in International Relations from George Washington University. He is a graduate of the National War College and of the Executive Development Program of the University of Michigan Graduate School of Business. He spent an academic year as Military Fellow at the Council on Foreign RelationsDirector Qualifications:·Leadership Experience - Chief of Staff of the U.S. Air Force; Founding investor and chairman of Ethicspoint (subsequently Navex Global).·Industry Experience - Personal investments in the oil and gas industry.Peter Benz: Director. Mr. Benz joined our Board of Directors on June 23, 2016 in connection with the completion of the merger with Brushy. Prior to that, Mr. Benz had served on Brushy’s Board of Directors since January 20, 2012. Mr. Benz serves as the Chairman and Chief Executive Officer of Viking Asset Management, LLC and is a member of its Investment Committee. He has been affiliated with Viking Asset Management, LLC since 2001. His responsibilities include assuring a steady flow of candidate deals, making asset allocation and risk management decisions and overseeing all business and investment operations. He has more than 25 years of experience specializing in investment banking and corporate advisory services for small growth companies in the areas of financing, merger/acquisition, funding strategy and general corporate development. Prior to founding Viking in 2001, Mr. Benz founded Bi Coastal Consulting Company where he advised hundreds of companies regarding private placements, initial public offerings, secondary public offerings and acquisitions. He has founded three public companies and served as a director for four other public companies. Prior to founding Bi Coastal Consulting, Mr. Benz was responsible for private placements and investment banking activities at Gilford Securities in New York, NY. Mr. Benz became a director of usell.com, Inc. on May 15, 2014. Mr. Benz is a graduate of Notre Dame University. As a result of these professional experiences, Mr. Benz possesses particular knowledge and experience in developing companies and capital markets that strengthen the board of director’s collective qualifications, skills, and experience.Director Qualifications:·Leadership Experience –Chairman and CEO of Viking Asset Management; founded three public companies.56·Industry Experience –Extensive experience in the investment banking and corporate advisory services industries; founded Bi Coastal Consulting, a consulting company advising companies regarding private placements, initial public offerings, secondary public offerings and acquisitions.Joseph C. Daches: Executive Vice President, Chief Financial Officer and Treasurer. On January 23, 2017, our Board appointed Joseph Daches to the position of Executive Vice President, Chief Financial Officer and Treasurer, effective immediately. Prior to joining our company, Mr. Daches most recently held the position of Chief Financial Officer and Senior Vice President of Magnum Hunter Resources Corp. (“MHR”) from July 2013 to June 2016, where he finished his tenure by successfully guiding MHR through a restructuring, and upon emergence was appointed Co-CEO by MHR’s new board of directors until his departure. Mr. Daches has over 20 years of experience and expertise in directing strategy, accounting and finance in primarily small and mid-size oil and gas companies and has helped guide several of those companies through financial strategy, capital raises and private and public offerings. Prior to joining MHR, Mr. Daches served as Executive Vice President, Chief Accounting Officer and Treasurer of Energy & Exploration Partners, Inc. from September 2012 until June 2013 and as a director of that company from April 2013 through June 2013. He previously served as a partner and Managing Director of the Willis Consulting Group, LLC, from January 2012 to September 2012. From October 2003 to December 2011, Mr. Daches served as the Director of E&P Advisory Services at Sirius Solutions, LLC, where he was primarily responsible for financial reporting, technical and oil and gas accounting and the overall management of the E&P Advisory Services practice. Mr. Daches earned a Bachelor of Science in Accounting from Wilkes University in Pennsylvania, and he is a certified public accountant in good standing with the Texas State Board of Public Accountancy.Brennan Short: Chief Operating Officer. On January 27, 2017, our Board appointed Brennan Short to the position of Chief Operating Officer, effective immediately. Mr. Short most recently held the position of President at MMZ Consulting Inc. from May 2012 to January 2017, where he provided full cycle drilling & completions engineering and operational support to multiple clients. Mr. Short has over 20 years of proven expertise in domestic oil & gas exploration and production operations, field supervision, management and petroleum engineering consulting. Prior to forming MMZ Consulting Inc., Mr. Short held the position of Drilling Engineering Specialist at EOG Resources, Inc. from March 2010 to May 2012, where he was a drilling engineer in the infancy of the Eagleford Shale Play in South Texas. Previous to his role EOG Resources, Inc., Mr. Short was a Drilling Engineer at SM Energy from November 2007 to March 2010 and a Drilling Engineer at Samson Investment Company from March 2005 to November 2007. Mr. Short earned his Bachelor’s degree in Petroleum Engineering from Texas A&M University.Ariella Fuchs: Executive Vice President, General Counsel and Secretary. Ariella Fuchs joined our company in March 2015. Prior to that, Ms. Fuchs was an associate with Baker Botts L.L.P. from April 2013 to February 2015, specializing in securities transactions and corporate governance. Prior to joining Baker Botts L.L.P, she served as an associate at White & Case LLP and Dewey and LeBoeuf LLP from January 2010 to March 2013 in their mergers and acquisitions groups. Ms. Fuchs received a J.D. from New York Law School and a B.A. in Political Science from Tufts University.Seth Blackwell: Executive Vice President of Land and Business Development. Seth Blackwell joined our company in December 2016. Mr. Blackwell is a Professional Landman with extensive knowledge and experience in all facets of land management. Prior to joining our company, Mr. Blackwell held the position of Vice President of Land for XOG Resources where he managed all land and business development efforts for the company. Mr. Blackwell also gained extensive experience in a wide variety of major US oil and gas plays while working for Occidental Petroleum. Mr. Blackwell started his career blocking together large acreage positions in excess of 30,000 acres throughout Central and East Texas. Mr. Blackwell is an active member of the American Association of Professional Landman, North Houston Association of Professional Landman and the Houston Association of Professional Landman. Mr. Blackwell holds a bachelor’s degree in Business Management from Fort Hays State University and is currently pursuing his MBA in Energy from the University of Tulsa.Directors hold office for a period of one year from their election at the annual meeting of stockholders and until a particular director’s successor is duly elected and qualified. Officers are elected by, and serve at the discretion of, our Board of Directors. None of the above individuals has any family relationship with any other. It is expected that our Board of Directors will elect officers annually following each annual meeting of stockholders.57Section 16(a) Beneficial Ownership Reporting ComplianceOur executive officers and directors and persons who own more than 10% of our common stock are required to file reports with the SEC, disclosing the amount and nature of their beneficial ownership in our common stock, as well as changes in that ownership. Based solely on our review of reports and written representations that we have received, we believe that all required reports were timely filed during 2016 and through the date of this report, except as follows:·Kevin Nanke filed one Form 4, reporting one transaction late.·R. Glenn Dawson filed one Form 4 reporting one transaction late. After the reporting period, Mr. Dawson filed one Form 4 reporting one transaction late.·Sean O-Sullivan Revocable Living Trust (the “SOS Trust”) filed one Form 3 late, as well as an amendment to such Form 3 reporting his initial beneficial ownership late. The SOS Trust filed three Form 4s reporting eight transactions late, as well as an amendment to one of the late Form 4s, reporting an additional two transactions late.·SOSVentures LLC filed one Form 3 late.·Ronald D. Ormand filed one Form 4 amendment reporting two transactions late.·Peter Benz filed one Form 4 amendment reporting one transaction late.·Joseph C. Daches filed one Form 3 reporting his initial beneficial ownership late.The Board of Directors and Committees ThereofOur Board of Directors conducts its business through meetings and through its committees. Our Board of Directors held ten meetings in 2016 and took action by unanimous written consent on nine occasions. Each director attended at least 75% of (i) the meetings of the Board held after such director’s appointment and (ii) the meetings of the committees on which such director served, after being appointed to such committee. Our policy regarding directors’ attendance at the annual meetings of stockholders is that all directors are expected to attend, absent extenuating circumstances.Affirmative Determinations Regarding Director Independence and Other MattersOur Board of Directors follows the standards of independence established under the rules of the Nasdaq Stock Market, or the Nasdaq, as well as our Corporate Governance Guidelines on Director Independence, which was amended on December 10, 2015, a copy of which is available on our website at www.lilisenergy.com under “Investors-Corporate Governance-Highlights” in determining if directors are independent. The Board has determined that four of our current directors, Mr. Brandolini, General McPeak, Mr. Benz and Mr. Dawson are “independent directors” under the Nasdaq rules referenced above.No independent director receives, or has received, any fees or compensation directly as an individual from us other than compensation received in his or her capacity as a director or indirectly through their respective companies, except as described below. See “Certain Relationships and Related Transactions, and Director Independence”. There were no transactions, relationships or arrangements not otherwise disclosed that were considered by the Board of Directors in determining whether any of the directors were independent.Committees of the Board of DirectorsPursuant to our amended and restated bylaws, our Board of Directors is permitted to establish committees from time to time as it deems appropriate. To facilitate independent director review and to make the most effective use of our directors’ time and capabilities, our Board of Directors has established an audit committee, a compensation committee and a nominating and corporate governance committee. The membership and function of these committees are described below.58Audit CommitteeDuring the year ended December 31, 2016, each of Mr. Brandolini, General McPeak, Mr. Dawson and Mr. Benz served on the audit committee. Currently, the audit committee consists of Mr. Benz, Mr. Brandolini and General McPeak. Mr. Benz is the acting as chairman of the audit committee and meets the definition of an audit committee financial expert. Our Board of Directors determined that each of Mr. Brandolini, General McPeak, Mr. Dawson and Mr. Benz were independent as required by Nasdaq for audit committee members.The audit committee met four times during the year ended December 31, 2016, but met separately on several occasions in connection with a meeting of the full Board of Directors. The audit committee is governed by a written charter that is reviewed, and amended if necessary, on an annual basis. A copy of the charter is available on our website at www.lilisenergy.com under “Investors-Corporate Governance-Highlights.”Compensation CommitteeOur compensation committee currently consists of Mr. Brandolini, General McPeak and Mr. Dawson. Mr. Ormand had also served on the compensation committee, but resigned 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 chairman of the compensation committee.The compensation committee met six times during the year ended December 31, 2016, and acted by written consent twice. The compensation committee has also met separately on several occasions in connection with a meeting of the full Board. The Board determined that each of Mr. Brandolini, General McPeak and Mr. Dawson were independent as required by Nasdaq for compensation committee members.The compensation committee reviews, approves and modifies our executive compensation programs, plans and awards provided to our directors, executive officers and key associates. The compensation committee also reviews and approves short-term and long-term incentive plans and other stock or stock-based incentive plans. In addition, the committee reviews our compensation and benefit philosophy, plans and programs on an as-needed basis. In reviewing our compensation and benefits policies, the compensation committee may consider the recruitment, development, promotion, retention, compensation of our executive and senior officers, trends in management compensation and any other factors that it deems appropriate. Under its charter, the compensation committee may create and delegate such tasks to such standing or ad hoc subcommittees as it may determine to be necessary or appropriate for the discharge of its responsibilities, as long as the subcommittee has at least the minimum number of directors necessary to meet any regulatory requirements. The compensation committee may engage consultants in determining or recommending the amount of compensation paid to our directors and 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 is available on our website at www.lilisenergy.com under “Investors-Corporate Governance-Highlights.”Nominating and Corporate Governance CommitteeOur nominating and corporate governance committee currently consists of Mr. Benz, General McPeak and Mr. Brandolini, who is the chairman of the nominating and corporate governance committee. The nominating and corporate governance committee met once during the year ended December 31, 2016, but met separately on several occasions in connection with a meeting of the full Board.The primary responsibilities of the nominating and corporate governance committee include identifying, evaluating and recommending, for the approval of the entire Board of Directors, potential candidates to become members of the Board of Directors, recommending membership on standing committees of the Board of Directors, developing and recommending to the entire Board of Directors corporate governance principles and practices for our company and assisting in the implementation of such policies, and assisting in the identification, evaluation and recommendation of potential candidates to become officers of our company. The nominating and corporate governance committee will review our code of business conduct and ethics and its enforcement, and reviews and recommends to our Board of Directors whether waivers should be made with respect to such code. A copy of the nominating and corporate governance committee charter may be found on our website at www.lilisenergy.com under “Investor Relations-Corporate Governance-Highlights.” During fiscal year 2016, there have been no material changes to the procedures by which security holders may recommend nominees to our Board of Directors.59Communications with the Board of DirectorsStockholders may communicate with our Board of Directors or any of the directors by sending written communications addressed to the Board of Directors or any of the directors, Lilis Energy, Inc., 300 E. Sonterra Blvd., Suite No. 1220, San Antonio, Texas 78258, Attention: General Counsel. All communications are compiled by the general counsel and forwardedrelating to the BoardCompany’s 2019 Annual Meeting of Directors orStockholders, which will be filed with the individual director(s) accordingly.Code of EthicsOur Board of DirectorsSecurities and Exchange Commission and is incorporated herein by reference.business conduct and ethics, which we refer to as theour Code of Business Conduct, that applies to all of our officers and employees, including ourthe Company’s chief executive officer, chief financial officer or controller, and persons performing similar functions. Ourchief accounting officer. The full text of such code of business conduct and ethics codifieshas been posted on the business and ethical principles that govern all aspects of our business. A copy of our code of business conduct and ethics is available on ourCompany’s website at www.lilisenergy.com under “Investors-Corporate Governance-Highlights.” We undertake to provide a copyand is available free of our code of business conduct and ethicscharge in print to any person, at no charge, upon a written request. All writtenstockholder who requests it. Request for copies should be directed to: Lilis Energy, Inc., 300 E. Sonterra Blvd.,addressed to the Vice President of Human Resources at mailing address, 1800 Bering Drive, Suite No. 1220, San Antonio,510, Houston, Texas 78258, Attention: General Counsel. If any substantive amendments are made to our code of business conduct and ethics, or if any waiver (including any implicit waiver) is granted from any provision of the code of business conduct and ethics to our chief executive officer, chief financial officer or controller, we will disclose the nature of such amendment or waiver on our website at www.lilisenergy.com under “Investors-Corporate Governance-Highlights.” or, if required, in a Current Report on Form 8-K.77057.Executive Compensation for Fiscal Year 2016The compensation earned by our executive officers foryear ending December 31, 2016 consisteddefinitive Proxy Statement of base salary, short-term incentive compensation consisting of cash payments and long-term incentive compensation consisting of awards of stock grants. All share and per share amounts, fair values per share and exercise prices that appear in this section have been adjusted to reflect the 1-for-10 reverse stock split of our outstanding common stock effected on June 23, 2016.Summary Compensation TableThe table below sets forth compensation paid to our named executive officers (NEOs) for the years ending December 31, 2016 and 2015.Name and Principal
Position Year Salary
($) Bonus
($) Stock
Awards
($)(1) Option
Awards
($)(2) All Other
Compensation
($)(3) Total
($) Abraham “Avi” Mirman 2016 350,000 175,000 (4) ─ 4,295,894 22,484 4,843,378 (Chief Executive Officer) 2015 325,466 100,000 (5) 90,000 1,397,721 31,504 1,944,691 Ronald D. Ormand(6) 2016 150,000 ─ 1,875,000 533,092 69,502 2,627,594 (Chairman of the Board of Directors) Ariella Fuchs 2016 240,000 112,500 (4) ─ 1,288,768 8,417 1,649,685 (General Counsel and Secretary) 2015 182,083 ─ 48,000 234,887 10,538 475,508 60(1)Represents restricted stock awards. The grant date fair values for restricted stock awards were computed in accordance with FASB ASC Topic 718. The amounts reported in this column reflect the accounting cost for the stock awards and do not necessarily correspond to the actual economic value that may be received for the stock awards.(2)Awards in this column are reported at grant date fair value, if awarded in the period, and any incremental fair value, if modified in the period, in each case in accordance with FASB ASC Topic 718. Mr. Mirman was granted 1,250,000 options on each of June 24, 2016 and December 15, 2016; Mr. Ormand was granted 250,000 options on December 15, 2016; and Ms. Fuchs was granted 375,000 options on each of June 24, 2016 and December 15, 2016. The grant date fair values for options granted on June 24, 2016 and December 15, 2016 were $1.30 (rounded) and $2.13 (rounded), respectively. For both Mr. Mirman and Ms. Fuchs, their options granted June 24, 2016 were modified December 15, 2016 to provide for accelerated exercisability upon an involuntary employment termination and upon a change in control, and for extension of the post-termination exercise period upon an employment termination other than for cause. However, there was no incremental fair value for those modified options. The amounts reported in this column reflect the accounting cost for the options and do not correspond 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 in the notes to our consolidated financial statements included in this Annual Report on Form 10-K.(3)For 2016, reflects reimbursement of health insurance premiums for all of the NEOs. For Mr. Ormand, the amount also reflects $55,000 in director fees paid to him for his Board service in 2016 prior to the time he became an officer.(4)Reflects a bonus payable under the officer’s employment agreement for the successful completion of the Brushy merger.(5)Reflects a sign-on bonus.(6)Effective July 11, 2016, Mr. Ormand began to serve as Executive Chairman of the Board, which is an officer position. Prior to July 11, 2016, Mr. Ormand was a nonemployee director of the Board and his compensation from January 1 to July 10, 2016 is reflected under All Other Compensation.Outstanding Equity Awards at Fiscal Year-End Option Awards Stock Awards Name Number of
Securities
Underlying
Unexercised
Options
(#)
Exercisable Number of
Securities
Underlying
Unexercised
Options
(#)
Unexercisable
Exercise
Price Option
Expiration
Date Number of
Shares or
Units of
Stock That
Have Not
Vested
(#) Market
Value of
Shares or
Units of
Stock That
Have Not
Vested
($) Abraham “Avi” Mirman 170,000 330,000 (1) 2.98 12/15/2026 ─ ─ 425,000 825,000 (2) 1.34 6/24/2026 ─ ─ 60,000 ─ 21.10 9/16/2023 ─ ─ Ronald D. Ormand 85,000 165,000 (1) 2.98 12/15/2026 833,333 (3) 2,583,332 31,666 13,334 (4) 16.50 4/20/2025 ─ ─ Ariella Fuchs 127,500 247,500 (1) 2.98 12/15/2026 ─ ─ 127,500 247,500 (2) 1.34 6/24/2026 ─ ─ (1)Options vest in equal installments on each of December 15, 2017 and 2018, subject to acceleration provisions and continued service(2)Options vest in equal installments on each of June 24, 2017 and 2018, subject to acceleration provisions and continued service.(3)Restricted shares vest in equal installments on each of July 7, 2017 and July 7, 2018, subject to acceleration provisions and continued service.(4)Options vest in equal installments on each of April 20, 2017 and 2018, subject to acceleration provisions and continued service.61Employment Agreements and Other Compensation Arrangements2012 Equity Incentive Plan (“2012 EIP”) (formerly the RecoveryLilis Energy, Inc. 2012 Equity Incentive Plan)Our Board and stockholders approved our 2012 EIP in August 2012. The 2012 EIP provided for grants of equity incentives to: attract, motivate and retain the best available personnel for positions of substantial responsibility; provide additional incentives to our employees, directors and consultants; and promote the success and growth of our business. Equity incentives that were available for grant under our 2012 EIP included stock options, stock appreciation rights (SARs), restricted stock awards, restricted stock units (RSUs), and unrestricted stock awards.Our 2012 EIP is administered by our compensation committee, subjectrelating to the ultimate authorityCompany’s 2019 Annual Meeting of our Board,Stockholders, which has full power and authority to take all actions and to make all determinations required or provided for under the 2012 EIP.Under our 2012 EIP, 1,000,000 shares of our common stock were available for issuance. As a result of the adoption of our 2016 Plan, awards are no longer made under the 2012 EIP, as discussed below.2016 Omnibus Incentive Plan (“2016 Plan”)BackgroundOur 2016 Plan was approved by our Board effective April 20, 2016 and approved by our stockholders at their 2016 annual meeting on May 23, 2016. Our 2016 Plan replaced our 2012 EIP.The purposes of our 2016 Plan are to create incentives that are designed to motivate eligible directors, officers, employees and consultants to put forth maximum effort toward our success and growth, and to enable us to attract and retain experienced individuals who by their position, ability and diligence are able to make important contributions to our success.EligibilityAwards may be granted under our 2016 Plan to officers, employees, directors, consultants and advisors of the Company and its affiliates. Tax-qualified incentive stock options may be granted only to employees of the Company or its subsidiaries.AdministrationOur 2016 Plan may be administered by our Board or its compensation committee. Our compensation committee, in its discretion, generally selects the individuals to whom awards may be granted, the time or times at which awards are granted and the terms and conditions of awards.Number of Authorized SharesWhen initially approved by our stockholders, 50,000,000 shares of our common stock were made available for issuance under our 2016 Plan. As a result of our 1-for-10 reverse stock split, which took effect on June 23, 2016, the number of shares available for issuance under our 2016 Plan was automatically reduced to 5,000,000. On August 25, 2016, our Board approved an amendment to our 2016 Plan to increase the maximum number of shares that may be issued from 5,000,000 to 10,000,000, and our stockholders approved that amendment at a special meeting on November 3, 2016.62In addition, as of May 23, 2016, any awards then outstanding under our 2012 EIP remain subject to and will be paid under the 2012 EIP and any shares then subject to outstanding awards under the 2012 EIP that subsequently expire, terminate or are surrendered or forfeited for any reason without issuance of shares will automatically become available for issuance under our 2016 Plan. Up to 5,000,000 shares may be granted as tax-qualified incentive stock options under our 2016 Plan. The shares issuable under our 2016 Plan will consist of authorized and unissued shares, treasury shares or shares purchased on the open market or otherwise.If any award is canceled, terminates, expires or lapses for any reason prior to the issuance of shares or if shares are issued under our 2016 Plan and thereafter are forfeited to the Company, the shares subject to those awards and the forfeited shares will not count against the aggregate number of shares available for grant under the plan. In addition, the following items will not count against the aggregate number of shares available for grant under our 2016 Plan: (1) the payment in cash of dividends or dividend equivalents under any outstanding award, (2) any award that is settled in cash rather than by issuance of shares, (3) shares surrendered or tendered in payment of the option price or purchase price of an award or any taxes required to be withheld in respect of an award or (4) awards granted in assumption of or in substitution for awards previously granted by an acquired company.Limits on Awards to Nonemployee DirectorsThe maximum number of shares subject to awards under our 2016 Plan granted during any calendar year to any nonemployee member of our Board, taken together with any cash fees paid to the director during the fiscal year, may not exceed $500,000 in total value (calculating the value of any such awards based on the grant date fair value of such awards for financial reporting purposes).Types of AwardsOur 2016 Plan permits the granting of any or all of the following types of awards: stock options, which entitle the holder to purchase a specified number of shares at a specified price; SARs, which, upon exercise, entitle the holder to receive payment per share in stock or cash equal to the excess of the share’s fair market value on the date of exercise over the grant price of the SAR; restricted stock, which are shares of common stock subject to specified restrictions; RSUs, which represent the right to receive shares of our common stock in the future; other types of equity or equity-based awards; and performance awards, which entitle participants to receive a payment from the Company, the amount of which is based on the attainment of performance goals established by the compensation committee over a specified award period.No RepricingWithout shareholder approval, our compensation committee is not authorized to (1) lower the exercise or grant price of a stock option or SAR after it is granted, except in connection with certain adjustments to our corporate or capital structure permitted by our 2016 Plan, such as stock splits, (2) take any other action that is treated as a repricing under generally accepted accounting principles or (3) cancel a stock option or SAR at a time when its exercise or grant price exceeds the fair market value of the underlying stock, in exchange for cash, another stock option or SAR, restricted stock, RSUs or other equity award, unless the cancellation and exchange occur in connection with a change in capitalization or other similar change.ClawbackAll awards granted under our 2016 Plan will be subject to all applicable laws regarding the recovery of erroneously awarded compensation, any implementing rules and regulations under such laws, any policies we adopt to implement such requirements and any other compensation recovery policies as we may adopt from time to time.Transferability2016 Plan awards are not transferable other than by will or the laws of descent and distribution, except that in certain instances transfers may be made to or for the benefit of designated family members of the participant for no value.63Effect of Change in ControlUnder our 2016 Plan, in the event of a change in control, outstanding awards will be treated in accordancefiled with the applicable transaction agreement. If no treatmentSecurities and Exchange Commission and is provided for in the transaction agreement, each award holder will be entitled to receive the same consideration that stockholders receive in the change in control for each share of stock subject to the award holder’s awards, upon the exercise, payment or transfer of the awards, but the awards will remain subject to the same terms, conditions and performance criteria applicable to the awards before the change in control, unless otherwise determinedincorporated herein by our compensation committee. In connection with a change in control, outstanding stock options and SARs can be cancelled in exchange for the excess of the per share consideration paid to stockholders in the transaction, minus the applicable exercise price.Subject to the terms and conditions of the applicable award agreement, awards granted to nonemployee directors will fully vest upon a change in control.Subject to the terms and conditions of the applicable award agreement, for awards granted to all other service providers, vesting of awards will depend on whether the awards are assumed, converted or replaced by the resulting entity.·For awards that are not assumed, converted or replaced, the awards will vest upon the change in control. For performance awards, the amount vesting will be based on the greater of (1) achievement of all performance goals at the “target” level or (2) the actual level of achievement of performance goals as of our fiscal quarter end preceding the change in control, and will be prorated based on the portion of the performance period that had been completed through the date of the change in control.·For awards that are assumed, converted or replaced by the resulting entity, no automatic vesting will occur upon the change in control. Instead, the awards, as adjusted in connection with the transaction, will continue to vest in accordance with their terms and conditions. In addition, the awards will vest if the award recipient has a separation from service within two years after a change in control other than for cause or by the award recipient for good reason. For performance awards, the amount vesting will be based on the greater of (1) achievement of all performance goals at the “target” level or (2) the actual level of achievement of performance goals as of fiscal quarter end preceding the change in control, and will be prorated based on the portion of the performance period that had been completed through the date of the separation from service.Term, Termination and Amendment of 2016 PlanUnless earlier terminated by our Board, our 2016 Plan will terminate, and no further awards may be granted, 10 years after the date on which it is approved by stockholders. Our Board may amend, suspend or terminate our 2016 Plan at any time, except that, if required by applicable law, regulation or stock exchange rule, stockholder approval will be required for any amendment. The amendment, suspension or termination of our 2016 Plan or the amendment of an outstanding award generally may not, without a participant’s consent, materially impair the participant’s rights under an outstanding award.Equity Grants for Fiscal Year 2016During our year ended December 31, 2016, we granted 1,780,052 shares of restricted common stock and 5,683,500 options to purchase shares of common stock to employees and directors. Also during the year ended December 31, 2016, our employees forfeited and we cancelled 335,000 stock options previously issued in connection with the termination of certain employees and directors. As a result, as of December 31, 2016, the Company had 1,068,305 restricted shares of common stock and 5,956,833 options to purchase shares of common stock outstanding to employees and directors. Options issued to employees and directors generally vest in equal installments over specified time periods during the service period or upon achievement of certain performance based operating thresholds.
reference.64Employment AgreementsMr. MirmanEffective as of March 30, 2015, we entered into an amended and restated employment agreement with Mr. Mirman, which replaced his prior employment agreement. The agreement had a three-year term and provided for a $100,000 cash bonus due upon signing, base compensation of $350,000 per year, and 200,000 stock options, where one-third of the options vested immediately and two-thirds were scheduled to vest in two annual installments on each of the next two anniversaries of the grant date. The agreement also provided for additional bonuses due based on our achievement of certain performance measures.On July 5, 2016, we entered into a new employment agreement with Mr. Mirman under which he will serve as our CEO. This agreement became effective June 24, 2016 upon the closing of our merger with Brushy. The initial term of the agreement is scheduled to end on December 31, 2017, and the agreement will renew automatically for additional one-year periods beginning on December 31, 2017, unless either party gives notice of non-renewal at least 180 days before the end of the then-current term. The agreement replaces in its entirety Mr. Mirman’s prior employment agreement with the Company.Mr. Mirman’s base salary (which will be reviewed by the Board for adjustments) is $350,000 for the first year of the agreement, $375,000 for the second year of the agreement, and $425,000 for the third year of the agreement. Mr. Mirman was entitled to a bonus under the agreement equal to $175,000, payable in cash on the first regular payroll date of the Company following June 24, 2016 (the closing date of the merger with Brushy). Mr. Mirman will also be eligible to receive a cash bonus equal to a percentage of his base salary (ranging from 0% to 400%) depending on the level of achievement of certain BOE per day, EBITDAX and cash on hand performance measures. Mr. Mirman will also be eligible to receive awards of equity and non-equity compensation and to participate in our annual and long-term incentive plans, in each case as determined by our Board in its discretion. On June 24, 2016, Mr. Mirman received a grant of 1,250,000 stock options under our 2016 Plan, with an exercise price of $1.34. This grant is scheduled to vest over two years, with 34% vesting on the grant date, 33% vesting on the first anniversary of the grant date and 33% vesting on the second anniversary of the grant date, subject to continued service through each vesting date.Under his employment agreement, Mr. Mirman will be entitled to a lump sum severance payment equal to 12 months of base salary and 12 months of COBRA premiums upon a termination by us without cause or a termination by him for good reason. Upon a termination by us without cause or a termination by Mr. Mirman for good reason within 12 months following a change in control, he will be entitled to a lump sum severance payment equal to 24 months of base salary and 24 months of COBRA premiums. Upon a termination due to disability, Mr. Mirman will be entitled to a lump sum severance payment equal to six months of COBRA premiums. All severance payments under Mr. Mirman’s employment agreement are subject to his execution and non-revocation of a release of claims against us. The severance payments are also subject to reduction in order to avoid an excise tax associated with Section 280G of the Internal Revenue Code, but only if that reduction would result in Mr. Mirman receiving a greater net after tax benefit as a result of the reduction.All payments to Mr. Mirman under his employment agreement will be subject to clawback in the event required by applicable law. Further, Mr. Mirman is subject to non-competition, non-solicitation, anti-raiding and confidentiality provisions under his employment agreement.Mr. OrmandOn July 5, 2016, we entered into an employment agreement with Ronald D. Ormand, effective as of July 11, 2016, under which he will serve as our Executive Chairman. The initial term of the agreement is scheduled to end on December 31, 2017, and the agreement will renew automatically for additional one-year periods beginning on December 31, 2017, unless either party gives notice of non-renewal at least 180 days before the end of the then-current term.65Mr. Ormand’s base salary (which will be reviewed by the Board for adjustments) is $300,000 for the first year of the agreement, $350,000 for the second year of the agreement, and $400,000 for the third year of the agreement. Mr. Ormand will be eligible to receive a cash bonus equal to a percentage of his base salary (ranging from 0% to 400%) depending on the level of achievement of certain BOE per day, EBITDAX and cash on hand performance measures. Mr. Ormand will also be eligible to receive awards of equity and non-equity compensation and to participate in our annual and long-term incentive plans, in each case as determined by our Board in its discretion. On July 7, 2016, Mr. Ormand received a grant of restricted stock under our 2016 Plan for 1.25 million shares of common stock. The restricted stock vests over two years, with 34% vesting on the date of the grant, 33% vesting on the first anniversary of the date of the grant and 33% vesting on the second anniversary of the date of the grant, subject to continued service through each vesting date.Under his employment agreement, Mr. Ormand will be entitled to a lump sum severance payment equal to 12 months of base salary and 12 months of COBRA premiums upon a termination by us without cause or a termination by him for good reason. Upon a termination by us without cause or a termination by Mr. Ormand for good reason within 12 months following a change in control, he will be entitled to a lump sum severance payment equal to 24 months of base salary and 24 months of COBRA premiums. Upon a termination due to disability, Mr. Ormand will be entitled to a lump sum severance payment equal to six months of COBRA premiums. All severance payments under Mr. Ormand’s employment agreement are subject to his execution and non-revocation of a release of claims against us. The severance payments are also subject to reduction in order to avoid an excise tax associated with Section 280G of the Internal Revenue Code, but only if that reduction would result in Mr. Ormand receiving a greater net after tax benefit as a result of the reduction.All payments to Mr. Ormand under his employment agreement will be subject to clawback in the event required by applicable law. Further, Mr. Ormand is subject to non-competition, non-solicitation, anti-raiding, and confidentiality provisions under his employment agreement.Ms. FuchsIn connection with the appointment of Ms. Fuchs as our General Counsel, we entered into an employment agreement with her dated March 16, 2015. The agreement provided, among other things, that Ms. Fuchs would receive an annual salary of $230,000. Additionally, as of the effective date of the agreement, Ms. Fuchs was granted (i) 5,000 shares of restricted stock and (ii) 30,000 stock options, which were scheduled to vest in equal installments on the first three anniversaries of the effective date of the agreement. Ms. Fuchs was also eligible receive a cash incentive bonus if we achieved certain production thresholds.On July 5, 2016, we entered into a new employment agreement with Ms. Fuchs under which she will continue to serve as our General Counsel. This agreement became effective June 24, 2016 upon the closing of our merger with Brushy. The initial term of the agreement is scheduled to end on December 31, 2017, and the agreement will renew automatically for additional one-year periods beginning on December 31, 2017, unless either party gives notice of non-renewal at least 180 days before the end of the then-current term. The agreement replaces in its entirety Ms. Fuchs’ prior employment agreement with us.Ms. Fuchs’ initial base salary under the agreement (which will be reviewed for adjustments) is $250,000. Ms. Fuchs was entitled to a bonus under the agreement equal to $112,500, payable in cash on the first regular payroll date of the Company following June 24, 2016 (the closing date of the merger with Brushy). Ms. Fuchs is also eligible to receive a cash bonus equal to a percentage of her base salary (ranging from 0% to 400%) depending on the level of achievement of certain BOE per day, EBITDAX and cash on hand performance measures. Ms. Fuchs is also eligible to receive awards of equity and non-equity compensation and to participate in our annual and long-term incentive plans, in each case as determined by our Board in its discretion. On June 24, 2016, Ms. Fuchs received a grant of 375,000 stock options under our 2016 Plan, with an exercise price of $1.34. This grant is scheduled to vest over two years, with 34% vesting on the grant date, 33% vesting on the first anniversary of the grant date and 33% vesting on the second anniversary of the grant date, subject to continued service through each vesting date.66Under her employment agreement, Ms. Fuchs’ will be entitled to a lump sum severance payment equal to six months of base salary and six months of COBRA premiums upon a termination by the Company without cause or a termination by her for good reason. Upon a termination by the Company without cause or a termination by Ms. Fuchs for good reason within 12 months following a change in control, she will be entitled to a lump sum severance payment equal to 24 months of base salary and 24 months of COBRA premiums. Upon a termination due to disability, Ms. Fuchs will be entitled to a lump sum severance payment equal to six months of COBRA premiums. All severance payments under Ms. Fuchs employment agreement are subject to her execution and non-revocation of a release of claims against the Company. The severance payments are also subject to reduction in order to avoid an excise tax associated with Section 280G of the Internal Revenue Code, but only if that reduction would result in Ms. Fuchs receiving a greater net after tax benefit as a result of the reduction.All payments to Ms. Fuchs under her employment agreement will be subject to clawback in the event required by applicable law. Further, Ms. Fuchs is subject to non-competition, non-solicitation, anti-raiding and confidentiality provisions under her employment agreement.Potential Payments Upon Termination or Change-In-ControlMr. MirmanUnder his employment agreement, Mr. Mirman will be entitled to a lump sum severance payment equal to 12 months of base salary and 12 months of COBRA premiums upon a termination by us without cause or a termination by him for good reason. Upon a termination by the Company without cause or a termination by Mr. Mirman for good reason within 12 months following a change in control, he will be entitled to a lump sum severance payment equal to 24 months of base salary and 24 months of COBRA premiums. Upon a termination due to disability, Mr. Mirman will be entitled to a lump sum severance payment equal to six months of COBRA premiums. All severance payments under Mr. Mirman’s employment agreement are subject to his execution and non-revocation of a release of claims against us. The severance payments are also subject to reduction in order to avoid an excise tax associated with Section 280G of the Internal Revenue Code, but only if that reduction would result in Mr. Mirman receiving a greater net after tax benefit as a result of the reduction. All payments to Mr. Mirman under his employment agreement will be subject to clawback in the event required by applicable law. Further, Mr. Mirman is subject to non-competition, non-solicitation, anti-raiding and confidentiality provisions under his employment agreement.Mr. OrmandUnder his employment agreement, Mr. Ormand will be entitled to a lump sum severance payment equal to 12 months of base salary and 12 months of COBRA premiums upon a termination by us without cause or a termination by him for good reason. Upon a termination by us without cause or a termination by Mr. Ormand for good reason within 12 months following a change in control, he will be entitled to a lump sum severance payment equal to 24 months of base salary and 24 months of COBRA premiums. Upon a termination due to disability, Mr. Ormand will be entitled to a lump sum severance payment equal to six months of COBRA premiums. All severance payments under Mr. Ormand’s employment agreement are subject to his execution and non-revocation of a release of claims against the Company. The severance payments are also subject to reduction in order to avoid an excise tax associated with Section 280G of the Internal Revenue Code, but only if that reduction would result in Mr. Ormand receiving a greater net after tax benefit as a result of the reduction. All payments to Mr. Ormand under his employment agreement will be subject to clawback in the event required by applicable law. Further, Mr. Ormand is subject to non-competition, non-solicitation, anti-raiding and confidentiality provisions under his employment agreement.Ms. FuchsUnder her employment agreement, Ms. Fuchs’ will be entitled to a lump sum severance payment equal to six months of base salary and six months of COBRA premiums upon a termination by us without cause or a termination by her for good reason. Upon a termination by us without cause or a termination by Ms. Fuchs for good reason within 12 months following a change in control, she will be entitled to a lump sum severance payment equal to 24 months of base salary and 24 months of COBRA premiums. Upon a termination due to disability, Ms. Fuchs will be entitled to a lump sum severance payment equal to six months of COBRA premiums. All severance payments under Ms. Fuchs employment agreement are subject to her execution and non-revocation of a release of claims against us. The severance payments are also subject to reduction in order to avoid an excise tax associated with Section 280G of the Internal Revenue Code, but only if that reduction would result in Ms. Fuchs receiving a greater net after tax benefit as a result of the reduction. All payments to Ms. Fuchs under her employment agreement will be subject to clawback in the event required by applicable law. Further, Ms. Fuchs is subject to non-competition, non-solicitation, anti-raiding and confidentiality provisions under her employment agreement.67Stock OptionsEach of Mr. Mirman, Mr. Ormand and Ms. Fuchs hold unvested options under our 2016 Plan, all of which become fully exercisable (1) immediately upon the officer’s separation from service other than for cause or for good reason, and (2) immediately prior to, and contingent upon, a change in control prior to the officer’s separation from service.Retirement and Other BenefitsAll employees, including our NEOs, may participate in our 401(k) retirement savings plan (“401(k) Plan”). Each employee may make before tax contributions in accordance with Internal Revenue Service limits. We provide this 401(k) Plan to help our employees save a portion of their cash compensation for retirement in a tax efficient manner. In prior years, we have made a matching contribution in an amount equal to 100% of the employee’s elective deferral contribution below 3% of the employee’s compensation and 50% of the employee’s elective deferral that exceeds 3% of the employee’s compensation but does not exceed 5% of the employee’s compensation.Compensation of Nonemployee DirectorsName Fees Earned
or Paid in
Cash
Compensation
($) Stock Awards
($)(1) Option
Awards
($)(2)
Compensation G. Tyler Runnels(3) ─ ─ ─ ─ ─ Nuno Brandolini(4) 72,500 135,000 ─ ─ 207,500 General Merrill McPeak(5) 85,000 135,000 ─ ─ 220,000 R. Glenn Dawson(6) 70,522 255,750 81,000 ─ 407,272 Peter Benz(7) 43,901 135,000 67,500 ─ 246,401 (1)Represents restricted stock awards. The grant date fair values for restricted stock awards were determined in accordance with FASB ASC Topic 718. The amounts reported reflect the accounting cost for the awards and do not correspond to the actual economic value that may be received for the awards.(2)Awards in this column are reported at grant date fair value in accordance with FASB ASC Topic 718. The amounts reported reflect the accounting cost for the options and do not correspond 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 in the notes to our consolidated financial statements included in this Annual Report on Form 10-K. As of December 31, 2016, our nonemployee directors held the following equity awards: Mr. Brandolini - 45,000 options, 50,000 restricted shares and 41,666 restricted stock units; General McPeak - 45,000 options, 33,333 restricted shares and 66,666 restricted stock units; Mr. Dawson - 45,000 options and 113,667 restricted shares; and Mr. Benz - 45,000 options and 33,333 restricted shares.(3)Mr. Runnels served as a director from November 21, 2014, through January 13, 2016.(4)Mr. Brandolini has served as a director since February 13, 2014.(5)General McPeak was appointed to the board on January 29, 2015.(6)Mr. Dawson was appointed to the Board on January 13, 2016.(7)Mr. Benz was appointed to the Board on June 23, 2016.68On April 16, 2015, our Board adopted an amended nonemployee director compensation program (the “Prior Program”). The Prior Program was comprised of the following components:·Initial Grant: Each nonemployee director would receive 100,000 restricted shares of common stock on the first anniversary of the date of the director’s appointment, which would vest in three equal installments over a three-year period, (subject to the continued service of the director and certain accelerated vesting provisions);·Annual Stock Award: Each nonemployee director would receive an annual stock award equal to $60,000 divided by the most recent per share closing price of the common stock prior to the date of each annual grant, payable on each anniversary of the date an independent director was initially appointed to our Board, and subject to certain accelerated vesting provisions;·Option Award: Each nonemployee director would receive a one-time initial grant of 25,000 stock options, which would vest immediately, and 20,000 options that would vest in equal installments over a three-year period beginning on the first anniversary of the grant date; and·Committee Fees: On a quarterly basis, beginning at the end of the first full quarter following the appointment of the nonemployee director to Chairman of the Board, Chairman of the Audit Committee or Chairman of the Compensation Committee, the director would receive $12,500, $6,250 and $6,250, respectively, in cash compensation, which at the election of the director would be payable in cash or stock (calculated by dividing the value of cash compensation (or a portion thereof), by the most recent per share closing price of the common stock prior to the date of the grant).Beginning January 1, 2017, our Board adopted an amended nonemployee director compensation program (the “New Program”). The New Program is substantially similar to the Prior Program. However, the New Program sets forth an annual equity date (which will be the first business day on or after January 31 of each year) pursuant to which each nonemployee director will receive an Annual Stock Award, subject to substantially the same terms and conditions set forth above. In addition, the New Program establishes annual limits on the number of shares subject to our equity compensation plan awards that may be granted during any calendar year to any director, which, taken together with any cash fees paid to the director during the year, cannot exceed $500,000 in total value.Indemnification of Directors and OfficersPursuant to our certificate of incorporation we provide indemnification of our directors and officers to the fullest extent permitted under Nevada law. We believe that this indemnification is necessary to attract and retain qualified directors and officers.69Securities Authorized for Issuance under Equity Compensation PlansThe following table represents the securities authorized for issuance under our equity compensation plans at December 31, 2016.Plan category Number of
securities to
be issued
upon exercise
of outstanding
options,
warrants and
rights (1) Weighted-average
exercise price of
outstanding
options, warrants
and rights (2) Number of
securities
remaining
available for
future issuance
under equity
compensation
plans Equity compensation plans approved by security holders 5,354,794 1.74 3,574,742 Equity compensation plans not approved by security holders - - Total 5,354,794 1.74 3,574,742 (1)Includes stock options and restricted stock units outstanding under our 2016 Plan and our 2012 EIP as of December 31, 2016. Does not include shares of restricted stock issued pursuant to our 2016 Plan or our 2012 EIP.(2)Represents the weighted average exercise price of outstanding options issued pursuant to our 2016 Plan and our 2012 EIP as of December 31, 2016.Other Equity CompensationWe have entered into various services agreements for which compensation has been paid with equity securities, including (i) a consulting agreement with Bristol Capital LLC pursuant to which we issued to Bristol a five year warrant to purchase up to 641,026 shares of common stock at an exercise price of $3.12 per share (or, in the alternative, 641,026 options, but in no case both), (ii) consulting agreements with Market Development Consulting Group, Inc. pursuant to which we issued five year warrants to purchase up to an aggregate of 500,000 shares of common stock ,with an exercise price of $2.33 for the warrant to purchase 250,000 shares of common stock and an exercise price of $2.00 for the warrant to purchase 250,000 shares of common stock; (iii) an investment banking agreement with TRW pursuant to which we issued 900,000 warrants at an exercise price of $4.25 per share; and (iv) various agreements pursuant to which issued an aggregate amount of 150,000 and 300,000 five year warrants to purchase shares of common stock at an exercise price of $2.50 and $2.00, respectively. With respect to the warrants awarded to Bristol Capital, we recorded the warrants as a derivative due to the price reset provision encompassed in the warrants.70SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENTThe following table sets forth certain information with respect to beneficial ownership of our common stock as of March 1, 2017, by each of our executive officers and directors and each person known to be the beneficial owner of 5% or more of the outstanding common stock.This table is based upon the total number of shares outstanding as of March 1, 2017 of 24,387,793. Unless otherwise indicated, the persons and entities named in the table have sole voting and sole investment power with respect to the shares set forth opposite the stockholder’s name. Beneficial ownership is determined in accordance with Rule 13d-3 under the Securities Exchange Act of 1934, as amended. In computing the number of shares beneficially owned by a person or a group and the percentage ownership of that person or group, shares of our common stock subject to options or warrants currently exercisable or exercisable within 60 days after March 1, 2017 are deemed outstanding by such person or group, but are not deemed outstanding for the purpose of computing the percentage ownership of any other person. All share amounts that appear in this report have been adjusted to reflect a 1-for-10 reverse stock split of our outstanding common stock effected on June 23, 2016. Unless otherwise indicated, the address of each stockholder listed in the table is c/o Lilis Energy, Inc., 300 E. Sonterra Blvd. Ste. 1220, San Antonio, Texas 78258 Series B Preferred Stock Common Stock Name and Address of Beneficial
Owner Shared
Beneficially
Owned (1) % of
Class Lilis
common
stock
Held
Directly Lilis
common
stock
Acquirable
Within 60
Days(2) Total
Beneficially
Owned(2) Percent of
Class
Beneficially
Owned(2) Directors and Named Executive Officers Abraham Mirman, Chief Executive Officer and Director 1,650 10.59 % 762,906 (3) 643,334 (4) 1,406,240 5.6 %(5) Ronald D. Ormand, Executive Chairman of the Board 1,000 6.42 % 2,495,752 (6) 115,001 (7) 2,610,753 10.7 %(8) Joseph Daches, Chief Financial Officer — — 45,000 250,000 (9) 295,000 1.2 % Ariella Fuchs, Executive Vice President, General Counsel and Secretary — — — 250,000 (10) 250,000 1.0 % Peter Benz, Director — — 75,000 25,000 (11) 100,000 * Nuno Brandolini, Director — — 402,060 159,574 (12) 561,634 2.3 % R. Glenn Dawson, Director — — 440,861 108,486 (13) 549,347 2.2 % General Merrill McPeak, Director — — 406,207 143,521 (14) 549,728 2.2 % Directors and Officers as a Group (10 persons) 2,650 17.0 % 4,627,786 1,694,916 (15) 6,322,702 24.2 %(16) 5% Stockholders Bryan Ezralow, 23622 Calabasas Road, Suite 200, Calabasas, CA 913012 900 5.8 % 1,564,969 (17) — (18) 1,564,969 6.42 % Marc Ezralow, 23622 Calabasas Road, Suite 200, Calabasas, CA 913012 750 4.8 % 1,221,566 (19) — (20) 1,221,566 5.01 % *Represents beneficial ownership of less than 1% of the outstanding shares of common stock.(1)Applicable percentages are based on 15,588 shares of Series B Preferred Stock outstanding as of the date March 1, 2017. Series B Preferred Stock is non-voting, and currently, no holder of shares of Series B Preferred Stock may convert such shares if, upon conversion, such holder would beneficially own more than 4.99% of the Company’s then-outstanding stock. Accordingly, holders of 5% or more of shares of Series B Preferred Stock have been excluded from this beneficial ownership table.
relating to the Company’s 2019 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.71(2)The terms of the Series B Preferred Stock, and each of the Company’s outstanding warrants, the “Blocker Securities”) contain a provision prohibiting the conversion of such Series B Preferred Stock, and the exercise of warrants into common stock of the Company if, upon such conversion or exercise, as applicable, the holder thereof would beneficially own more than a certain percentage of the Company’s then outstanding common stock (the “Blocker Limitation”). This percentage limitation is 4.99%, except that upon 61 days prior notice to the Company, a holder of Series B Preferred Stock may increase the percentage limitation with respect to the Series B Preferred up to a maximum of 9.99%. However, the foregoing restrictions do not prevent such holder from converting or exercising, as applicable, some of its holdings, selling those shares, and then converting or exercising, as applicable, more of its holdings, while still staying below the respective percentage limitation. As a result, the holder could sell more than any applicable ownership limitation while never actually holding more shares than the applicable limitations allow. Accordingly, the share numbers in the above table represent ownership without regard to the beneficial ownership limitations described in this footnote. While the ownership percentages are also given without regard to this beneficial ownership limitation, specific footnotes indicate what the effect of each ownership limitation would be as of March 1, 2017.(3)Consists of: (i) 11,087 shares of common stock held by The Bralina Group, LLC; and (ii) 751,819 shares of common stock held directly by Mr. Mirman. Mr. Mirman has shared voting and dispositive power over the securities held by The Bralina Group, LLC with Susan Mirman.(4)Represents shares of common stock subject to options exercisable within 60 days.In addition, Mr. Mirman beneficially owns an aggregate of 2,566,274 additional shares of common stock acquirable within 60 days, each of which is subject to a Blocker Limitation. However, Mr. Mirman’s percentage ownership is currently in excess of such Blocker Limitations, and as a result, such Blocker Securities have been excluded from the table. These Blocker Securities consist of the following: (i) 1,500,000 shares of common stock issuable upon conversion of shares of Series B Preferred held by the Bralina Group; (ii) 305,187 shares of common stock issuable upon exercise of warrants held by the Bralina Group and (iii) 761,087 shares of common stock issuable upon exercise of warrants held directly by Mr. Mirman.(5)Including the Blocker Securities, and ignoring the Blocker Limitation, Mr. Mirman beneficially owns a total 3,972,514 shares of common stock, which represents 14.4% of our currently issued and outstanding common stock.(6)Consists of: (i) 1,259,388 shares of common stock held directly by Mr. Ormand; (ii) 100,000 shares of common stock held by Perugia Investments L.P. (“Perugia”); and (iii) 1,136,364 shares of common stock held by The Bruin Trust, an irrevocable trust managed by Jerry Ormand, Mr. Ormand’s brother, as trustee and whose beneficiaries include the adult children of Mr. Ormand. Mr. Ormand is the manager of Perugia and has sole voting and dispositive power over the securities held by Perugia.(7)Represents shares of common stock subject to options exercisable within 60 days.In addition, Mr. Ormand beneficially owns an aggregate of 1,874,011 additional shares of common stock acquirable within 60 days, each of which is subject to a Blocker Limitation. However, Mr. Ormand’s percentage ownership is currently in excess of such Blocker Limitations, and as a result, such Blocker Securities have been excluded from the table. These Blocker Securities consist of the following: (i) 464,920 shares of common stock issuable upon exercise of warrants held by Perugia; (ii) 500,000 shares of common stock issuable upon exercise of warrants held by The Bruin Trust; and (iii) 909,091 shares of common stock issuable upon conversion of shares of Series B Preferred Stock held by Perugia.(8)Including the Blocker Securities, and ignoring the Blocker Limitation, Mr. Ormand beneficially owns a total 4,484,764 shares of common stock, which represents 17% of our currently issued and outstanding common stock.(9)Represents shares of common stock subject to options exercisable within 60 days.72(10) Represents shares of common stock subject to options exercisable within 60 days.(11)Represents shares of common stock subject to options exercisable within 60 days.(12)Consists of: (i) 45,000 shares of common stock subject to options exercisable within 60 days; and (ii) 114,574 shares of common stock issuable upon exercise of warrants. The effect of any Blocker Limitation with respect to the securities described here has been excluded, as Mr. Brandolini is below the threshold of any such limitation.(13)Consists of: (i) 31,667 shares of common stock subject to options exercisable within 60 days; and (ii) 76,819 shares of common stock issuable upon exercise of warrants. The effect of any Blocker Limitation with respect to the securities described here has been excluded, as Mr. Dawson is below the threshold of any such limitation.(14)Consists of: (i) 38,333 shares of common stock subject to options exercisable within 60 days; (ii) 105,188 shares of common stock issuable upon exercise of warrants. The effect of any Blocker Limitation with respect to the securities described here has been excluded, as General McPeak is below the threshold of any such limitation.(15)As indicated in the above footnotes, this amount excludes an aggregate of 4,440,285 additional shares of common stock acquirable within 60 days, which are subject to Blocker Limitations.(16)Including the Blocker Securities, and ignoring the Blocker Limitation, the directors and officers as a group beneficially own a total of 10,762,987 shares of common stock, which represents 37.34% of our currently issued and outstanding common stock.(17)Based solely on a Schedule 13G filed by Bryan Ezralow on February 14, 2017. Collectively, the shares of Common Stock reported herein in which Bryan Ezralow has shared voting and dispositive power over such shares is an aggregate of 1,011,451 shares. Such shares are held directly by (a) the Ezralow Family Trust u/t/d 12/9/1980 (the “Family Trust”) in the amount of 36,723 shares, where Bryan Ezralow as a co-trustee of the Family Trust shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; (b) the Ezralow Marital Trust u/t/d 1/12/2002 (the “Marital Trust”) in the amount of 42,583 shares, where Bryan Ezralow as a co-trustee of the Marital Trust shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; (c) Elevado Investment Company, LLC, a Delaware limited liability company (“Elevado Investment”), in the amount of 140,821 shares, where Bryan Ezralow as a co-trustee and manager, respectively, of the two trusts and limited liability company that comprise the managing members of Elevado Investment, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; (d) EMSE LLC (“EMSE”), a Delaware limited liability company, in the amount of 81,949 shares, where Bryan Ezralow, as a manager of EMSE, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; (e) EZ Colony Partners, LLC, a Delaware limited liability company (“EZ Colony”), in the amount of 709,372 shares, where Bryan Ezralow as the sole trustee of one of the trusts that is a manager of EZ Colony, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; and (f) EZ MM&B Holdings, LLC, a Delaware limited liability company (“EZ MM&B”), in the amount of 3 shares, where Bryan Ezralow as the sole trustee of one of the trusts that is a manager of EZ MM&B, and as a co-trustee and manager, respectively, of the two trusts and limited liability company that comprise the managing members of one of the other managers of EZ MM&B, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares.Collectively, the shares of Common Stock reported herein in which Bryan Ezralow has sole voting and dispositive power over such shares are 553,518 shares. Such shares are held directly by (a) the Bryan Ezralow 1994 Trust u/t/d/ 12/22/1994, Bryan Ezralow, Trustee (the “Bryan Trust”) in the amount of 518,669 shares, where Bryan Ezralow as sole trustee of the Bryan Trust has sole voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; and (b) the Marc Ezralow Irrevocable Trust u/t/d 6/1/2004 (the “Irrevocable Trust”) in the amount of 34,849 shares, where Bryan Ezralow as sole trustee of the Irrevocable Trust has sole voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares.73(18)In addition, Bryan Ezralow beneficially owns an aggregate of 2,137,598 additional shares of common stock acquirable within 60 days, each of which is subject to a Blocker Limitation. However, the percentage ownership by Bryan Ezralow is currently in excess of such Blocker Limitations, and as a result, such Blocker Securities have been excluded from the table. These Blocker Securities consist of the following: (A) (i) 272,728 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 529,091 shares of common stock issuable upon the exercise of warrants, each held by the Bryan Trust; (B) (i) 45,455 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 68,546 shares of common stock issuable upon the exercise of warrants, each held by the Irrevocable Trust; (C) (i) 136,364 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 200,371 shares of common stock issuable upon the exercise of warrants, each held by Elevado; (D) (i) 90,910 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 75,550 shares of common stock issuable upon the exercise of warrants, each held by EMSE; (E) (i) 181,819 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 343,168 shares of common stock issuable upon the exercise of warrants, each held by EZ Colony; (F) (i) 45,455 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 53,234 shares of common stock issuable upon the exercise of warrants, each held by the Marital Trust; and (H) (i) 45,455 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 49,452 shares of common stock issuable upon the exercise of warrants, held by the Family Trust.(19)Based solely on a Schedule 13G filed by Marc Ezralow on February 14, 2017. Collectively, the shares of Common Stock reported herein in which Marc Ezralow has shared voting and dispositive power over such shares are an aggregate of 1,011,451 shares. Such shares are held directly by (a) the Ezralow Family Trust u/t/d 12/9/1980 (the “Family Trust”) in the amount of 36,723 shares, where Marc Ezralow, as a co-trustee of the Family Trust, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; (b) the Ezralow Marital Trust u/t/d 1/12/2002 (the “Marital Trust”) in the amount of 42,583 shares, where Marc Ezralow, as a co-trustee of the Marital Trust, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; (c) Elevado Investment Company, LLC, a Delaware limited liability company (“Elevado Investment”), in the amount of 140,821 shares, where Marc Ezralow as a co-trustee and manager, respectively, of the two trusts and limited liability company that comprise the managing members of Elevado Investment, shares voting and dispositive power over such shares, and thus, be deemed to beneficially own such shares; (d) EMSE LLC (“EMSE”), a Delaware limited liability company, in the amount of 81,949 shares, where Marc Ezralow, as a manager of EMSE shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; (e) EZ Colony Partners, LLC, a Delaware limited liability company (“EZ Colony”), in the amount of 709,372 shares, where Marc Ezralow as the sole trustee of one of the trusts that is a manager of EZ Colony, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; and (f) EZ MM&B Holdings, LLC, a Delaware limited liability company (“EZ MM&B”) in the amount of 3 shares, where Marc Ezralow as the sole trustee of one of the trusts that is a manager of EZ MM&B, and as a co-trustee and manager, respectively, of the two trusts and limited liability company that comprise the managing members of one of the other managers of EZ MM&B, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares.Collectively, the shares of Common Stock reported herein in which Marc Ezralow has sole voting and dispositive power over said Common Stock are 210,115 shares. Such shares are held directly by (a) the Marc Ezralow 1997 Trust u/t/d/ 11/26/1997, Marc Ezralow, Trustee (the “Marc Trust”) in the amount of 175,266 shares, where Marc Ezralow as sole trustee of the Marc Trust has sole voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; and (b) the SPA Trust u/t/d 9/13/2004 (the “SPA Trust”), in the amount of 34,849 shares, where Marc Ezralow as sole trustee of the SPA Trust has sole voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares.(20)In addition, Marc Ezralow beneficially owns an aggregate of 1,769,416 additional shares of common stock acquirable within 60 days, each of which is subject to a Blocker Limitation. However, the percentage ownership by Marc Ezralow is currently in excess of such Blocker Limitations, and as a result, such Blocker Securities have been excluded from the table. These Blocker Securities consist of the following: (A) (i) 45,455 shares of common stock issuable upon conversion of shares of Series B Preferred Stock and (ii) 68,546 shares of common stock issuable upon exercise of warrants, each held the SPA Trust; (B) (i) 136,364 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 297,273 shares of common stock issuable upon exercise of warrants, each held by the 1997 Trust; (C) (i) 136,364 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 200,371 shares of common stock issuable upon the exercise of warrants, each held by Elevado; (D) (i) 90,910 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 75,550 shares of common stock issuable upon the exercise of warrants, each held by EMSE; (E) (i) 181,819 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 343,168 shares of common stock issuable upon the exercise of warrants, each held by EZ Colony; (F) (i) 45,455 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 53,234 shares of common stock issuable upon the exercise of warrants, each held by the Marital Trust; and (H) (i) 45,455 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 49,452 shares of common stock issuable upon the exercise of warrants, held by the Family Trust.To Lilis’s knowledge, except as noted above, no person or entity is the beneficial owner of 5% or more of Lilis’s common stock.74Item 13.Related Transactions, and Director IndependenceParty Transactions,We describe below transactions and seriesDirector Independencesimilar transactions, since January 1, 2016, to which we were a party, in which:·The amounts involved exceeded or will exceed the lesser of $120,000 or one percent (1%) of our average total assets at year-end for the last two completed fiscal years; and·Any of our directors, executive officers, or holders of more than 5% of our capital stock, or any member of the immediate family of, or person sharing the household with, any of the foregoing persons, who had or will have a direct or indirect material interest.All share and per share amounts applicable to our common stock from transactions that occurred prior to the June 23, 2016 reverse split in the following summaries of related party transactions have not been adjusted to reflect the 1-for-10 reverse split of our issued and outstanding common stock, unless specifically described below.Series B Preferred Stock Private PlacementOn June 15, 2016, we entered into the Series B Purchase Agreement with certain institutional and accredited investors (the “Purchasers”) in connection with the Series B preferred stock offering. For more information on the Series B preferred stock offering see Note 13-Shareholders Equity.On June 6, 2016, as subsequently amended, we entered into a Transaction Fee Agreement with TRW, a more than 5% shareholder of our company during the year ended December 31, 2016, in connection with the Series B preferred stock offering to act as co-broker dealers along with KES7, and as administrative agent. TRW received a cash fee of $500,000 and broker warrants to purchase up to 452,724 shares of common stock, at an exercise price of $1.30, exercisable on or after September 17, 2016, for a period of two years. Of the cash fee paid to TRW, $150,000 was reinvested into the Series B preferred stock offering in exchange for 150 shares of Series B preferred stock and the related warrants to purchase 68,182 shares of common stock at an exercise price of $2.50. These fees were recorded as a reduction to equity.Certain other Purchasers in the Series B preferred stock offering include certain of our related parties, such as Abraham Mirman, our Chief Executive Officer and a director, through the Bralina Group, LLC for which Mr. Mirman holds shared voting and dispositive power ($1.65 million); Ronald D. Ormand, the Chairman of our Board of Directors through Perugia Investments LP for which Mr. Ormand holds sole voting and dispositive power ($1.0 million), Kevin Nanke, the Company’s former Executive Vice President and Chief Financial Officer during the year ended December 31, 2016, through KKN Holdings LLC, for which Mr. Nanke holds sole voting and dispositive power ($200,000), R. Glenn Dawson, a director of our company ($125,000), Pierre Caland through Wallington Investment Holdings, Ltd. a more than 5% shareholder of our company ($250,000) during the year ended December 31, 2016 and Bryan Ezralow and Marc Ezralow through various entities beneficially owned by them ($1.3 million).Credit and Guarantee Agreement and Warrant RepriceOn September 29, 2016, we entered into the Credit Agreement. For more information about the Credit Agreement see Management’s Discussion and Analysis—Credit Agreement and Warrant Reprice.Certain parties to the Credit Agreement included certain of our related parties such as TRW, acting as collateral agent, and Bryan Ezralow, Marc Ezralow and Marshall Ezralow through certain of their investment entities ($2.8 million).Debenture Conversion AgreementOn December 29, 2015, we entered into the Debenture Conversion Agreement with all of the remaining holders of the Debentures. For more information about the Debentures see Management’s Discussion and Analysis—Debentures.Certain parties to the Debenture Conversion Agreement included certain of our related parties at that time, such as the Steven B. Dunn and Laura Dunn Revocable Trust dated 10/28/10, of which its respective Debenture amount converted was approximately $1.02 million, Bryan Ezralow through EZ Colony Partners, LLC of which his respective Debenture amount converted was approximately $1.54 million and Pierre Caland through Wallington Investment Holdings, Ltd., of which its respective Debenture amount converted was approximately $2.09 million. Steven B. Dunn and Laura Dunn Revocable Trust dated October 28, 2010 who held more than 5% of our Common Stock during the year ended December 31, 2016.75Series A Preferred StockOn May 30, 2014, we entered into a securities purchase agreement with accredited investors, pursuant to which it issued an aggregate of $7.5 million in Series A preferred stock with a conversion price of $24.10 and warrants to purchase up to 155,602 shares of common stock.On June 23, 2016, after the receipt of requisite stockholder approval and in connection with the consummation of the Merger, all outstanding shares of Series A preferred stock were converted into common stock at a reduced conversion price of $5.00 a share, resulting in the issuance of 1,500,000 shares of common stock. In exchange for the reduction in conversion price from $24.10 per share to $5.00 per share, all accrued but unpaid dividends were forfeited.Several of our officers, directors and affiliates were investors in the Series A preferred stock and converted their shares at $5.00 including Abraham Mirman ($250,000), Ronald D. Ormand (through Perugia Investments ($500,000), Nuno Brandolini ($100,000), General Merrill McPeak ($250,000), TRW ($779,000) and Pierre Caland through Wallington Investment Holdings, Ltd. ($125,000).Convertible NotesIn a series of transactions from December 29, 2015 to May 6, 2016, we issued an aggregate of approximately $5.8 million in Convertible Notes maturing on June 30, 2016 and April 1, 2017 at a conversion price of $5.00 and warrants to purchase an aggregate of approximately 2.3 million shares of common stock with an exercise price of $2.50 for warrants issued between December 2015 and March 2016 and $0.10 for the warrants issued in May 2016. The purchasers include certain of our related parties, including Abraham Mirman, our Chief Executive Officer and director of our company ($750,000), the Bruin Trust (the “Bruin Trust”), an irrevocable trust managed by an independent trustee and whose beneficiaries include the adult children of Ronald D. Ormand, Chairman of our Board of Directors ($1.15 million), General Merrill McPeak, a director of our company ($250,000), Nuno Brandolini, a director of our company ($250,000), Glenn Dawson, a director of our company ($50,000), Kevin Nanke, the Company’s former Executive Vice President and Chief Financial Officer during the year ended December 31, 2016 ($100,000, which was reinvested instead of a cash bonus payment due to Mr. Nanke pursuant to his prior executive employment agreement), Pierre Caland through Wallington Investment Holdings, Ltd. ($300,000), who held more than 5% of our common stock during the year ended December 31, 2016, Bryan and Marc Ezralow, through various entities who held more than 5% of our common stock during the year ended December 31, 2016 ($905,381) and TRW ($400,000).Subsequently, warrants to purchase up to 620,000 shares of common stock issued in connection with the Convertible Notes between December 2015 and March 2016 were amended and restated to reduce the exercise price to $0.10 in exchange for additional consideration given to us in the form of participation in the May Convertible Notes offering. Of those warrants, a total of 80,000 warrants were exercised. Additionally, during the three months ended June 30, 2016, in exchange for several offers to immediately exercise a portion of each investor’s outstanding warrants issued between 2013 and 2014, we reduced the exercise price on warrants to purchase a total of 416,454 shares of common stock ranging from $42.50 to $25.00 per share to $0.10 per share, of which a total of 315,990 were subsequently exercised, resulting in the issuance of an aggregate amount of 300,706 shares of common stock due to certain cashless exercises. TRW net exercised warrants to purchase 80,000 shares of common stock at a reset exercise price of $0.10, resulting in the issuance of 75,820 shares.TRW also received an advisory fee on the Convertible Notes in the amount of $350,000, which was subsequently reinvested in full into the Series B Preferred Offering for 350 shares of Series B Preferred Stock and related warrants to purchase up to 159,091 shares of common stock.On June 23, 2016, we entered into the Note Conversion Agreement. Certain parties to the Note Conversion Agreement include certain of our related parties, such as each officer and director who invested in the Notes, each of whom converted their outstanding amounts in full. In addition, Pierre Caland, through Wallington Investments, Ltd., was signatory to the Note Conversion Agreement and converted its outstanding amounts in full.On August 3, 2016, we entered into the first amendment to the Notes with the remaining holders of approximately $1.8 million of our Notes. Each of Bryan Ezralow and Marc Ezralow through various entities and TRW was a party to the first amendment. For a detailed description of the first amendment to the Convertible Notes see—Note 8—Long Term Debt.76SOSIn connection with the Merger, SOS, Brushy’s former subordinated lender, and a more than 5% shareholder of our Company during the year ended December 31, 2016, agreed to extinguish approximately $20.5 million of its outstanding debt in exchange for Brushy’s divestiture of its properties to SOS in the Giddings Field, the SOS Note and the SOS Warrant, which was completed on June 23, 2016.March 2017 Private PlacementOn February 28, 2017, we entered into a Securities Purchase Agreement in connection with the March 2017 Private Placement. For more information on the March 2017 Private Placement see Management’s Discussion and Analysis—Liquidity and Capital Resources—Subsequent Events—March 2017 Private Placement.The subscribers include certain of our related parties, including Bryan and Marc Ezralow through various entities ($2.6 million) and TRW, described further below.G. Tyler Runnels and T.R. WinstonWe have participated in several transactions with TRW, of which G. Tyler Runnels, a former member of our Board of Directors, is chairman and majority owner. During the year ended December 31, 2016, Mr. Runnels beneficially held more than 5% of our common stock, including the holdings of TRW and his personal holdings, and has personally participated in certain transactions with us.On January 31, 2014, we entered into the Debenture Conversion Agreement with all of the holders of the Debentures, including TRW and Mr. Runnels’ personal trust. On June 23, 2016, all of the outstanding Debentures were converted at $5.00. See “—Debenture Conversion Agreement.”On May 3, 2016 through May 5, 2016, in exchange for several offers to immediately exercise outstanding warrants issued between 2013 and 2014, we reduced the exercise price on warrants to purchase a total of 265,803 shares of common stock from a range of $42.50 to $25.00 per share to $0.10 per share which resulted in the issuance of a total of 250,520 shares of common stock. TRW received a total of 758,203 shares of common stock in this transaction.On June 6, 2016, as subsequently amended, we entered into a Transaction Fee Agreement with TRW in connection with the Series B preferred stock offering. See “—Series B Private Placement.”On November 1, 2016, we entered into a sublease agreement with TRW to sublease office space in New York, for which we pay $10,000 per month on a month-to-month basis.On February 28, 2017, we entered into a Subscription Agreement in connection with the March 2017 Private Placement, for which TRW acted as placement agent and received a fee of $459,060. Additionally, TRW was a participant in the offering for an aggregate amount of $750,000.Ronald D. OrmandOn March 20, 2014, we entered into an Engagement Agreement (the “Engagement Agreement”) with MLV & Co. LLC (“MLV”), which is now owned by FBR & Co., after it acquired MLV in September of 2015, pursuant to which MLV acted as our exclusive financial advisor. Ronald D. Ormand, a member of our Board of Directors since February 2015 and the current Executive Chairman of our Board of Directors, was previously the Managing Director and Head of theLilis Energy, Investment Banking Group at MLV. The Engagement Agreement provided for a fee of $25,000 to be paid monthly to MLV, subject to certain adjustments and other specific fee arrangements in connection with the nature of financial services being provided. We expensed $75,000 and $175,000 for the three and six months ended June 30, 2015, respectively. On May 27, 2015, MLV agreed to take $150,000 of its accrued fees in our common stock and was issued 75,000 shares in lieu of payment. The closing share price on May 27, 2015 was $1.56. The term of Engagement Agreement expired on October 31, 2015. On November 8, 2016, we paid FBR $100,000 as final settlement of outstanding fees owed under the Engagement Agreement.Additionally, MLV had been involved in certain initial discussionsInc., relating to the Merger forCompany’s 2019 Annual Meeting of Stockholders, which it did not receive a fee.
will be filed with the Securities and Exchange Commission and is incorporated herein by reference.77Agreements with Former Executive OfficersKevin Nanke, Former Executive Vice President and Chief Financial OfficerOn February 13, 2017, we entered into a Separation and Release of Claims Agreement (the “Separation Agreement”) with Mr. Nanke, providing for his separation as an officer of our company, effective January 23, 2017. Pursuant to the Separation Agreement and the terms of his employment agreement, Mr. Nanke will receive (1) a lump sum severance payment in an amount equal to 24 months of base salary in effect immediately prior to the date of termination, (2) a lump sum payment equal to 24 months of COBRA premiums based on the terms of our group health plan and Mr. Nanke’s coverage under such plan as of the date of termination, and (3) a lump sum bonus payment of $175,000. For consideration of the separation benefits listed above, Mr. Nanke (1) provided a general release of claims against us, our affiliates, and related parties, (2) to the extent reasonable, shall continue to provide full and continued cooperation in good faith with our company, our subsidiaries, and affiliates for 24 months following the date of termination in connection with certain matters relating to our company, and (3) agreed to be bound by confidentiality commitments to our company.Additionally, pursuant to Mr. Nanke’s former employment agreement with us, dated as of March 18, 2016, he was entitled to receive a performance bonus of $100,000 if we were to achieve certain compliance goals set forth therein. In May 2016, our Board of Directors approved the reinvestment by Mr. Nanke of his performance bonus in the amount of $100,000 into the May Offering, pursuant to the same terms as the May Offering.Edward Shaw, Former Executive Vice President and Chief Operating Officer of the CompanyOn February 13, 2017, we entered into a Separation and Release of Claims Agreement (the “Settlement Agreement”) with Mr. Shaw, providing for his separation as an officer of our company, effective January 24, 2017 (the “Separation Date”). Pursuant to the Settlement Agreement, Mr. Shaw received (1) a lump sum severance payment in an amount equal to 3 months of base salary in effect immediately prior to the date of termination, (2) a lump sum payment equal to 3 months of COBRA premiums based on the terms of our group health plan and Mr. Shaw’s coverage under such plan as of the date of termination, and (3) a period of three months from the separation date to exercise all vested options. For consideration of the separation benefits listed above, Mr. Shaw (1) provided a general release of claims against us, our affiliates, and related parties, (2) to the extent reasonable, shall continue to provide full and continued cooperation in good faith with our company, our subsidiaries, and affiliates for 24 months following the date of termination in connection with certain matters relating to our company, and (3) agreed to be bound by confidentiality commitments to our company.For additional information on the above-mentioned agreements, see “Employment Agreements and Other Arrangements” above.Compensation of DirectorsSee “Executive Compensation—Compensation of Nonemployee Directors” above.Conflict of Interest PolicyOur Board of Directors has recognized that transactions between us and certain related persons present a heightened risk of conflicts of interest. We have a corporate conflict of interest policy that prohibits conflicts of interests unless approved by our Board of Directors. Our Board of Directors has established a course of conduct whereby it considers in each case, whether the proposed transaction is on terms as favorable or more favorable to us than would be available from a non-related party. Our Board of Directors also looks at whether the transaction is fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us. Each of the related party transactions described above was presented to our Board of Directors for consideration and each of these transactions was unanimously approved by our Board of Directors after reviewing the criteria set forth in the preceding two sentences.Director IndependenceSee “Directors, Executive Officers and Corporate Governance—Affirmative Determinations Regarding Director Independence and Other Matters” above.following table sets forth fees billed by our principal accounting firm Marcum LLP for the years ended December 31, 2016 and 2015:78 Year Ended December 31, Fee Category 2016 2015 (In thousands) Audit Fees $ 358 $ 264 Audit-Related Fees 341 5 Tax Fees - - All Other Fees - - Total Fees $ 699 $ 269 Audit Fees consistBureau of Land Management of the aggregate fees for professional services rendered for the audit of our annual financial statements and the reviewsUnited States Department of the financial statementsInterior.Quarterly Reportsmulti-year drilling activities on Forms 10-Qexisting acreage. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and fornatural gas prices, costs, drilling results and other factors.other serviceswell that were normally provided by our auditorsis not a development well, an extension well, a service well or a stratigraphic well.connection with our statutory and regulatory filingswhich we own a working interest, reported at the 100% or engagements.Audit-Related Fees consist8/8ths level. For example, the number of gross wells is the total number of wells in which we own a working interest.aggregate fees billedbusiness relationship between an energy company and a landowner or reasonablymineral rights holder on a particular tract of land.billed for professional services rendered for assurancerecovered (i) through existing wells with existing equipment and related services that were reasonably relatedoperating methods or in which the cost of the required equipment is relatively minor compared to the performancecost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the audit or reviewreserves estimate if the extraction is by means not involving a well.our financial statementsoil and were not otherwise included in Audit Fees. Majoritynatural gas, which, by analysis of these services were relatedgeoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and government regulations - prior to the Brushy merger.Tax Fees consisttime at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.aggregate fees billed for professional services rendered for tax consulting. Included inreservoir, such Tax Fees were fees for consultancy, review,as gas injection or water flooding, to produce residual oil and advice related to ournatural gas remaining after the primary recovery phase.provisionexpenses, discounted at 10% per annum to reflect timing of future cash flows and using the appropriate presentationsame pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.our financial statementswhich wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas regardless of whether such acreage contains proved reserves.income tax related accounts.All Other Fees consist of the aggregate fees billed for productsproduction revenue, subject to all royalties, overriding royalties and services provided by our auditorsother burdens, all development costs, and not otherwise includedall risks in Audit Fees, Audit-Related Fees or Tax Fees.Audit Committee Pre-Approval PolicyOur independent registered public accounting firm may not be engaged to provide non-audit services that are prohibited by law or regulation to be provided by it, nor may our independent registered public accounting firm be engaged to provide any other non-audit service unless it is determined that the engagement of the principal accountant provides a business benefit resulting from its inherent knowledge of our company while not impairing its independence. Our audit committee must pre-approve permissible non-audit services. During the year ended December 31, 2016, we had no non-audit services provided by our independent registered public accounting firm.79a)Index to Financial StatementsReport of Independent Registered Public Accounting FirmF-1Consolidated Balance Sheetsa.The following documents are filed as part of December 31, 2016 and 2015F-2Consolidated Statements of Operations for the years ended December 31, 2016 and 2015F-4Consolidated Statements of Stockholders’ Equity (Deficit) for the years ended December 31, 2016 and 2015.F-5Consolidated Statements of Cash Flows for the years ended December 31, 2016 and 2015F-6Notes to Consolidated Financial StatementsF-7this Annual Report on Form 10-K or incorporated by reference:b)(i) ExhibitsThe consolidated financial statements of Lilis Energy, Inc. are listed on the Index to this Form 10-K, page 58.The information required by this Item is set forth on the exhibit index that follows the signature page to this Annual Report on Form 10-K and is incorporated herein by reference.c)b. Financial Statement SchedulesThe following exhibits are filed or furnished with this Annual Report on Form 10-K or incorporated by reference:Not applicable.80SIGNATURESPursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.LILIS ENERGY, INC.Date: March 3, 2017By:/s/ Abraham MirmanAbraham MirmanChief 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 the registrant in the capacities and on the dates indicated.SignatureTitleDate/s/ Abraham MirmanChief Executive Officer, DirectorMarch 3, 2017Abraham Mirman(Principal Executive Officer)/s/ Joseph C. DachesExecutive Vice President and Chief Financial OfficerMarch 3, 2017Joseph C. Daches(Principal Financial and Accounting Officer)/s/ Ronald D. OrmandExecutive Chairman of the BoardMarch 3, 2017Ronald D. Ormand/s/ Peter BenzDirectorMarch 3, 2017Peter Benz/s/ Nuno BrandoliniDirectorMarch 3, 2017Nuno Brandolini/s/ R. Glenn DawsonDirectorMarch 3, 2017R. Glenn Dawson/s/ General Merrill McPeakDirectorMarch 3, 2017General Merrill McPeak81Exhibit IndexThe following exhibits are either filed herewith or incorporated herein by reference2.1Agreement and Plan of Merger, dated as of December 29, 2015, among Lilis Energy, Inc., Lilis Merger Sub, Inc. and Brushy Resources, Inc. (incorporated herein by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on January 5, 2016). Certificate of Designation of Preferences, Rights, and Limitations of Series A 8% Convertible Preferred Stock, dated as of May 30, 2014 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 4, 2014).3.4Amendment to Certificate of Designation of Preferences, Rights, and Limitations of Series A 8% Convertible Preferred Stock, dated as of June 12, 2014 (incorporated herein by reference to Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, filed on June 17, 2014).3.5Certificate of Designation of Preferences, Rights and Limitations of 6% Redeemable Preferred Stock, dated as of August 29, 2014 (incorporated herein by reference to Exhibit 3.3 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2014, filed on November 26, 2014).3.6Certificate of Designation of Preferences, Rights and Limitations of Series B 6% Convertible Preferred Stock, dated as of June 15, 2016 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 16, 2016).3.73.84.1Warrant to Purchase Common Stock issued to Bristol Capital (incorporated herein by reference to Exhibit 4.3 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2014, filed on November 26, 2014).4.74.84.9Form of Warrant (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on January 5, 2016).4.104.11Common Stock Purchase Warrant issued to SOSV Investments, LLC on June 23, 2016. (incorporated herein by reference to Exhibit 4.3 to the Company’s Quarterly Report on Form 10-Q filed on August 25, 2016).4.12Form of Warrant (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on February 28, 2017).4.134.14†4.15†10.1†Employment Agreement with Kevin Nanke,10.2†10.3†Amended and Restated Employment Agreement between the Company and Abraham Mirman, dated as of March 30, 2015 (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 2, 2015).10.410.5Voting Agreement, dated as of December 29, 2015, among Lilis Energy, Inc., Lilis Merger Sub, Inc., Brushy Resources, Inc. and SOSventures, LLC (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 5, 2016).10.6Voting Agreement, dated as of December 29, 2015, among Lilis Energy, Inc., Lilis Merger Sub, Inc., Brushy Resources, Inc. and Longview Marquis Fund LP, LMIF Investments LLC and SMF investments, LLC (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on January 5, 2016).10.7Debenture Conversion Agreement, dated as of December 29, 2015, among Lilis Energy, Inc., T.R. Winston & Company, acting as placement agent, and each Debenture holder (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on January 5, 2016).10.810.910.1010.1110.12Convertible Subordinated Promissory Note Conversion Agreement, dated as of June 23, 2016, among Lilis Energy, Inc. and the parties signatory thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on June 28, 2016).10.13First Amendment to the Convertible Subordinated Promissory Notes, dated as of August 3, 2016, among Lilis Energy, Inc. and the parties signatory thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on August 5, 2016).10.14†Employment Agreement with Michael Pawelek, dated as of July 5, 2016 (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on July 8, 2016).10.15†Employment Agreement with Edward Shaw, dated as of July 5, 2016 (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on July 8, 2016).10.16†Employment Agreement with Abraham Mirman, dated as of July 5, 2016 (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on July 8, 2016).10.17†Employment Agreement with Kevin Nanke, dated as of July 5, 2016 (incorporated herein by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on July 8, 2016).10.18†10.19†10.20Transaction Fee Agreement, dated as of June 6, 2016, between Lilis Energy, Inc. and T.R. Winston & Company, LLC (incorporated herein by reference to Exhibit 10.12 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2016 filed on August 25, 2016).10.21First Amendment to Transaction Fee Agreement, dated as of June 8, 2016, between Lilis Energy, Inc. and T.R. Winston & Company, LLC (incorporated herein by reference to Exhibit 10.13 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2016 filed on August 25, 2016).10.22Escrow Deposit Agreement, dated as of May 26, 2016, by and among Lilis Energy, Inc., T.R. Winston & Company, LLC and Signature Bank (incorporated herein by reference to Exhibit 10.15 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2016 filed on August 25, 2016).10.2310.2410.2510.26†10.27†Employment Agreement with Brennan Short, dated as of January 27, 2017 (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 31, 2017).10.28†*Employment Agreement with Seth Blackwell, dated as of December 1, 2016.10.29†Separation and Release Agreement, dated February 13, 2017, between Kevin Nanke and Lilis Energy, Inc. (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 17, 2017).10.3010.3121.1*32.2*101.INS* 101.SCH* XBRL Taxonomy Extension Schema Document 101.CAL* XBRL Taxonomy Extension Calculation Linkbase Document 101.DEF* XBRL Taxonomy Extension Definition Linkbase Document 101.LAB* XBRL Taxonomy Extension Label Linkbase Document 101.PRE* XBRL Taxonomy Extension Presentation Linkbase Document * Filed herewith. † Indicates management contract or compensatory plan. + To be filed by amendment. LILIS ENERGY, INC. Date: March 7, 2019 By: /s/Ronald D. Ormand Ronald D. Ormand Signature Title Date /s/Ronald D. Ormand Executive Chairman of the Board & Chief Executive Officer March 7, 2019 Ronald D. Ormand (Principal Executive Officer) /s/ Joseph C. Daches President and Chief Financial Officer March 7, 2019 Joseph C. Daches (Principal Financial and Accounting Officer) /s/ Mark Christensen Director March 7, 2019 Mark Christensen /s/ Nuno Brandolini Director March 7, 2019 Nuno Brandolini /s/ R. Glenn Dawson Director March 7, 2019 R. Glenn Dawson /s/ John Johanning Director March 7, 2019 John Johanning /s/ Markus Specks Director March 7, 2019 Markus Specks /s/ Michael G. Long Director March 7, 2019 Michael G. Long /s/ David M. Wood Director March 7, 2019 David M. Wood /s/ Nicholas Steinsberger Director March 7, 2019 Nicholas Steinsberger To the Audit Committee of the and Shareholdersof and Subsidiariesand Subsidiaries (the “Company”) and subsidiaries as of December 31, 20162018 and 2015, and2017, the related consolidated statements of operations, changes in stockholders’ equity (deficit), and cash flows for the years then ended. Theseended, and the related notes (collectively referred to as the “consolidated financial statements are the responsibility of the Company’s management. 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)statements”). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. referred to above present fairly, in all material respects, the consolidated financial position of Lilis Energy, Inc.the Company and Subsidiaries, as ofsubsidiaries at December 31, 20162018 and 2015,2017, and the consolidated results of itstheir operations and itstheir cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.MarcumBDO USA, LLPMarcumLLPissued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on the COSO criteriaNew York, NY3, 2017
7, 2019 expressed an unqualified opinion thereon.F-1 December 31, 2016 2015 ASSETS Current assets: Cash and cash equivalents $ 11,738 $ 110 Accounts receivables, net of allowance of $106 and $80, respectively 2,247 952 Prepaid expenses and other current assets 767 79 Total current assets 14,752 1,141 Oil and gas properties, full cost method of accounting Unproved 24,461 - Proved 69,809 50,096 Less: accumulated depreciation, depletion, amortization and impairment (55,771 ) (49,573 ) Total oil and gas properties, net 38,499 523 Other property and equipment, net 52 44 Other assets 216 2,000 Total other assets 268 2,044 Total assets $ 53,519 $ 3,708 December 31, 2018 2017 ASSETS Current assets: Cash and cash equivalents $ 21,137 $ 17,462 Accounts receivable, net of allowance of $25 and $39, respectively 20,546 7,426 Derivative assets 2,551 — Prepaid expenses and other current assets 1,851 584 Total current assets 46,085 25,472 Property and equipment: Oil and natural gas properties, full cost method of accounting, net 430,379 170,305 Other property and equipment, net 524 76 Total property and equipment, net 430,903 170,381 Other assets 3,785 91 Total assets $ 480,773 $ 195,944 Current liabilities: Accounts payable $ 47,112 $ 10,488 Accrued liabilities 14,794 7,634 Revenue payable 14,546 6,460 Derivative instruments 515 853 Total current liabilities 76,967 25,435 Asset retirement obligations 2,433 726 Long-term debt 157,804 127,794 Derivative instruments 4,699 72,937 Long-term deferred revenue and other liabilities 52,513 — Total liabilities 294,416 226,892 Commitments and contingencies (Note 19) Mezzanine Equity: Series C-1 9.75% Convertible Participating Preferred Stock, 10,000,000 shares authorized, 100,000 shares issued and outstanding with a liquidation preference of $24.3 million as of December 31, 2018. 106,774 — Series C-2 9.75% Convertible Participating Preferred Stock, 10,000,000 shares authorized, 25,000 of shares issued and outstanding with a liquidation preference of $5.7 million as of December 31, 2018. 25,522 — Series D $8.25% Convertible Participating Preferred Stock, 10,000,000 shares authorized, 39,254 shares, issued and outstanding with a liquidation preference of $10.0 million as of December 31, 2018. 40,729 — Stockholders’ equity (deficit): Common stock, $0.0001 par value per share; 150,000,000 shares authorized, 71,182,016 and 53,368,331 shares issued and outstanding as of December 31, 2018 and 2017, respectively. 7 5 Additional paid-in capital 321,753 272,335 Treasury stock, 253,598 shares as of December 31, 2018 (997 ) — Accumulated deficit (307,431 ) (303,288 ) Total stockholders’ equity (deficit) 13,332 (30,948 ) Total liabilities, mezzanine equity and stockholders’ equity (deficit) $ 480,773 $ 195,944 F-2Balance Sheet December 31, 2016 2015 LIABILITIES, REDEEMABLE PREFERRED STOCK AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable $ 5,166 $ 1,331 Accrued liabilities 2,706 3,496 Dividends payable 808 719 Asset retirement obligations 338 - Current portion of long-term debt 17 11,067 Total current liabilities 9,035 16,613 Asset retirement obligations 919 209 Long-term debt 30,226 - Long-term derivative liabilities 1,400 56 Total liabilities 41,580 16,878 Commitments and contingencies (Note 9) Conditionally redeemable 6% preferred stock, $0.0001 par value, 7,000 shares authorized, 2,000 shares issued and outstanding with a liquidation preference of $2,240 at December 31, 2016. 1,874 1,173 Stockholders’ Equity (Deficit): Series A Preferred stock, $0.0001 par value; stated rate $1,000:10,000 shares authorized, 0 and 7,500 shares issued and outstanding as of December 31, 2016 and 2015, respectively. - 6,794 Series B Preferred stock, $0.0001 par value; stated rate $1,000: 20,000 shares authorized; 17,000 and 0 shares issued and outstanding at December 31, 2016 and 2015, respectively, with a liquidation preference of $20,627 at December 31, 2016. 13,432 - Common stock, $0.0001 par value per share; 100,000,000 shares authorized, 20,918,901 and 2,786,275 shares issued and outstanding as of December 31, 2016 and 2015, respectively. 2 - Additional paid-in capital 219,837 159,773 Accumulated deficit (223,206 ) (180,910 ) Total stockholders’ equity (deficit) 10,065 (14,343 ) Total liabilities, redeemable preferred stock and stockholders’ equity $ 53,519 $ 3,708 The accompanying notes are an integral part of these consolidated financial statementsF-3Lilis Energy, Inc. and SubsidiariesConsolidated Statements of Operations(In thousands, except share and per share data) Years Ended December 31, 2016 2015 Oil, natural gas and natural gas liquid sales $ 3,435 $ 396 Costs and expenses: Production costs 1,247 195 Production taxes (167 ) 28 General and administrative 14,570 7,930 Depreciation, depletion and amortization 1,566 574 Accretion of asset retirement obligations 132 10 Impairment of evaluated oil and gas properties 4,718 24,478 Total operating expenses 22,066 33,215 Loss from operations (18,631 ) (32,819 ) Other income (expenses): Other income 90 3 Debt conversion inducement expense (8,307 ) - Gain on extinguishment of debt 250 - Gain (loss) in fair value of derivative instruments (1,222 ) 1,638 Gain (loss) in fair value of conditionally redeemable 6% preferred stock (701 ) 514 Gain on modification of convertible debts 602 - Interest expense (4,924 ) (1,697 ) Total other income (expenses) (14,212 ) 458 Net loss (32,843 ) (32,361 ) Dividends on redeemable preferred stock (407 ) (120 ) Loss on extinguishment of Series A Convertible Preferred Stock (540 ) - Dividend and deemed dividend Series B Convertible Preferred stock (8,506 ) (600 ) Net loss attributable to common stockholders $ (42,296 ) $ (33,081 ) Net loss per common share basic and diluted $ (3.73 ) $ (12.13 ) Weighted average common shares outstanding: Basic and diluted 11,328,252 2,726,775 Year Ended December 31, 2018 2017 Revenues: Oil sales $ 58,042 $ 17,826 Natural gas sales 5,246 2,125 Natural gas liquid sales 6,928 1,661 Total revenues 70,216 21,612 Operating expenses: Production costs 13,843 5,832 Gathering, processing and transportation 3,392 1,191 Production taxes 3,709 1,187 General and administrative 33,251 49,851 Depreciation, depletion, accretion and amortization 25,367 7,025 Impairment of evaluated oil and natural gas properties — 10,505 Total operating expenses 79,562 75,591 Loss from operations (9,346 ) (53,979 ) Other income (expense): Loss on early extinguishment of debt (20,370 ) — Gain (loss) from commodity derivatives, net 55 (1,063 ) Gain (loss) from embedded derivatives 58,343 (6,260 ) Loss from conditionally redeemable preferred stock — (41 ) Interest expense (32,827 ) (18,757 ) Other income 2 18 Total other income (expense) 5,203 (26,103 ) Net loss before income taxes (4,143 ) (80,082 ) Income tax expense — — Net loss (4,143 ) (80,082 ) Dividends on Series C-1, C-2 and D convertible preferred stock (10,687 ) — Dividends on redeemable preferred stock — (122 ) Dividend and deemed dividends on Series B convertible preferred stock — (4,635 ) Net loss attributable to common stockholders $ (14,830 ) $ (84,839 ) Net loss per common share: Basic $ (0.24 ) $ (2.00 ) Diluted $ (0.47 ) $ (2.00 ) Weighted average common shares outstanding: Basic 62,854,214 42,428,148 Diluted 78,451,341 42,428,148 F-4 Series A Preferred Series B Preferred Additional Shares Shares Common Shares Paid In Accumulated Shares Amount Shares Amount Shares Amount Capital Deficit Total Balance, January 1, 2015 7,500 $ 6,794 - $ - 2,699,273 $ - $ 155,101 $ (147,829 ) $ 14,066 Issuances of common stock - - - - 87,002 - 365 - 365 Fair value of warrants issued for professional services - - - - - - 425 - 425 Fair value of warrants issued for bridge term loan - - - - - - 1,222 - 1,222 Stock based compensation - - - - - - 2,660 - 2,660 Dividend Preferred stockholders - - - - - - - (120 ) (120 ) Deemed dividend Series A Convertible Preferred Stock - - - - - - - (600 ) (600 ) Net loss - - - - - - - (32,361 ) (32,361 ) Balance, December 31, 2015 7,500 6,794 - - 2,786,275 - 159,773 (180,910 ) (14,343 ) Stock based compensation - - - - 711,667 - 7,078 - 7,078 Exercise of warrants - - - - 420,707 - 187 - 187 Fair value of warrants issued for financing costs - - - - - - 713 - 713 Issuance and repricing of warrants to induce conversion - - - - - - 8,307 - 8,307 Gain on modification of convertible debentures - - - - - - (602 ) - (602 ) Fair value of warrants issued for debt discount - - - - - - 1,479 - 1,479 Common stock issued for conversion of convertible notes and accrued interest - - - - 6,778,115 1 14,871 - 14,872 Common stock and warrants issued in connection with the Brushy merger - - - - 5,785,119 - 7,111 - 7,111 Series B Preferred stock issued for cash, net of fees - - 20,000 18,195 - - - - 18,195 Warrants issued for Series B Preferred Stock offering fees - - - (1,590 ) - - 1,590 - - Common stock issued for conversion of Series A Preferred Stock and accrued dividends (7,500 ) (6,794 ) - - 1,500,000 1 7,681 - 888 Loss on extinguishment of Series A Preferred Stock - - - - - - 540 (540 ) - Common stock issued for conversion of Series B Preferred Stock and accrued dividends - - (3,000 ) (3,173 ) 2,937,018 - 3,230 - 57 Dividends and deemed dividends for Preferred Stock - - - - - - 7,879 (8,913 ) (1,034 ) Net Loss - - - - - - - (32,843 ) (32,843 ) Balance, December 31, 2016 - $ - 17,000 $ 13,432 20,918,901 $ 2 $ 219,837 $ (223,206 ) $ 10,065 Common Shares Treasury Shares Accumulated Shares Amount Shares Amount Capital Shares Amount Deficit Total Balance, December 31, 2016 16,828 $ 13,432 20,918,901 $ 2 $ 219,837 — $ — $ (223,206 ) $ 10,065 Stock based compensation — — — — 21,538 — — — 21,538 Common stock for restricted stock and stock options — — 5,859,383 — 524 — — — 524 Common stock withheld for taxes on stock based compensation — — (786,081 ) — (3,709 ) — — — (3,709 ) Exercise of warrants — — 5,580,281 1 592 — — — 593 Conversion of Series B Preferred Stock and dividends (16,828 ) (13,432 ) 16,601,026 2 14,863 — — — 1,433 Sale of common stock in private placement, net — — 5,194,821 — 18,649 — — — 18,649 Warrants repriced for term loan — — — — 1,031 — — — 1,031 Dividends and deemed dividends on preferred stock — — — — (990 ) — — — (990 ) Net loss — — — — — — — (80,082 ) (80,082 ) Balance, December 31, 2017 — — 53,368,331 5 272,335 — — (303,288 ) (30,948 ) Stock based compensation — — — — 9,000 — — — 9,000 Common stock for restricted stock — — 404,093 — — — — — — Common stock withheld for taxes on stock based compensation — — (484,727 ) — (2,230 ) — — — (2,230 ) Exercise of warrants and stock options — — 5,000,834 — 3,751 — — — 3,751 Common stock issued for acquisition of oil and gas properties — — 6,940,722 1 24,777 — — — 24,778 Common stock issued for conversion of debt — — 5,952,763 1 24,584 — — — 24,585 Reclassification of warrant derivatives — — — — 223 — — — 223 Purchase of treasury stock — — — — — (253,598 ) (997 ) — (997 ) Dividends on preferred stock — — — — (10,687 ) — — — (10,687 ) Net loss — — — — — — — (4,143 ) (4,143 ) Balance, December 31, 2018 — $ — 71,182,016 $ 7 $ 321,753 (253,598 ) $ (997 ) $ (307,431 ) $ 13,332 F-5 Years Ended December 31, 2016 2015 Cash flows from operating activities: Net loss $ (32,843 ) $ (32,361 ) Adjustments to reconcile net loss to net cash used in operating activities: Equity instruments issued for services and compensation 7,078 3,450 Bad debt expense 494 - Inducement Expense 8,307 - Amortization of deferred financing cost 328 52 Accretion of debt discount 2,857 - Gain on extinguishment of debt (250 ) - Gain (loss) in fair value of derivative instruments 1,222 (1,604 ) Gain (loss) in fair value of conditionally redeemable 6% preferred stock 701 (514 ) Gain on modification of convertible debt (602 ) - Depreciation, depletion, amortization and accretion of asset retirement obligation 1,698 584 Impairment of evaluated oil and gas properties 4,718 24,478 Changes in operating assets and liabilities: Accounts receivable (1,264 ) (120 ) Other assets 1,554 57 Accounts payable, accrued expenses and other liabilities (307 ) 2,027 Net cash used in operating activities (6,309 ) (3,951 ) Cash flows from investing activities: Cash advance to Brushy Resources, Inc. - (1,750 ) Cash consideration for Brushy merger, net of cash acquired (2,302 ) - Restricted cash - 145 Capital expenditures (16,828 ) (98 ) Net cash used in investing activities (19,130 ) (1,703 ) Cash flows from financing activities: Net proceeds from issuance of Series B Preferred Stock 18,195 - Proceeds from bridge notes, net 2,863 5,950 Proceeds from warrant exercise 187 - Dividend payments on preferred stock - (180 ) Debt issuance costs (1,299 ) (266 ) Proceeds from issuance of term loan 31,000 - Repayment of debt (13,879 ) (250 ) Net cash provided by financing activities 37,067 5,254 Increase (decrease) in cash 11,628 (400 ) Cash at beginning of period 110 510 Cash at end of period $ 11,738 $ 110 Supplemental disclosure: Cash paid for interest $ 762 $ 365 Year Ended December 31, 2018 2017 Cash flows from operating activities: Net loss $ (4,143 ) $ (80,082 ) Adjustments to reconcile net loss to net cash provided by (used in) operating activities: Stock based compensation 9,000 21,538 Bad debt expense 106 22 Amortization of debt issuance cost and debt discount 15,656 10,371 Paid-in-kind interest 12,213 6,559 Loss on early extinguishment of debt 20,370 — (Gain) loss on commodity derivatives (55 ) 1,063 Net settlements on commodity derivatives (2,742 ) (96 ) Gain (loss) on embedded derivatives (58,343 ) 6,301 Depreciation, depletion, amortization and accretion 25,367 7,025 Impairment of evaluated oil and natural gas properties — 10,505 Changes in operating assets and liabilities: Accounts receivable (13,226 ) (5,204 ) Prepaid and other assets (473 ) 309 Accounts payable, accrued expenses and other liabilities 53,402 14,446 Proceeds from options associated with future midstream services 35,000 — Net cash provided by (used in) operating activities 92,132 (7,243 ) Cash flows from investing activities: Proceeds from options associated with salt water disposal infrastructure 17,500 — Acquisitions of Southwest Royalties LLC (17,039 ) — Acquisitions of oil and natural gas properties (75,371 ) — Net proceeds from sale of DJ Basin and non-operated properties — 1,282 Capital expenditures (168,025 ) (148,784 ) Net cash used in investing activities (242,935 ) (147,502 ) Cash flows from financing activities: Proceeds from term loans, net of financing costs 47,806 185,428 Proceeds from the revolving credit agreement 75,000 — Debt issuance costs (2,434 ) — Repayment of term loans and notes payable (88,836 ) (40,394 ) Proceeds from the issuance of Series C Preferred Stock 125,000 — Equity financing costs (2,582 ) — Proceeds from private placement, net of financing costs — 18,399 Proceeds from exercise of stock options and warrants 3,751 745 Payment for tax withholding on stock-based compensation (2,230 ) (3,709 ) Payment for common stock repurchased (997 ) — Net cash provided by financing activities 154,478 160,469 Increase in cash and cash equivalents 3,675 5,724 Cash and cash equivalents at beginning of period 17,462 11,738 Cash and cash equivalents at end of period $ 21,137 $ 17,462 Cash paid for interest $ 4,958 $ 2,292 F-6ORGANIZATIONOn September 21, 2007, Universal Holdings, Inc. (“Universal”), a Nevada corporation, completed the acquisition of Coronado Acquisitions, LLC (“Coronado”). Under the terms of the acquisition, Coronado was merged into Universal. On October 12, 2009, Universal changed its name to Recovery Energy, Inc. On December 1, 2013, Recovery Energy, Inc. changed its name to Organization and Businessandor the “Company”).explorationcompany focused on the acquisition, development, and production company focused onof conventional and unconventional oil and natural gas properties in the core of the Delaware Basin in Winkler, Loving, and LovingReeves Counties, Texas and Lea County, New Mexico and the Denver-Julesburg Basin (“DJ Basin”) in Wyoming, Colorado, and Nebraska.On June 23, 2016, the Company effected a 1-for-10 reverse stock split of its Common Stock (the “Reverse Split”). The accompanying consolidated financial statements and these notes to the consolidated financial statements give retroactive effect to the Reverse Split for all periods presented.All references to production, sales volumes and reserves quantities are net to the Company’s interest unless otherwise indicated.MANAGEMENT PLANS AND LIQUIDITYThe Company has reported net operating losses during the year ended December 31, 2016Basis of Presentation and for the past five years. As a result, the Company funded its operations in 2016 and the merger with Brushy Resources, Inc. through additional debt and equity financing. On September 29, 2016, the Company entered into a new Credit and Guaranty Agreement (the “Credit Agreement”) that provides for a three-year, senior, secured term loan with initial aggregate principal commitmentsSummary of $31 million and a maximum facility size of $50 million. The term loan was funded in two draws, with $25 million collected as of September 30, 2016 and the additional $6 million collected as of November 11, 2016.As of December 31, 2016, the Company had a working capital balance and a cash balance of approximately $5.7 million and $11.7 million, respectively. As of March 1, 2017, the Company’s cash balance was approximately $9.0 million, which included a drawdown of additional principal under its Credit Agreement on February 7, 2017 of $7.1 million and excluded net proceeds of the equity offering completed on March 1, 2017, or approximately $18.6 million. The Company believes that it will have sufficient capital to operate over the next 12 months from the date of the filing of this annual report. However, it is possible that the Company will seek to raise additional debt, equity capital, or both depending on the pace of its drilling and leasing activity.NOTE 3 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND ESTIMATESsubsidiaries. The Company’s wholly owned subsidiaries includewhich includes Brushy Resources, Inc (“Brushy”), ImPetro Operating, LLC (“ImPetro Operating”) and, ImPetro Resources, LLC (“ImPetro”), and Lilis Operating Company, LLC (“Lilis Operating”), and Hurricane Resources LLC (“Hurricane”). All significant intercompany accounts and transactions have been eliminated in consolidation.preparation ofaccompanying consolidated financial statements are prepared in conformity with generally accepted accounting principles in the United States (“U.S. GAAP”)GAAP which requires the Company to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities; disclosure of contingent assets and liabilities at the date of the financial statements;statements, the reported amounts of revenues and expenses during the reporting period; and the quantities and values of proved oil, natural gas and NGLnatural gas liquid (“NGL”) reserves used in calculating depletion and assessing impairment of its oil and natural gas properties.F-7financial estimates are associated withpertain to the Company’s estimated volumesevaluation of unproved properties for impairment, proved oil and natural gas reserves asset retirement obligations, assessments of impairment imbeddedand related cash flow estimates used in the carrying valuedepletion and impairment of undeveloped acreageoil and undevelopednatural gas properties; the timing and amount of transfers of our unevaluated properties into our amortizable full cost pool; the fair value of financial instruments, includingembedded derivatives and commodity derivative liabilities, depreciationcontracts, accrued oil and accretion, income taxesnatural gas revenues and contingencies. Although management believes that these estimates are reasonable, actualexpenses, valuation of options and warrants, and the allocation of general administrative expenses. Actual results could differ significantly from thosethese estimates.prior-period amountsreclassifications have been reclassified for comparative purposesmade to the prior year financial statements to conform withto the fiscal 20162018 presentation. These reclassifications have no effect on the Company’s previously reported results of operations.Equivalentwhen purchased to be cash equivalents as these instruments are readily convertible to known amounts of cash and do not bear significant risk of changes in value due to their short maturity period.records actual and estimated oil and gas revenuehas accounts receivable from third parties at its net revenue interest. The Company also reflects costs incurred on behalf of joint interest partners.owners of properties operated by the Company. The Company typically has the right to withhold future revenue disbursements to recover outstandingany non-payment of related joint interest billings on outstanding receivables from joint interest owners.billings. Management periodically reviewsroutinely assesses accounts receivable amounts forto determine their collectability and records itsaccrues an allowance for uncollectible receivables using the allowance methodwhen, based on past experience. Allowance for doubtful accounts are based primarily on joint interest billings for expenses related tothe judgment of management, it is probable that a receivable will not be collected. The Company records actual and estimated oil and natural gas wells. Receivables which deriverevenue receivable from third parties at its net revenue interest. In addition, the Company has receivables derived from sales of certain oil and natural gas production which are collateral under the Company’s Credit Agreement.Concentrationcredit agreements.Credit RiskThe Company’s cash is invested at major financial institutions primarily within the United States. AtFinancial Instruments20162018 and 2015,2017, the Company’scarrying value of cash was maintained inand cash equivalents, accounts that are insured upreceivable, accounts payable, accrued liabilities, revenue payable and advances from joint interest partners approximates fair value due to the limit determined by the federal governmental agency.short-term nature of such items. The Company may at times have balances in excess of the federally insured limits. Periodically, the Company evaluates the creditworthiness of the financial institutions, and has not experienced any losses in such accounts.Significant CustomersThe Company’s major customers include, Noble Energy, Texican and Energy Transfer, Inc. These customers accounted for approximately 41%, 38% and 16%carrying value of the Company’s revenue forsecured debt is carried at cost which approximates the year ended December 31, 2016. The Company’s major customers include, Shell Trading (US), PDC Energy and Noble Energy, which accounted for approximately 43%, 26% and 21% of its revenue for the year ended December 31, 2015.However, the Company believe that the loss of a single purchaser could not materially affect the Company’s business because alternative purchasers are available.ReservesAllfair value of the reserves data included herein are estimates. Estimates ofdebt as the Company’s crude oil and natural gas reserves are prepared in accordance with guidelines established byrelated interest rates approximates interest rates currently available to the Securities Exchange Commission (“SEC”), including rule revisions designed to modernize the oil and gas company reserves reporting requirements, which the Company implemented effective December 31, 2010. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Uncertainties include the projection of future production rates and the expected timing of development expenditures. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserves estimates may be different from the quantities of crude oil 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 the reserves estimate. The Company’s reserves estimates are based on 12-month average commodity prices, unless contractual arrangements otherwise designate the price to be used, in accordance with the SEC rules. However, oil and gas prices are volatile and, as a result, the Company’s reserves estimates may change in the future.
Company.F-8Estimates of proved crude oil and natural gas reserves significantly affect the Company’s depreciation, depletion, and amortization (“DD&A”) expense. For example, if estimates of proved reserves decline, the DD&A rate will increase, resulting in a decrease in net income. A decline in estimates of proved reserves could also result in an impairment charge, which would reduce earnings. 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 credit against capitalized exploration and development costs, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of proved reserves.The Company accounts for its unproven long-lived assets in accordance with Accounting Standards Codification (“ASC”) Topic 360-10-05, Accounting for the Impairment or Disposal of Long-Lived Assets. ASC Topic 360-10-05 requires that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the historical cost carrying value of an asset may no longer be appropriate.reserves; and (c) estimated decommissioning and abandonment/restoration costs, net of estimated salvage values,reserves, that are not otherwise included in capitalized costs.Costs associated with undeveloped acreage are excluded from the depletion base until it is determined whether proved reserves can be assigned 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 is added to full cost pool which is subject to depletion calculations.and net(net of deferred income taxestaxes) may not exceed an amount equal to the sum of the present value, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves and the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are not subject to amortization. Should capitalized costs exceed this ceiling, an impairment expense is recognized. During 2016, commodity prices continued to trade in a low range. With low commodity prices sustained for the majority of 2016 in the DJ Basin, some of the Company’s properties became uneconomic triggering an impairment charge of $4.7 million at December 31, 2016. Due to the decline in commodity prices and lack of liquidity the Company recorded an impairment charge during the year ended December 31, 2015. During the years ended December 31, 2016 and 2015, the Company recorded $4.7 million and $24.5 million impairment charges, respectively.The present value of estimated future net cash flows was computed by applying:applying a flat oil price to forecast revenues from estimated future production of proved oil and natural gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves (assuming the continuation of existing economic conditions), less any applicable future taxes.F-9$0.04$0.01 million and $0.03$0.04 million of depreciation for the years ended December 31, 20162018 and 2015,2017, respectively.ImpairmentLong-lived AssetsThe Company accounts for long-lived assets (other than oilDecember 31, 2018 and gas properties) at cost. The Company may impair these assets whenever events or changes in circumstances indicate that2017, the carrying amount of such assets may not be fully recoverable. Recoverability is measured by comparing 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 not be recoverable, and if the carrying amount of an asset exceeds its estimated fair value, an impairment charge is recognized to the extentCompany’s accrued liabilities consisted of the difference. December 31, 2018 2017 (in thousands) Accrued bonuses $ 2,300 $ 3,000 Accrued drilling costs 7,850 3,615 Accrued production expenses 2,926 182 Other accrued liabilities 1,718 837 Total accrued liabilities $ 14,794 $ 7,634 calculations, the Company includes estimated dismantlement and abandonment cost, net of salvage values, associated with future development activities that have not yet been capitalized as asset retirement obligations. Asset retirement obligations incurred are classified as Level 3 (unobservable inputs) fair value measurements. The asset retirement liabilityallocated to operating expense using a systematic and rational method.Fair Value of Financial InstrumentsAs of December 31, 2016 and 2015, the carrying value of cash and cash equivalents, accounts receivable, accounts payable, accrued expenses, interest and dividends payable and advance from joint interest partners approximates fair value duerecognized when control passes to the short-term naturepurchaser which generally occurs when production is transferred to the purchaser. The Company measures revenue as the amount of such items. The carrying valueconsideration it expects to receive in exchange for the commodities transferred. All of the Company’s secured debtrevenues from contracts with customers represent products transferred at a point in time as control is carried at cost which is approximately the fair value of the debt as the related interest rate are at the terms approximates rates currently availabletransferred to the Company.Revenue Recognitionwhenin the amount that reflects the consideration it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidenceexpects to receive in exchange for transferring control of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller's pricethose goods to the buyercustomer. The contract consideration in the Company’s variable price contracts is fixedtypically allocated to specific performance obligations in the contract according to the price stated in the contract. Payment is generally received one or determinable and (iv) collectability is reasonably assured.uses the entitlementsapplies a fair value method of accounting for oil, NGLs and gas revenues. Sales proceedsstock based compensation, which requires recognition in excessthe financial statements of the Company's entitlement are includedcost of services received in other liabilities and the Company's share of sales taken by others is included in other assets in the accompanying consolidated balance sheets. The Company had no material oil, NGL or gas entitlement assets or liabilities as of December 31, 2016 or 2015.Stock Based CompensationThe Company measures the fair value of stock-based compensation expense awards made to employees and directors, including stock options, restricted stock units, and restricted stock, on the date of grant using a Black-Scholes model.exchange for equity awards. For equity awards, compensation expense is based on the fair value on the grant date or modification date and is recognized in the Company’s financial statements over the vesting period. The measurementCompany utilizes the Black-Scholes Merton option-pricing model to measure the fair value of share-based compensation expense isstock options based on several criteria, including but not limited to, the valuation model used and associated input factors, such as expected term of the award, stock price volatility, risk free interest rate, dividend rate and award cancellation rate. These inputs are subjective and are determined using management’s judgment. If differences arise between the assumptions used in determining share-basedstock based compensation expense and the actual factors, which become known over time, the Company may change the input factors used in determining future share-basedstock based compensation expense.F-10Warrant Modification ExpenseThe 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, if any, of the fair value of the modified award over the fair value of the original award immediately before modification, and is either expensed as a period expense or amortized over the performance or vesting date. The Company estimates the incremental value of each warrant using the Black-Scholes option pricing model. The Black-Scholes model is highly complex and dependent on key estimates by management. The estimate with the greatest degree of subjective judgment is the estimated volatility of the Company’s stock price.Earnings (Loss) Per ShareBasic income (loss) per share was calculated by dividing net income or loss applicable to common shares by the weighted average number of common shares outstanding during the periods presented. The calculation of diluted income (loss) per share should include the potential dilutive impact of shares issuable upon the conversion of debt or preferred stock, vested restricted stock and exercise of warrants and options during the period, unless their effect is anti-dilutive. At December 31, 2016 and 2015, shares underlying restricted stock units, restricted stock, options, warrants, preferred stock and debentures have been excluded from the diluted share calculations as they were anti-dilutive as a result of net losses incurred. The Company has included 3,522,735 warrants, with an exercise price of $.01, in its earnings per share calculation for the year ended December 31, 2016.The Company had the following shares of Common Stock equivalents at December 31, 2016 and 2015: December 31, 2016 2015 Stock Options 5,956,833 6,083,333 Restricted Stock Units 149,584 1,869,000 Restricted Stock 1,068,305 - Series A Preferred Stock - 3,112,033 Series B Preferred Stock 15,454,545 - Stock Purchase Warrants 12,392,776 24,383,161 Convertible Debentures - 3,423,233 Convertible Bridge Notes - 5,900,004 35,022,043 44,770,764 20162018 and 2015,2017, the Company has determined that no liability is required to be recognized.20162018 and 2015.2017. Further, the Company does not expect that the total amount of unrecognized tax benefits will significantly increase or decrease during the next 12 months.Recently Issued Accounting Pronouncementsconsidersoperates a substantial portion of its oil and natural gas properties. As the applicabilityoperator of a property, the Company makes full payment for costs associated with the property and impactseeks reimbursement from the other joint interest owners in the property for their portion of allthose costs. When warranted, prepayments are required from joint interest owners for drilling and completion projects. Joint interest owners consist primarily of independent oil and natural gas producers whose ability to reimburse the Company could be negatively impacted by adverse market conditions. Year Ended December 31, 2018 2017 Texican Crude & Hydrocarbon, LLC 87 % 85 % ETC Field Services LLC 2 % 14 % Lucid Energy 10 % — % All others 1 % 1 % 100 % 100 % Updates (“ASUs”). ASUsCompany adopted Accounting Standard Update (ASU) No. 2016-02, Leases (Topic 842) on January 1, 2019. This ASU establishes significant changes to accounting for leases which include recognizing a lease liability and a right-of-use (ROU) asset for all leases, with terms exceeding 12 months on the Company’s Consolidated Balance Sheet. Expenses related to operating leases will continue to be recognized in the Company’s Consolidated Statements of Operations that are similar to current lease accounting guidance. The Company adopted this ASU using the modified retrospective approach and elected a package of practical expedients which allows the Company to avoid reassessing contracts that commenced prior to adoption and were correctly classified under existing lease accounting guidance. The Company will apply the transition requirements at the January 1, 2019 effective date. This approach allows for a cumulative effect adjustment in the period of adoption and prior periods will not listed belowbe restated.determinedidentified at January 1, 2019, the Company estimates the impact to its Consolidated Balance Sheet would be eitherapproximately between the range of $6.7 million and $8.2 million and does not applicable or are expected to have minimalexpect a material impact on its Consolidated Statements of Operations or Consolidated Statement of Cash Flows. As Reported Balances without Adoption of ASC 606 Increase (Decrease) Year Ended December 31, 2018 (in thousands) Consolidated Statements of Operations: Revenues $ 70,216 $ 70,321 $ (105 ) Operating expenses (3,392 ) (3,497 ) 105 As of December 31, 2018 Consolidated Balance Sheets: Accounts receivable $ 17,363 $ 17,468 $ (105 ) Accrued liabilities 14,793 14,898 (105 ) position and/instruments with down round features by requiring companies to disregard the down round feature when assessing whether the instrument is indexed to its own stock, for purposes of determining liability or resultsequity classification. Companies that provide earnings per share (EPS) data will adjust their basic EPS calculation for the effect of operations.
the feature when triggered (that is, when the exercise price of the related equity-linked financial instrument is adjusted downward because of the down round feature) and will also recognize the effect of the trigger within equity. Part II of ASU 2017-11 is not applicable to the Company since it addresses concerns relating to an indefinite deferral available to private companies with mandatorily redeemable financial instruments and certain noncontrolling interests. The provisions of ASU 2017-11 related to down rounds are effective for public business entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. Early adoption is permitted for all organizations. The Company elected to adopt ASU 2017-11 on January 1, 2018. The Company’s SOS Warrant Liability (as described in Note 7) was accounted for as a derivative instrument solely because of its down round feature. The outstanding SOS Warrants of $0.2 million as of the date of adoption were reclassified to equity and the Company no longer recognize any gain or loss based on the fair value of the SOS Warrants. The cumulative effect of the adoption was not material. The SOS Warrants expired on June 23, 2018. No other derivatives instruments were affected by the adoption of ASU 2017-11.F-11In“Business Combinations (Topic 805): Clarifying the Definition of a Business”Business (ASU 2017-01), which clarifies the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. The standardASU 2017-01 introduces a screen for determining when assets acquired are not a business and clarifies that a business must include, at a minimum, an input and a substantive process that contribute to an output to be considered a business. This standard is effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period. The Company adopted this ASU 2017-01 on January 1, 2017, and expects that2018. During year ended December 31, 2018, the adoptionCompany completed multiple acquisitions which were assessed in accordance with the new standard (see Note 4).thisCash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force). This ASU could have a material impact on future consolidated financialrequires the statements for acquisitions that are not considered to be businesses.The FASB issued ASU 2016-18, “Restricted Cash (Topic 230),” to clarify the presentation of restricted cash in the statement of cash flows. The amendments require that a statement of cash flows explainto present the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. In additions to changes in cash and cash equivalents,Therefore, amounts generally described as restricted cash and restricted cash equivalents should beare now included with cash and cash equivalents when reconciling the beginning-of-periodbeginning of period and end-of-period totalend of period amounts shownpresented on the statementstatements of cash flows. As a result, transfers between cash and restricted cash will not be presented as a separate line item in the operating, investing or financing section of the cash flow statement. The amendments are effect for public business entities for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted. The Company will adopt this ASU in 2017. The adoptionretrospective application of this ASU will affect the presentationsnew accounting guidance did not have a material impact in the Company’s consolidated balance sheets andaccompanying consolidated statement of cash flows and will not materially impact the results of operations.In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842),” which requires companies to recognize the assets and liabilities for the rights and obligations created by long-term leases of assets on the balance sheet. The guidance requires adoption by application of a modified retrospective transition approach for existing long-term leases and is effective for fiscal years beginning after December 15, 2018, including interim periods within those years. The effect of this guidance relating to the Company’s existing long-term leases will not have material impact on the Company’s consolidated financial statements. As ofyear ended December 31, 2016,2017. For the Company currently has only one 2-year operating lease.The FASB issued ASU 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. This ASU will simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This ASU is effective for annual and interim periods beginning in 2017 with early adoption permitted. The Company adopted this ASU on January 1, 2017 and does not believe that the simplification of accounting for share-based compensation and related income taxes will have a material impact on its consolidated financial statements.In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). This ASU amends the principal versus agent guidance in ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), which was issued in May 2014 (“ASU 2014-09”). Further, in April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing. This ASU also amends ASU 2014-09 and is related to the identification of performance obligations and accounting for licenses. The effective date and transition requirements for both of these amendments to ASU 2014-09 are the same as those of ASU 2014-09, which was deferred for one year by ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date. That is, the guidance under these standards is to be applied using a full retrospective method or a modified retrospective method, as outlined in the guidance, and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted only for annual periods, and interim period within those annual periods, beginning after December 15, 2016. The Company has not selected a transition method and is evaluating its revenue recognition policies and existing customer contracts to determine the impact this guidance will have on its financial statements.In March 2016, the FASB issued ASU No. 2016-06, “Derivatives and Hedging (Topic 815): Contingent Put and Call Options in Debt Instruments” (“ASU 2016-06”). This new standard simplifies the embedded derivative analysis for debt instruments containing contingent call or put options by removing the requirement to assess whether a contingent event is related to interest rates or credit risks. This new standard will be effective for the Company on January 1, 2017. The Company expects the adoption of this standard may have material impact on the Company’s result of operations from its continued efforts in raising capital to fund its operations and develop its oil and gas properties from issuing convertible equity or debt instruments.On August 26, 2016, the FASB issued ASU No. 2016-15, Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force), (“ASU 2016-15”). The amendments in ASU 2016-15 address eight specific cash flow issues and apply to all entities, including both business entities and not-for-profit entities that are required to present a statement of cash flows under FASB Accounting Standards Codification (FASB ASC) 230, Statement of Cash Flows. The amendments in ASU 2016-15 are effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The Company adopted this ASU on January 1, 2017 and expects the adoption will only affect the classifications within the consolidated statement of cash flows.F-12In September 2015, the FASB issued ASU No. 2015-16, “Business Combinations (Topic 805), Simplifying the Accounting for Measurement-Period Adjustments” (“ASU 2015-16”). The update requires that the acquirer in a business combination recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined (not retrospectively as with prior guidance). Additionally, the acquirer must record in the same period’s financial statements the effect on earnings of changes in depreciation, amortization or other 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. The acquiring entity is required to disclose, on the face of the financial statements or in the footnotes to the financial statements, the portion of the amount recorded in current period earnings, by financial statement line item, that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The guidance in ASU No. 2015-16 is effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. Earlier application is permitted for financial statements that have not been issued. The Company adopted this standard on January 1, 2016 and there were no material impact on its consolidated financial statements.In April 2015, the FASB issued ASU No. 2015-03 (“ASU 2015-03”), “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs.” ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from 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 the Company on January 1, 2016. Once adopted, entities are required to apply the new guidance retrospectively to all prior periods presented. The retrospective application represents a change in accounting principle. Early adoption is permitted for financial statements that have not been previously issued. The Company adopted this standard on January 1, 2016. The adoption of ASU 2015-03 only affects the presentation of the Company’s accompanying consolidated balance sheets and related financial statement disclosures in Note 9. In conjunction with the adoption of ASU 2015-03, $1.8 million and $0.2 million of debt issuance costs, previously presented as part of other assets was included as part of long-term debt which was reclassified as a direct deduction from the carrying amount of that debt liability as ofended December 31, 2016 and 2015, respectively.In August 2014, the FASB issued ASU No. 2014–15 (“ASU 2014-15”), “Presentation of Financial Statements – Going Concern.” ASU 2014-15 provides GAAP guidance on management’s responsibility in evaluating whether2018, there is substantial doubt about a company’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, management will be required to evaluate whether there are conditions or events that raise substantial doubt about a company’s ability to continue as a going concern within one year from the date the financial statements are issued. The new standard is effective for the Company on January 1, 2017. As of December 31, 2016, the Company believes that it has sufficient capital to operate for the next 12 months – see management’s assessment and analysis of its plans and liquidity in Note 2was no restricted cash. Management Plans and Liquidity above.NOTE 4 – OIL AND NATURAL GAS PROPERTIESsetsset forth a summary of oil and natural gas property costs (net of divestitures) not being amortized at December 31, 20162018 and 2015: December 31, 2016 2015 (In thousands) Undeveloped unevaluated acreage Beginning Balance $ - $ 2,886 Lease purchases 546 - Assets conveyed 23,915 - Transfer and other reclassification to evaluated properties - (2,886 ) Total undeveloped acreage $ 24,461 $ - Wells in progress: Beginning Balance $ - $ 6,042 Additions 7,453 - Disposition of wells in progress for elimination of accrued expenses for drilling - (5,198 ) Reclassification to evaluated properties - (844 ) Total wells in progress and not subject to DD&A $ 7,453 $ -
2017:F-13During 2018 2017 Oil and natural gas properties: (In thousands) Proved $ 358,858 $ 141,717 Unproved 169,863 101,771 Total oil and natural gas properties 528,721 243,488 Accumulated depletion, depreciation and amortization (98,342 ) (73,183 ) Oil and natural gas properties, net $ 430,379 $ 170,305 Year of Acquisition Total 2018 2017 2016 Unamortized costs: (in thousands) Unproved leasehold costs $ 168,302 $ 92,505 $ 52,744 $ 23,053 Exploratory costs 1,561 1,561 — — Total $ 169,863 $ 94,066 $ 52,744 $ 23,053 2016,2018, $11.1 million of unproved property costs were transferred to proved properties due to defective titles in certain leases. There were no such transfers of unproved properties to proved properties for the Company entered the Delaware Basin through the Merger. Since then, Lilis has increased its Delaware Basin acreage position by 53% and has added 860 net contiguous acres further expanding its Delaware Basin footprint. Atyear ended December 31, 2016 and 2015, the Company completed an assessment of its inventory of unevaluated acreage, which resulted in a transfer of $0 and $2.9 million, respectively from unevaluated acreage to evaluated properties.(“DD&A”) expensesexpense related to the proved properties werefull cost pool was approximately $1.6$25.4 million and $0.6$7.0 million for the years ended December 31, 20162018, and 2015,2017, respectively.5 – MERGER WITH BRUSHY RESOURCES, INC.4 - ACQUISITIONS AND RELATED TRANSACTIONSJune 23, 2016, the CompanyOctober 16, 2018, Lilis completed the merger transaction contemplated by the Agreement and Plan of Merger dated as of December 29, 2015, as amended to date (the “Merger Agreement”) by and among the Company, Brushy and Lilis Merger Sub, Inc., a Delaware corporation, a wholly-owned subsidiary of the Company (“Merger Sub”). Pursuant to the terms of the Merger Agreement, at the effective time (the “Effective Time”), Merger Sub merged with and into Brushy (the “Merger”), with Brushy continuing as the surviving corporation and becoming a wholly-owned subsidiary of Brushy.The Merger resulted in thean acquisition of Brushy’s propertiesapproximately 568.5 net acres in the Delaware Basin as well as the majority of its current operating activity.The results of Brushy, since the closing date of the Merger are includedWinkler county in the Company’s consolidated statement of operations. The Merger was effected through the issuanceTexas from Southwest Royalties LLC (the “Southwest Royalties Acquisition”) for total consideration of approximately 5.785 million shares of Common Stock in exchange for all outstanding shares of Brushy common stock using a ratio of 0.4550916 shares of Lilis Common Stock for each share of Brushy common stock and the assumption of Brushy's liabilities, including approximately $11.4 million of outstanding debt with Independent Bank, Brushy’s former senior lender, and approximately $6.2 million of accounts payable, accrued expenses and asset retirement obligations. In connection with the closing of the Merger, Lilis paid-down $6.0$17.0 million. The Company recorded $12.6 million of the principal amount outstanding on Brushy’s term loantotal consideration to the full cost pool associated with Independent Bank, made a cash payment of $500,000 to SOSV Investments, LLC (“SOS”), Brushy's former subordinated lenderacquired working interests in proved properties and issued a $1 million promissory note to SOS (the “SOS Note”), along with a warrant to purchase 200,000 shares of Common Stock (the “SOS Warrant”).In connection with the Merger, Lilis incurred costs of approximately $3.22$4.5 million to date, including (i) $3.05 million of consulting, investment, advisory, legal and other Merger-related fees, and (ii) $170,000 of value in conjunction with the warrants issued to SOS recorded additional Merger consideration.Allocation of Purchase Price -unproved acreage cost. The Merger has beenSouthwest Royalties Acquisition was accounted for as a business combination, usingcombination. Therefore, the acquisition method. The following table represents the allocation of the total purchase price of Brushywas allocated to the assets acquired and liabilities assumed based on their estimated acquisition date fair values available at closing. Transaction costs associated for this acquisition were immaterial and were expensed in the fair value on the closing date of the Merger.The following table sets forth the Company’s purchase price allocation(in thousands, except shares data and stock price):Shares of Lilis Common Stock issued to Brushy shareholders 5,785,119 Lilis Common Stock closing price on June 23, 2016 $ 1.20 Fair value of Common Stock issued $ 6,942 Cash consideration paid to SOS 500 SOS Note 1,000 Fair value of SOS warrant 170 Warrant liability - repricing derivative 164 Advance to Brushy pre-merger 2,508 Total purchase price 11,284 Plus: liabilities assumed by Lilis Current Liabilities Account payable and accrued expenses $ 5,447 Term loan - Independent Bank 11,379 16,826 Long-Term Debt 19 Asset Retirement Obligation 777 Amount attributable to liabilities assumed 17,622 $ 28,906 Fair Value of Brushy Assets Current Assets: Cash $ 706 Other current assets 624 $ 1,330 Oil and Gas Properties: Evaluated properties 7,512 Unevaluated properties 19,662 27,174 Other assets Other Property Plant & Equipment 42 Other assets 360 402 Total Asset Value $ 28,906 F-14Pro forma Financial Information - The following pro forma condensed combined financial information was derived from the historical financial statements of Lilis and Brushy and gives effect to the Merger as if it had occurred on January 1, 2015Consolidated Statements for Operations during the year ended December 31, 2015. Below information reflects pro forma adjustments based on available information2018. Revenues and certain assumptions thatoperating expenses associated with the Company believes are reasonable, including (i) Lilis’s Common Stock issuedproved properties were insignificant to convert Brushy’s outstanding sharesthe December 31, 2018 Consolidated Statements of common stockOperations. As of October 16, 2018 (In thousands) Fair value of net assets: Proved oil and natural gas properties $ 12,562 Unproved oil and natural gas properties 4,542 Total assets acquired 17,104 Asset retirement obligations assumed (65 ) Fair value of net assets acquired $ 17,039 Merger, (ii)Felix leasehold interests, the Company acquired certain working interests in two wells operated by the Company in Winkler County, Texas. The Company paid Felix for the well costs incurred by Felix to drill and complete the two wells, less any revenues paid to Felix. The final settlement was a payment of $0.4 million which was recorded as an adjustment to the full cost pool. Transaction costs associated for this acquisition were immaterial.conform Brushy’s historical policythe Purchase and Sale Agreement consist of accountingleasehold acreage in the Delaware Basin in Lea County, New Mexico. On March 15, 2018, the Company completed the OEP Acquisition whereby the Company paid $40 million in cash and issued 6,940,722 shares of the Company’s common stock valued at approximately $24.9 million for a total purchase price of approximately $64.9 million, before acquisition costs and customary purchase price adjustments. The value of the shares issued was determined using the closing price of the Company’s stock on the date of closing. Transaction costs associated for this acquisition were $1.1 million.successful efforts methodsale of non-operated properties sold in 2017. Year Ended December 31, 2018 2017 (In thousands) ARO, beginning of period $ 952 $ 1,257 Additional liabilities incurred 374 20 Accretion expense 85 82 Liabilities settled (87 ) (288 ) Revision in estimates (1) 1,120 (119 ) ARO, end of period 2,444 952 Less: current portion of ARO (2) (11 ) (226 ) ARO, non-current $ 2,433 $ 726 (1) The significant increase in revision of estimates of $1.1 million for the year ended December 31, 2018 was primarily attributed to increases in plugging and abandonment cost estimates by approximately $50,000 per well. full cost methodpurchaser which generally occurs when production is transferred to the purchaser. The Company measures revenue as the amount of accounting, (iii) depletionconsideration it expects to receive in exchange for the commodities transferred. All of Brushy's fair-valued provedthe Company’s revenues from contracts with customers represent products transferred at a point in time as control is transferred to the customer.(iv)also recorded as accounts receivable in the estimated tax impactsaccompanying condensed consolidated balance sheets. In this scenario, payment is unconditional, as the Company has satisfied its performance obligations through delivery of the pro forma adjustments. The pro forma results of operationsrelevant product. As a result, the Company has concluded that its product sales do not include any cost savingsgive rise to contract assets or other synergiesliabilities under the New Revenue Standard.may resultwas delivered to the customer and the price that will be received for the sale of the product. Additionally, to the extent actual volumes and prices of oil, natural gas and NGLs are unavailable for a given reporting period because of timing or information not received from third-party purchasers, the expected sales volumes and prices for those barrels of oil, cubic feet of gas and gallons of NGL are also estimated. The Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the Mergerpurchaser. The Company has existing internal controls in place for its estimation process, and any identified differences between its revenue estimates and actual revenue received historically have not been significant.any estimated coststhe agent in the contract and, as a result,been or will be incurred by Lilis to integratecontract terms less than one year, the Brushy assets. The pro forma combined financial informationCompany has been included for comparative purposes andutilized the practical expedient in the New Revenue Standard that states that it is not necessarily indicativerequired to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the results that might have actually occurred had the Merger taken place on January 1, 2015; furthermore, the financial informationtransaction price allocated to remaining performance obligations is not intendedrequired. The following table disaggregates the Company’s revenue by contract type (in thousands): Short-term contracts Long-term contracts Total Year Ended December 31, 2018 (in thousands) Crude Oil $ 58,042 $ — $ 58,042 Natural Gas 1,045 4,201 5,246 NGLs 1,381 5,547 6,928 Gathering, processing and transportation (676 ) (2,716 ) (3,392 ) be a projectioncredit risk is through receivables from the sale of futureour oil and natural gas production of approximately $8.2 million at December 31, 2018, and through actual and accrued receivables from our joint interest partners of approximately $11.4 million at December 31, 2018. We are subject to credit risk due to the concentration of our oil and natural gas receivables with our most significant customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. December 31, 2016 2015 (In thousands, except share data) Revenue $ 4,989 $ 3,173 Net loss $ (35,835 ) $ (75,808 ) Net loss attributable to common stockholders $ (45,288 ) $ (76,528 ) Net loss per common share basic and diluted $ (4.00 ) $ (13.32 ) Weighted average shares outstanding: Basic and diluted 11,328,252 5,745,785 6 –7 - FAIR VALUE OF FINANCIAL INSTRUMENTS● 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. F-15Asset Retirement Obligationfair valuedetermination of the Company’s asset retirement obligation liability is calculated at the point of inception by taking into account, the cost of abandoning oil and gas wells, which is based on the Company’s and/or Industry’s historical experience for similar work, or estimates from independent third-parties; the economic lives of its properties, which are based on estimates from reserve engineers; the inflation rate; and the credit adjusted risk-free rate, which takes into account the Company’s credit risk and the time value of money. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs.Executive CompensationIn September 2013, the Company announced the appointment of Abraham Mirman as its new president. In connection with Mr. Mirman’s appointment, the Company entered into an employment agreement with Mr. Mirman (the “Mirman Agreement”). The Mirman Agreement provides for an incentive bonus package that, depending upon the relative performance of the Company’s Common Stock compared to the performance of stocks of certain peer group companies as measured from Mr. Mirman’s initial date of employment through December 31, 2014, may result in a cash bonus payment to Mr. Mirman of up to 3.0 times his base salary. The incentive bonus is recorded as a liability and valued at each reporting period. The Company engaged a valuation firm (“VFIRM”) to complete a valuation of this incentive bonus. As previously announced, on March 30, 2015, the Company entered into an amended and restated employment agreement, which the Company refers to as the Mirman CEO Agreement with Mr. Mirman. The Mirman CEO Agreement also provides for Mr. Mirman to receive a cash incentive bonus if certain production 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, 2016, there was no bonus liability due to Mr. Mirman since the production thresholds were not met by the Company. As of December 31, 2015, the Company provided for $87,000 of the bonus liability which represents the amount earned as of December31, 2015.On March 6, 2015, the Company announced the appointment of Kevin Nanke as its new Executive Vice President and Chief Financial Officer. Mr. Nanke would also receive a cash incentive bonus if certain production thresholds were achieved by the Company and a performance bonus of $100,000 if the Company achieved certain goals set forth in Mr. Nanke’s employment agreement. Mr. Nanke’s new incentive bonus liability was valued by VFIRM at $83,000 at December 31, 2015. As of December 31, 2016, there was no bonus liability due to Mr. Nanke since the production thresholds were not met by the Company. As of December 31, 2015, the Company provided for $69,000 of the liability which represents the amount earned as of that date.On March 16, 2015, the Company entered into an employment agreement with Ariella Fuchs for services to be performed as General Counsel to the Company. Ms. Fuchs will also receive a cash incentive bonus if certain production thresholds are achieved by the Company. Ms. Fuchs’ new incentive bonus liability was valued by VFIRM at $80,000 at December 31, 2015. As of December 31, 2016, there was no bonus liability due to Ms. Fuchs since the production thresholds were not met by the Company. As of December 31, 2015, the Company provided for $67,000 of the liability which represents the amount earned as of that date.Change in Warrant LiabilityOn September 2, 2014, the Company entered into a Consulting Agreement with Bristol Capital, LLC, pursuant to which the Company issued to Bristol a warrant to purchase up to 100,000 shares of Common Stock at an exercise price of $20.00 per share (or, in the alternative, 100,000 options, but in no case both). The agreement has a price protection feature that will automatically reduce the exercise price if the Company enters into another consulting agreement pursuant to which warrants are issued with a lower exercise price, which triggered during fiscal year 2016. On December 31, 2016, the Company revalued the warrants/option using the revised terms as follows: (i) 641,026 total warrants/options issued; (ii) stock price of $3.10; (iii) exercise price of $3.12; (iv) expected life of 2.67 years; (v) volatility of 101%; (vi) risk free rate of 1.38% for a total value of $1.2 million, which adjusted the change in fair value valuation of the derivative by $1.0 million. On December 31, 2015, the Company revalued the warrants/options using the following variables: (i) 100,000 total warrants/options issued (as stated above, the Company will only issue a total of 100,000 shares of Common Stock under the option or the warrant, but no more than 100,000 shares of Common Stock in the aggregate); (ii) stock price of $2.00; (iii) exercise price of $2.00; (iv) expected life of 3.7 years; (v) volatility of 100%; risk free rate of 1.5% for a total value of approximately $44,000, which adjusted the change in fair value valuation of 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 to purchase up to 22,500 shares of Common Stock at an adjusted exercise price of $4.05 with the initial advance, which contains an anti-dilution feature that will automatically 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 issued to the Heartland Bank using the following variables: (i) 22,500 warrants issued; (ii) stock price of $2.00; (iii) exercise price of $ 25.00; (iv) expected life of 4.0 years; (v) volatility of 100%; (vi) risk free rate of 1.5% for a total value of $12,000, which adjusted the change in fair value valuation of the derivative by $12,000 for the year ended December 31, 2015. On December 31, 2016, the Company revalued the warrants using the following variables: (i) 22,500 warrants issued; (ii) stock price of $3.10; (iii) adjusted exercise price of $ 4.05; (iv) expected life of 3.02 years; (v) volatility of 101%; (vi) risk free rate of 1.5% for a total value of approximately $42,000, which adjusted the change in fair value valuation of the derivative by $18,675 for the year ended December 31, 2016.F-16Pursuant to the Merger Agreement and as a condition to the Fourth Amendment (defined below), the Company was required to make a cash payment of $500,000, issue the SOS Note and the SOS Warrant. The SOS Warrant contains a price protection feature that will automatically reduce the exercise price if the Company enters into another financing agreement pursuant to which warrants are issued with a lower exercise price after June 23, 2016. This initial value of $164,000 was recorded as additional Merger consideration. On December 31, 2016, the Company evaluated the SOS Warrant using the following variables: (i) stock price of $3.10 (ii) exercise price of $25.00 (iii) contractual life of 1.48 years; (iv) volatility of 101%; (v) risk free rate of 1.02% for a total value of approximately $144,000, which adjusted the fair value valuation of the derivative by approximately $284,000 for the year ended December 31, 2016.Debentures Conversion Derivative LiabilityAs of December 31, 2015, the Company had $6.85 million in remaining Debentures, which, subject to stockholder approval, were convertible at any time at the holders’ option into shares of Common Stock at $20.00 per share, or 342,323 underlying conversion shares prior to the execution of the Debenture Conversion Agreement. The Debentures have elements of a derivative due to the potential for certain adjustments, including both the conversion option and the price protection embedded in the Debentures. The conversion option allows the Debenture holders to convert their Debentures to underlying Common Stock at a conversion price of $20.00 per share, subject to certain adjustments, including the requirement to reset the conversion for any subsequent offering at a lower price per share amount. The Company values this conversion liability at each reporting period using a Monte Carlo pricing model.On June 23, 2016, pursuant to the terms of the Debenture Conversion Agreement, dated December 29, 2015, the Company's remaining outstanding 8% Convertible Debentures (the “Debentures”) of approximately $6,846,000 converted automatically upon consummation of the Merger. The conversion price was modified from $20.00 per share to $5.00 per share, resulting in the issuance of 1,369,293 shares of Common Stock. Upon the conversion of the Debentures, the associated conversion liability of approximately $43,000 was reclassified to additional paid-in capital. At December 31, 2016 and 2015, the Company valued the conversion feature associated with the Debentures at $0 and $6,000, respectively. As of December 31, 2016, the remaining debentures were fully converted into 1,369,293 shares of the Company’s common stock.The following table provides a summary of the recurring fair values of assets andour derivative contracts incorporates various factors, which include not only the impact of our non-performance risk on our liabilities measured at fair value(in thousands):December 31, 2016 Level 1 Level 2 Level 3 Total Recurring fair value measurements: Warrant liabilities - - (1,400 ) (1,400 ) Total recurring fair value measurements $ - $ - $ (1,400 ) $ (1,400 ) December 31, 2015 Level 1 Level 2 Level 3 Total Recurring fair value measurements: Executive employment agreement $ - $ - $ (223 ) $ (223 ) Warrant liabilities - - (56 ) (56 ) Convertible debenture conversion derivative liability - - (6 ) (6 ) Total recurring fair value measurements $ - $ - $ (285 ) $ (285 ) F-17The following table provides a summary of changes in fair valuebut also the credit standing of the Company’s Level 3counterparties involved. We utilize counterparty rate of default values to assess the impact of non- performance risk when evaluating both our liabilities to, and receivables from, counterparties.assets and liabilities as of December 31, 2016 and 2015(in thousands): Conversion
derivative
liability Bristol/
Heartland/SOS
warrant liability Incentive
bonus Total Balance at January 1, 2016 $ (6 ) $ (56 ) $ (223 ) $ (285 ) Additional liability - (164 ) (393 ) (557 ) Reversal of accrued bonus - - 718 718 Converted to equity (54 ) - - (54 ) Change in fair value of liability 60 (1,180 ) (102 ) (1,222 ) Balance at December 31, 2016 $ - $ (1,400 ) $ - $ (1,400 ) Conversion
derivative
liability
liability Incentive
bonus Total Balance at January 1, 2015 $ (1,249 ) $ (394 ) $ (40 ) $ (1,683 ) Additional liability - (56 ) (149 ) (205 ) Change in fair value of liability 1,243 394 (34 ) 1,603 Balance at December 31, 2015 $ (6 ) $ (56 ) $ (223 ) $ (285 ) Assets and liabilitiesinstruments measured at fair value on a nonrecurring basis.Certainrecurring basis consist of the following: December 31, 2018 2017 Derivative assets (liabilities): Derivative assets - current $ 2,551 $ — Derivative assets - non-current (1) 1,822 — Derivative liabilities - current (515 ) (853 ) Derivative liabilities - non-current (2) (4,699 ) (72,937 ) Total derivative liabilities, net $ (841 ) $ (73,790 ) Fair Value Measurement Classification Total (in thousands) As of December 31, 2018 Oil and natural gas derivative instruments: Oil and natural gas derivative swap contracts $ — $ (2,923 ) $ — $ (2,923 ) Oil and natural gas derivative collar contracts — 4,047 — 4,047 Embedded derivative instruments: Second Lien Term Loan conversion features — — (1,965 ) (1,965 ) Total $ — $ 1,124 $ (1,965 ) $ (841 ) As of December 31, 2017 Oil and natural gas derivative instruments: Oil and natural gas derivative swap contracts $ — $ (706 ) $ — $ (706 ) Oil and natural gas derivative collar contracts — (147 ) — (147 ) Equity instruments: Warrant liabilities — — (223 ) (223 ) Embedded derivative instruments: Second Lien Term Loan conversion features — — (72,714 ) (72,714 ) Total $ — $ (853 ) $ (72,937 ) $ (73,790 ) are measured at fair value on a nonrecurring basis. These assetsinclude unsettled amounts related to commodity derivative positions, including swaps and liabilities are not measured at fair value on an ongoing basis, but are subject to fair value adjustments in certain circumstances. These assets and liabilities can include proved and unproved oil and gas properties and other long-lived assets that are written down to fair value when they are impaired or held for sale.Proved oil and gas properties. The Company estimates the expected undiscounted future cash flowscollars as of its oil and natural gas properties and compares such amounts to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, 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 to management’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, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. These assumptions represent Level 3 inputs. Impairment of oil and gas assets for the year ended December 31, 20162018 and 2015 was $4.7 million and $24.5 million, respectively. following table provides a summary of the non-recurring fair values of assetsthe Company’s derivatives are based on third-party pricing models which utilize inputs that are either readily in the public market which can be corroborated from active markets of broker quotes. Swaps and collars generally have observable inputs and these instruments are classified as Level 2.at fair value(in thousands):December 31, 2016 Level 1 Level 2 Level 3 Total Non-recurring fair value measurements Impairment of proved oil and gas properties - - 4,700 4,700 Total non-recurring fair value measurements $ - $ - $ 4,700 $ 4,700 Non-recurring fair value measurements Impairment of proved oil and gas properties - - 24,500 24,500 Total non-recurring fair value measurements $ - $ - $ 24,500 $ 24,500 The Company did not have any transfers of assets or liabilities between Level 1, Level 2 orusing Level 3 inputs as follows:fair value measurement hierarchy during the years ended December 31, 2016 and 2015.F-18NOTE 7 – ASSET RETIREMENT OBLIGATIONS (ARO)The information below reconciles the valueCompany’s second lien credit agreement, dated as of the asset retirement obligation for the periods presented (in thousands): Year Ended December 31, 2016 2015 (In thousands) Balance, beginning of year $ 208 $ 200 Liabilities assumed from the Merger 777 - Liabilities incurred 311 - Accretion expense 132 10 Conveyance of liability with oil and gas properties conveyance (92 ) - Change in estimate (79 ) (1 ) Balance, end of year 1,257 209 Less: current portion of ARO at end of year (338 ) - Total Long-term ARO at end of year $ 919 $ 209 NOTE 8 – LONG-TERM DEBTS As of December 31, 2016 2015 (In thousands) Term Loan: 6% Senior Secured Term Loan, due 2019, net of deferred financing costs and debt discount $ 29,214 $ - Senior Secured Term Loan, interest at prime rate, due 2018, net of deferred financing costs and debt discount - 2,492 6% note payable to SOS Investment, LLC, due 2019 1,000 - Convertible Notes: 12% convertible related party note, due 2016, net of deferred financing costs and debt discount - 1,055 12% convertible non-related party note, due 2016, net of deferred financing costs and debt discount - 674 Convertible Debentures: 8% convertible debentures, due 2018, net of deferred financing costs and debt discount 6,846 Other notes payable 29 - $ 30,243 $ 11,067 Less: current portion (17 ) (11,067 ) $ 30,226 $ - Credit and Guarantee AgreementOn September 29, 2016, the Company entered into a credit and guaranty agreement (the “Credit and Guarantee Agreement”)April 26, 2017, by and among the Company, and its wholly ownedcertain subsidiaries Brushy, ImPetro Operating, LLC (“Operating”of the Company, as guarantors (the “Guarantors”) and ImPetro Resources, LLC (“Resources”, and together with Brushy and Operating, the “Initial Guarantors”Wilmington Trust, National Association, as administrative agent (the “Agent”), and the lenders party thereto (each(the “Lenders”), including Värde as lead lender (the “Lead Lender”), as amended (the “Second Lien Credit Agreement”), the Lead Lender has the option to convert“Lender”discount rate equal to the Treasury Rate plus 50 basis points discounted to the repayment, prepayment or acceleration date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months), over (b) the principal amount of the Second Lien Term Loan repaid, prepaid or accelerated. The number of shares of common stock issued will be based on the division of 70% of the Conversion Sum by the conversion price then in effect.together,bifurcated from its host contracts, the “Lenders”)Second Lien Term Loan, and T.R. Winston &accounted for separately from the debt. The conversion features contained in the Second Lien Term Loan are recorded as a derivative liability at fair value each reporting period based upon values determined through the use of discounted lattice models of the Second Lien Term Loan under the Second Lien Credit Agreement. Change in fair value is accounted for in the consolidated statement operations. On October 10, 2018, the Company LLC (“TRW”) actingexecuted Amendment No. 6 to the Second Lien Credit Agreement for an exchange transaction of approximately $68.3 million claim amount of its Second Lien Term Loan for a combination of 5,952,763 shares of the Company’s common stock representing a claim value of $29.0 million and issuance of 100,000 shares of Series D Preferred Stock representing a claim value of $39.3 million. As a result of the exchange transaction, the fair value of the remaining embedded derivative liability decreased by $12.4 million as of October 10, 2018. The Company recorded an unrealized gain of $58.3 million and an unrealized loss of $7.1 million on the change in fair value of derivative liabilities associated with the Second Lien Term Loan conversion features for the years ended December 31, 2018 and 2017, respectively. Total (in thousands) Balance at January 1, 2018 $ (72,714 ) $ (223 ) $ (72,937 ) Transferred to equity — 223 223 Fair value of the converted portion of the embedded derivatives associated with the Second Lien Term Loan 12,406 — 12,406 Change in fair value of derivative liabilities 58,343 — 58,343 Balance at December 31, 2018 $ (1,965 ) $ — $ (1,965 ) Total (in thousands) Balance at January 1, 2017 $ — $ (1,400 ) $ (1,400 ) Issuance (65,647 ) — (65,647 ) Cashless exercise of warrants — 370 370 Change in fair value of derivative liabilities (7,067 ) 807 (6,260 ) Balance at December 31, 2017 $ (72,714 ) $ (223 ) $ (72,937 ) agent. 2019 2020 Oil positions: Oil swaps (NYMEX WTI): Hedged Volume (Bbls) — 277,685 Average price ($ per Bbl) $ — $ 56.21 Basis swaps (NYMEX WTI): Hedged Volume (Bbls) 909,500 547,500 Average price ($ per Bbl) $ (6.85 ) $ (5.62 ) Put Options (NYMEX WTI): Hedged Volume (Bbls) 1,095,000 — Average price ($ per Bbl) $ 50.41 $ — Call Options (NYMEX WTI): Hedged Volume (Bbls) 638,000 — Average price ($ per Bbl) $ 69.76 $ — Natural gas positions: Gas swaps (NYMEX Henry Hub): Hedged Volume (MMBtu) 906,238 714,134 Average price ($ per MMBtu) $ 2.75 $ 2.54 Put Options (NYMEX Henry Hub): Hedged Volume (MMBtu) 392,481 144,130 Average price ($ per MMBtu) $ 3.05 $ 2.80 Call Options (NYMEX Henry Hub): Hedged Volume (MMBtu) 392,481 144,130 Average price ($ per MMBtu) $ 3.58 $ 3.06 Year Ended December 31, 2018 2017 (In thousands) Unrealized gain (loss) on unsettled derivatives $ 1,977 $ (853 ) Net settlement paid on derivative contracts (2,742 ) (96 ) Net settlement receivable (payable) on derivative contracts 820 (114 ) Net gain (loss) on commodity derivatives $ 55 $ (1,063 ) December 31, 2018 (in thousands) Offsetting Derivative Assets: Current assets $ 4,122 $ (1,571 ) $ 2,551 Long-term assets 1,854 (32 ) 1,822 Total assets $ 5,976 $ (1,603 ) $ 4,373 Offsetting Derivative Liabilities: Current liabilities $ (2,086 ) $ 1,571 $ (515 ) Long-term commodity derivative liabilities (2,766 ) 32 (2,734 ) Long-term embedded derivative liabilities (1,965 ) — (1,965 ) Total liabilities $ (6,817 ) $ 1,603 $ (5,214 ) December 31, 2017 (in thousands) Offsetting Derivative Assets: Current asset $ — $ — $ — Long-term asset — — — Total asset $ — $ — $ — Offsetting Derivative Liabilities: Current liabilities $ (853 ) $ — $ (853 ) Long-term commodity derivative liabilities — — — Long-term embedded derivative liabilities (72,937 ) — (72,937 ) Total liabilities $ (73,790 ) $ — $ (73,790 ) As of December 31, 2018 2017 (In thousands) 6% bridge loans associated with the amended First Lien Term Loan, due 2019, net of debt issuance costs $ — $ 30,363 8.25% Second Lien Term Loan, due 2021, net of debt issuance costs and debt discount 82,804 96,431 Revolving Credit Agreement, due April 2021 75,000 — Other notes payable, due 2018 and 2019 — 1,011 Total long-term debt $ 157,804 $ 127,805 Less: current portion — (11 ) Total long-term debt, net of current portion $ 157,804 $ 127,794 (in thousands) As of December 31, 2018 Revolving Credit Agreement, due April 2021 $ 75,000 $ — $ — $ 75,000 Second Lien Term Loan, due April 2021 100,000 11,641 (28,837 ) 82,804 Total: $ 175,000 $ 11,641 $ (28,837 ) $ 157,804 As of December 31, 2017 Bridge loans associated with the amended First Lien Term Loan, due September 2019 $ 30,000 $ 807 $ (444 ) $ 30,363 Second Lien Term Loan, due April 2021 150,000 5,752 (59,321 ) 96,431 Total: $ 180,000 $ 6,559 $ (59,765 ) $ 126,794 Guaranteeamong the Company, as borrower, certain subsidiaries of the Company, as guarantors (the “Guarantors”), BMO Harris Bank, N.A., as administrative agent, and the lenders party thereto. The Revolving Credit Agreement provides for a three-year senior secured term loanreserve based revolving credit facility with an initial commitmentsborrowing base of $31$95.0 million. The borrowing base is subject to semiannual re-determinations in May and November of each year. On December 7, 2018, the Company’s borrowing base under the Revolving Credit Agreement was increased to $108 million as a result of which $25 million was collected asits regularly scheduled fall redetermination process.September 30, 2016,either LIBOR or a specified base rate plus a margin determined based upon the usage of the borrowing base. The Company is required to pay a commitment fee ofadditional $6 million was collected at December 31, 2016. The initial aggregate principal amount may be increased to a maximum principal amount of $50 million at the Company’s requestGuarantors’ assets and with the consent of the Lenders holding loans in excess of 60% of the then outstanding loans pursuant to an accordion advance provision in the Credit and Guarantee Agreement (the “Term Loan”).In connection with the Company’s entry into the Credit and Guarantee Agreement, it incurred commitment fees toare unconditionally guaranteed by each of the Lenders equalGuarantors.2.0%repay in full and retire the Company’s previously existing $50.0 million Riverstone First Lien Credit Agreement (the credit agreement for which was amended and restated by the Revolving Credit Agreement), including accrued interest and a prepayment premium, and to pay transaction expenses. Future borrowings may be used to fund working capital requirements, including for the acquisition, exploration and development of their respective initial loan advancesoil and advisory fees totaledgas properties, and for general corporate purposes. The Revolving Credit Agreement also provides for issuance of letters of credit in an aggregate amount up to approximately $1.2 million as$5.0 million. As of December 31, 2016. 2018, the outstanding balance under the Revolving Credit Agreement was $75.0 million.accounted forcapitalizes certain direct costs associated with the $1.2 million as deferred financingissuance of the Revolving Credit Agreement and amortizes such costs to be amortized over the term of the loan. As partial consideration givendebt instrument. The deferred financing costs related to the lenders, we also amended certain warrants issuedRevolving Credit Agreement are classified in the Series B preferred stock offering held by the lenders during the third and fourth quarters of the year ended December 31, 2016, to purchase up to an aggregate amount of approximately 2,850,000 and approximately 672,000, shares of common stock respectively, such that the exercise price per share was lowered from $2.50 to $0.01 on such warrants. The portion repriced in the fourth quarter was due to certain delayed funding that occurred after the initial commitment. Additionally, each lender received a 2.0% commitment fee equal to their respective initial loan advance. All of the amended warrants are immediately exercisable from the original issuance date, for a period of two years, subject to certain conditions. The Company accounted for the reduction in the conversion price as a debt discount of $714,000 and will be accreted over the term of the loan.assets. For the year ended December 31, 2016,2018, the Company amortized approximately $108,000debt issuance costs associated with revolving credit agreements of deferred financing costs and accreted approximately $119,000 of debt discount relating to$2.2 million. For the loan. These amounts were recorded as a component of non-cash interest expense.year ended December 31, 2017, the Company had no revolving credit agreements. As of December 31, 2016,2018, the unamortized portionCompany has $0.5 million and $1.7 million of the debt discount andunamortized deferred financing costs were $0.6 millionin other current assets and $1.2 million,non-current assets, respectively.F-19Term Loan bears interest at a rate of 6.0% per annum andRevolving Credit Agreement matures on September 30, 2019.the earlier of the fifth anniversary of the closing date and the date that is 180 days prior to the maturity date of the Company’s Second Lien Credit Agreement (as defined below). Borrowings under the Revolving Credit Agreement are subject to mandatory repayment with the net proceeds of certain asset sales and debt incurrences or if a borrowing base deficiency occurs. The Company hasalso may voluntarily repay borrowings from time to time and, subject to the rightborrowing base limitation and other customary conditions, may reborrow amounts that are voluntarily repaid. Mandatory and voluntary repayments generally will be made without premium or penalty.prepaymaintain a ratio of Total Debt to EBITDAX of not more than 4.00 to 1.00 and a ratio of current assets to current liabilities of not less than 1.00 to 1.00 (each as defined in the Term Loan, in whole or in part, at any time at a prepayment premium equalRevolving Credit Agreement). On October 10, 2018, the Company entered into the Revolving Credit Agreement pursuant to 6.0%which BMO Harris Bank N.A., SunTrust Bank, Capital One, N.A., and Credit Suisse AG, Cayman Islands Branch, (collectively, the “Lenders”) have made certain credit available to and on behalf of the amount repaid. Such prepayment premium must also be paid ifCompany. In connection with the Term Loan is repaid prior to maturity as a resultpreparation of a changethese financial statements, the Company informed its Lenders, that it did not satisfy the leverage ratio covenant in control. In certain situations, the Credit and Guarantee Agreement requires mandatory prepaymentsSection 9.01(a) of the Term Loans at the requestRevolving Credit Agreement, as of the fiscal quarter ended December 31, 2018. Accordingly, the Company recevied the Lenders including in the event of certain non-ordinary course asset sales, the incurrence of certain debt, and receipt of proceeds in connectionconsent to a waiver with insurance claims. and Guarantee Agreement also provides for events of default, including failure to pay any principal, interest or interestother amounts when due, failure to perform or observe covenants, cross-default on certain outstanding debt obligations, inaccuracy of representations and warranties, certain ERISA events, change of control, the failure of a Guarantorsecurity documents or guaranty ceasing to comply with the provisions of its Guaranty,be effective, and bankruptcy or insolvency events. The amountsevents, subject to customary cure periods. Amounts owed by the Company under the Revolving Credit Agreement could be accelerated and bebecome immediately due and payable uponfollowing the occurrence an event of default.Investment LLC NoteMerger Agreementmerger agreement with Brushy and as a condition of the Fourth Amendment,fourth amendment to such merger agreement, the Company was required to make a cash payment of $500,000 to SOSV LLC,SOS, and also executed a subordinated promissory note with SOSV LLC,SOS, for $1$1.0 million, at an interest rate of 6% per annum which matures on June 30, 2019. In conjunction with the cash payment and the note, the Company also issued 200,000 warrants at an exercise price of $25.00. The Company accounted for the cost of warrants of $0.2 million as part of the MergerBrushy merger transaction costs forduring the year ended December 31, 2016.Independent Bank The SOS note was fully paid on January 22, 2018. Year Ended December 31, 2018 2017 (in thousands) Interest on bridge loans associated with First Lien Term Loan $ 728 $ 1,774 Interest on Revolving Credit Agreements 2,242 — Interest on Notes Payable 5 53 Paid-in-kind interest on First Lien Term Loan and Second Lien Term Loan 12,213 6,559 Amortization of debt financing costs on Second Lien Term Loan and Revolving Credit Agreement 3,241 1,886 Amortization of discount on Second Lien Term Loan 14,398 8,485 Total: $ 32,827 $ 18,757 Promissory NoteOn June 22, 2016, in connectiondisposal agreement with SCM Water, LLC (“SCM Water”). The water gathering project will complement the completionCompany’s existing water disposal infrastructure, and the Company has reserved the right to recycle its produced water. SCM Water will commence, upon receipt of regulatory approval, to build out new gathering and disposal infrastructure to all of the Merger,Company’s current and future well locations in Lea County, New Mexico, and Winkler County, Texas. All future capital expenditures will be fully funded by SCM Water and will be designed to accommodate all water produced by the Company’s operations. The Company will act as contract operator of SCM Water’s salt water disposal (“SWD Wells”). The Company has sold to SCM Water an option to acquire the Company’s existing water infrastructure, a system which is comprised of approximately 14 miles of pipeline and one SWD well for cash consideration upon closing, with additional payments based on reaching certain milestones.Brushyreceived an upfront non-refundable payment of $10.0 million for the option to acquire its existing water infrastructure for the firm transportation and Independent Bankpricing for crude oil and $5.0 million for a prefunded drilling bonus. Additionally, the Company received $2.5 million on October 1, 2018 for the right-of-way/easement bonus and would receive an additional $2.5 million upon hitting the target of 40,000 barrels per day of produced water. As of December 31, 2018, the Company recorded the $17.5 million as deferred revenue until such time as SCM Water exercises its option to acquire the Company’s salt water disposal infrastructure.“Lender”“Gathering Agreement”), Brushy’s senior secured lender, enables SCM to (i) design, engineer, and construct a gathering system which will provide gathering services for the Company’s crude oil and (ii) gather the Company’s crude oil on the gathering system in certain production areas located in Winkler and Loving Counties, Texas and Lea County, New Mexico. Construction of the gathering system has commenced and is expected to be completed in November 2018. The Gathering Agreement has a term of 12 years that automatically renews on a year to year basis until terminated by either party. SCM and the Company also entered into an amendmentoption agreement (the “Option Agreement”) whereby the Company granted an option to Brushy’s forbearance agreementSCM to provide certain midstream services related to natural gas in Winkler and Loving Counties, Texas and Lea County, New Mexico, subject to the expiration and terms of the Company’s existing gas agreement. The Option Agreement has a term commencing May 21, 2018 and terminating January 1, 2027, pursuant to its one-time option. As consideration for this option, the Company received a one-time of payment $35.0 million which was recorded in long-term deferred revenue. Year Ended December 31, Related Party Transactions 2018 2017 ($ in thousands) Brennan Short (former Chief Operating Officer) Consulting fees paid to MMZ Consulting, Inc. (“MMZ”) which is owned by Mr. Short. Mr. Short is the sole member of MMZ. $ — $ 204 Total: $ — $ 204 Kevin Nanke (former Chief Financial Officer) Purchased the DJ Basin properties from the Company through Nanke Energy, LLC $ — $ 2,000 Total: $ — $ 2,000 Värde Partners, Inc. (“Värde”) (1) The Company acquired oil and natural gas interests from VPD, an affiliate of Värde $ 10,705 $ — ImPetro Operating, LLC, a wholly-owned subsidiary of the Company is the operator for two of VPD's producing wells and VPD reimbursed the Company for operating overhead charges. 44 — Receivable balance outstanding as of December 31, 2018 for operating costs associated with the VPD's producing wells 1,843 — Total: $ 12,592 $ — Lender (the “Fourth Amendment”),lead lender in the Company’s Second Lien Loans (see Note 9 – Long-term Debt) and also participated in the issuances of the Preferred Stock in January and October 2018 (see Note 13 – Mezzanine Preferred Stock). December 31, 2018 2017 (in thousands) U.S. Federal: Current $ — $ — Deferred (7,496 ) 32,579 State and local: Current — — Deferred 509 1,059 (6,987 ) 33,638 Change in valuation allowance 6,987 (33,638 ) Income tax provision $ — $ — December 31, 2018 2017 (In thousands) Deferred tax assets: Net operating loss carry-forward $ 27,568 $ 15,653 Share based compensation 808 784 Abandonment obligation 541 212 Derivative instruments — 191 Deferred revenue 11,630 — Interest expense 3,804 — Accrued liabilities and other 85 52 Total deferred tax asset 44,436 16,892 Valuation allowance (23,611 ) (16,624 ) Deferred tax asset, net of valuation allowance $ 20,825 $ 268 Deferred tax liabilities: Derivative instruments 249 — Oil and natural gas properties and equipment 20,576 268 Total deferred tax liability 20,825 268 Net deferred tax asset (liability) $ — $ — Year Ended December 31, 2018 2017 Effective federal tax rate 21.00 % 34.00 % State tax rate, net of federal benefit 2.06 % 1.11 % Effect of the Tax Cuts and Jobs Act — % -11.22 % Change in fair value derivative liability 295.70 % -2.59 % Debt discount amortization -72.97 % -3.51 % Share based compensation differences and forfeitures — % 0.91 % Change in rate -6.40 % -0.05 % Other permanent differences -5.69 % -4.61 % NOL true-up - §382 limitation -5.51 % -47.22 % Loss from early debt extinguishment -59.01 % — % Other -0.56 % -6.47 % Valuation allowance -168.62 % 39.65 % Net — % — % among other things, providedoccurred in the current and prior tax years. The Company is currently in the process of determining the effect of the current change in ownership on the net operating loss carryforwards, including the analysis of net unrealized built-in-gains that will ultimately effect the overall limitation. The conclusion of the additional analysis under Section 382 will have no effect on the Company’s effective income tax rate or the amount of the present valuation allowance position. pay-downvaluation allowance on the Company’s deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon whether future book income is sufficient to reverse existing temporary differences that give rise to deferred tax assets, as well as whether future taxable income is sufficient to utilize net operating loss and credit carryforwards. Assessing the need for, or the sufficiency of, a valuation allowance requires the evaluation of all available evidence, both positive and negative. Negative evidence considered by management includes cumulative book and tax losses in recent years, no taxable income in available carryback years, and no tax planning strategies contemplated to realize the valued deferred tax assets.$6.0$23.6 million and $16.6 million on its deferred tax assets as of December 31, 2018 and 2017, respectively.principal amount outstandingtax effects of the Act for annual periods that include December 22, 2017. At December 31, 2017, the Company made reasonable estimates of the effects on its existing deferred tax balances. The Company remeasured certain federal deferred tax assets and liabilities based on the loan (the “Loan”), plus feesrates at which they are expected to reverse in the future, which is generally twenty one percent. The amount recognized related to the remeasurement of its federal deferred tax balance was $9.5 million, which was subject to a valuation allowance at December 31, 2017.expenses incurred in connection with the Loan, in exchange for an extensionprovisions of the maturity date through December 15, 2016, at an interest ratetax reform. This further analysis could potentially affect the measurement of 6.5%deferred tax balances or potentially give rise to new deferred tax amounts.payable monthly. Additionally,pursuant to which the Company agreed to (i) guarantyissue and sell to the approximately $5.4 million aggregate principal amountPurchasers, and the Purchasers agreed to purchase from the Company, 100,000 shares of a newly created series of preferred stock of the Loan, (ii) grantCompany, designated as “Series C 9.75% Convertible Participating Preferred Stock” (the “Series C Preferred Stock”), for a lien in favorpurchase price of $1,000 per share, or an aggregate of $100.0 million. The terms of the Lender on allSeries C Preferred Stock were set forth in the Certificate of Designation for the Series C Preferred Stock (the “Amended and Restated Certificate of Designation”) filed by the Company with the Secretary of State of the Company’s real and personal property, (iii) restrict the incurrenceState of additional debt and (iv) maintain certain deposit accounts with various restrictions with the Lender. On September 29, 2016, in connection with the Company’s entry into the Credit and Guarantee Agreement, the Company used partNevada on January 31, 2018. Closing of the proceedsissuance and sale of the Term Loanshares of Series C Preferred Stock pursuant to repay the balance of Brushy’s outstanding indebtedness with Independent Bank in full.Heartland BankJanuary 8, 2015,April 26, 2017, the Company entered into the Second Lien Credit Agreement (as defined above in Note 9 - Long Term Debt) under which Värde is the lead lender, and certain private funds affiliated with Heartland Bank (the “Credit Agreement”), as administrative agent and the Lenders party thereto. The Credit Agreement provided for a three-year senior secured term loan in an initial aggregate principal amount of $3 million, or the Term Loan.Värde are lenders). On December 29, 2015, after a default on an interest payment and in connection with the Merger, the Company entered into the Forbearance Agreement with Heartland (the “Heartland Forbearance Agreement”). The Heartland Forbearance Agreement, restricted Heartland from exercising any of its remedies until April 30, 2016, which was subject to certain conditions, including a requirement for the Company to make a monthly interest payment to Heartland.Following the First Amendment to the Credit Agreement entered into on March 1, 2016, on May 4, 2016, as a result of a default on the required March 1, April 1 and May 1 interest payments pursuant to the Forbearance Agreement,October 10, 2018, the Company entered into a second amendment to the ForbearanceTransaction Agreement (the “Second Amendment”“Transaction Agreement”). Pursuant to the Second Amendment, the limit on the amount of New Subordinated Debt, by and among the Company had been permittedand certain private funds affiliated with Värde Partners, Inc. (the “Värde Parties”), pursuant to raise was eliminated and the Forbearance Expiration Date was extended to May 31, 2016. As consideration for the forgoing,which the Company paid Heartland(i) exchanged approximately $68.3 million of the overdue interest owedloans under its Second Lien Credit Agreement for a combination of a Series D Preferred Stock and Common Stock (as such terms are hereinafter defined) and (ii) agreed to a tack-on issuance and sale to Värde Parties of a new subseries of Series C Preferred Stock. Specifically, pursuant to the Term Loan and interest due through June 23, 2016 in the approximate amount of $160,000 and reimbursement of a portion of Heartland’s fees and expenses in an approximate amount of $53,000. During the year ended December 31, 2016,Transaction Agreement, the Company amortized approximately $38,000 of debt discount. This amount is recorded as a component of non-cash interest expense. As of December 31, 2016 and 2015,agreed to:unamortized deferred financing costs were $0 and $38,000, respectively.In connection with the consummation of the Merger, on June 23, 2016, the Company repaid the entire balance of its outstanding indebtedness with Heartland at a discount of $250,000 (recognized as a gain in other income (expense), resulting in the elimination of $2.75 million in senior secured debt and the extinguishment of Heartland’s security interest in the assets of the Company.F-20Convertible NotesFrom December 29, 2015 to January 5, 2016, the Company entered into 12% Convertible Subordinated Note Purchase Agreements with various lending parties, which the Company refers to as the Purchasers, for the issuance of an aggregate principal amount of $3.75 million unsecured subordinated convertible notes, or the Convertible Notes, which includes the $750,000 of short-term notes exchanged for Convertible Notes by the Company and warrants to purchase up toVärde Parties (i) an aggregate of approximately 1,500,0005,952,763 shares of the Company’s common stock, par value $0.0001 per share (the “Common Stock”), which includes 5,802,763 shares of Common Stock at an exerciseexchange price of $2.50$5.00 per share.share of Common Stock plus an additional 150,000 shares of Common Stock, and (ii) 39,254 shares of a newly created series of preferred stock of the Company, designated as “Series D 8.25% Convertible Participating Preferred Stock” (the “Series D Preferred Stock”), as consideration for the reduction by approximately $56.3 million of the outstanding principal amount of the Second Lien Term Loan under the Second Lien Credit Agreement, together with accrued and unpaid interest and the make-whole amount thereon totaling approximately $11.9 million;this financing were usedthe sale of the shares of Series C-2 Preferred Stock for general corporate purposes, including the acquisition, exploration and development of oil and natural gas properties. Number of Series C-1 Preferred Shares Series C-1 Preferred Stock Number of Series C-2 Preferred Shares Series C-2 Preferred Stock Number of Series D Preferred Shares Series D Preferred Stock Total (In thousands, except shares) Balance, January 1, 2018 — $ — — $ — — $ — $ — Issuance of Preferred Stock 100,000 100,000 25,000 25,000 39,254 39,919 164,919 Transaction costs (1) — (2,494 ) — (87 ) — — (2,581 ) Net Proceeds 100,000 97,506 25,000 24,913 39,254 39,919 162,338 Paid-in-kind dividends — 9,268 — 609 — 810 10,687 Balance, December 31, 2018 100,000 $ 106,774 25,000 $ 25,522 39,254 $ 40,729 $ 173,025 Stated value per share $ 1,093 $ 256 $ 407 paythe Series C Preferred Stock, and the Series C Preferred Stock ranks senior to the Common Stock with respect to dividends and rights on the liquidation, dissolution or winding up of the Company.$2 million refundable depositper share stated value of $1,000, subject to increase in connection with the Merger,payment of dividends in kind (the “Stated Value”).fund approximately $1.3receive cumulative preferential dividends, payable and compounded quarterly in arrears on January 1, April 1, July 1 and October 1 of each year, commencing April 1, 2018, at an annual rate of 9.75% of the Stated Value for the Series C Preferred Stock and 8.25% of the Stated Value for the Series D Preferred stock until April 26, 2021, after which the annual dividend rate will increase to 12.00% if paid in full in cash or 15.00% if not paid in full in cash. Dividends are payable, at the Company’s option, (i) in cash, (ii) in kind by increasing the Stated Value by the amount per share of the dividend, or (iii) in a combination thereof. In addition to these preferential dividends, holders of the Preferred Stock will be entitled to participate in any dividends paid on the Common Stock on an as-converted basis. As of December 31, 2018, the Company accrued a cumulative balance of $10.7 million of interest paymentsPIK dividends for the Preferred Stock as presented in the above table.Company’s lenders and for its working capital and accounts payable.The Convertible Notes bear interest at a rate of 12% per annum, payable at maturity on June 30, 2016. The Convertible Notes and the accrued but unpaid interest thereon are convertibleSeries C Preferred Stock, in whole or in part, fromat any time (subject to certain limitations on partial redemptions), at a price per share equal to (i) the Stated Value then in effect multiplied by (a) 120% if redeemed during 2018, (b) 125% if redeemed during 2019 or (c) 130% if redeemed after 2019, plus (ii) accrued and unpaid dividends thereon and any other amounts payable by the Company in respect thereof (the “Series C Optional Redemption Amount”). The Company has the right to redeem the Series D Preferred Stock, in whole or in part at any time (subject to certain limitations on partial redemptions), at a price per share equal to (i) the Stated Value then in effect multiplied by 117.5%, plus (ii) accrued and unpaid dividends thereon and any other amounts payable by the Company in respect thereof (the “Series D optional Redemption Amount”). Each Series of the Preferred Stock is perpetual and is not mandatorily redeemable at the option of the holders, except upon the occurrence of a Change of Control (as defined in the Certificates of Designation) as described below.holders thereofholder into a number of shares of the Company’s Common Stock atequal to (i) the applicable Series C Optional Redemption Amount divided by (ii) a conversion price of $5.00. The Convertible Notes may be prepaid in whole or in part (but with payment$6.15, subject to adjustment (the “Series C Conversion Price”). Each share of accrued interest to the date of prepayment)Series D Preferred Stock is convertible at any time at a premium of 103% for the first 120 days and a premium of 105% thereafter, so long as no Senior Debt is outstanding. The Convertible Notes contain customary events of default, which, if uncured, entitle each noteholder to accelerate the due dateoption of the unpaid principal amountholder into a number of shares of Common Stock equal to (i) the Series D Optional Redemption Amount divided by (ii) a conversion price of $5.50, subject to adjustment (the "Series D Conversion Price" and, all accruedtogether with the Series C Conversion Price, the “Conversion Prices”). The Conversion Prices will be subject to proportionate adjustment in connection with stock splits and unpaid interest,combinations, dividends paid in stock and similar events affecting the outstanding Common Stock. Additionally, the Conversion Prices will be adjusted, based on a broad-based weighted average formula, if the Company issues, or is deemed to issue, additional shares of Common Stock for consideration per share that is less than the lesser of (i) $5.25 and (ii) the applicable Conversion Price then in effect, subject to certain subordination provisions.Additionally,exceptions and to the applicable Share Cap (as defined below).March 18, 2016,the principal exchange on which it is then traded has been at least 140% of the applicable Conversion Price then in effect for at least 20 of the 30 consecutive trading days immediately preceding the exercise by the Company issued an additional aggregate principal amount of $500,000 of Convertible Notes, which have the same terms and conditions as the Convertible Notes with the exception of the maturity date, which is April 1, 2017. The proceeds from these Convertible Notes were used to make advances to Brushy for payment of operating expenses pending completionforced conversion right and (ii) certain trading and other conditions are satisfied.Merger. These notes were fully converted followingNYSE American (on which the consummationCommon Stock is traded), the Certificates of Designation provide that the number of shares of Common Stock issuable on conversion of a share of Preferred Stock may not exceed (i) in the case of the Merger.In connection withSeries C-1 Preferred Stock (a) the closing ofStated Value divided by (b) $4.42 (which was the Merger, on June 23, 2016, certain holders of Convertible Notes in an aggregate principal amount of approximately $4.0 million entered into a Conversion Agreement with the Company (the "Note Conversion Agreement"). The terms of the Note Conversion Agreement provided that the Convertible Notes were automatically converted into Common Stock upon the closing of the Merger. Pursuant to the terms of the Note Conversion Agreement, in exchange for immediate conversion upon closing, the conversion price of the Convertible NotesCommon Stock on the NYSE American on January 30, 2018) (the “C-1 Share Cap”) or (ii) in the case of the Series C-2 Preferred Stock and the Series D Preferred Stock (a) the Stated Value divided by (b) $4.41 (which was reducedthe closing price of the Common Stock on the NYSE American on October 9, 2018) (together with the C-1 Share Cap, the “Share Caps”), in each case prior to $1.10, which resulted inthe receipt of shareholder approval of the issuance of 3,636,366shares of Common Stock.The modification of such conversion rate resulted in a $3.4 million inducement charge recorded in other expense. Holders of these Convertible Notes waived and forfeited approximately $198,000 rights to receive accrued but unpaid interest.On August 3, 2016, the Company entered into the first amendment to the Convertible NotesWhen voting together with the remaining holdersCommon Stock, each share of approximately $1.8 millionPreferred Stock will entitle the holder to a number of Convertible Notes. Pursuantvotes equal to the first amendment: (i) the maturityapplicable Stated Value as of the applicable record date was changed to January 2, 2017,or other determination date divided by (ii) the conversion price was adjusted to $1.10 and (iii) the coupon rate was increased to 15% per annum. All accrued and unpaid interest on the Convertible Notes would also be convertible in certain circumstances at the conversion price. Additionally, if the aggregate principal amount outstanding on the Convertible Notes was not either converted by the holder or repaid in full on or before the maturity date, the Company agreed to pay a 25% premium on the maturity date. The Company accounted for the reduction(a) in the conversioncase of Series C-1 Preferred Stock, $4.42 (the closing price of remaining outstanding convertible notes as an inducement expense and recognized approximately $1.6 million in other income (expense). In exchange for the holders’ willingness to enter into the first amendment, the Company issued to the holders additional warrants to purchase up to approximately 1.65 million shares of Common Stock. The warrants issued were valued using the following variables: (i) stock price of $1.12; (ii) exercise price of $2.50; (iii) contractual life of 3 years; (iv) volatility of 203%; (v) risk free rate of 0.76% for a total value of approximately $1.63 million. This amount was recorded as an inducement expense and an increase to additional paid-in capital.On September 29, 2016, in connection with the Company’s entry into the Credit and Guarantee Agreement the remaining holders of the Convertible Notes converted the outstanding principal amount of approximately $1.8 million and accrued and unpaid interest in an amount of approximately $138,000 into 1,772,456 shares of Common Stock.Convertible DebenturesIn numerous separate private placement transactions between February 2011 and October 2013, the Company issued an aggregate of approximately $15.6 million of Debentures, secured by mortgages on several of its properties. On January 31, 2014, the Company entered into a debenture conversion agreement (the “First Conversion Agreement”) with all of the holders of the Debentures.F-21Pursuant to the terms of the First Conversion Agreement, $9.0 million in Debentures (approximately $8.73 million of principal and $270,000 in interest) was converted by the holders to shares of Common Stock at a conversion price of $20.00 per share. In addition, the Company issued warrants to the Debenture holders 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 $25.00 per share.Under the terms of the First Conversion Agreement, the balance of the Debentures may be converted to Common Stock on the terms provided therein (includingNYSE American on January 30, 2018), and (b) in the terms related to the warrants) at the electioncase of Series C-2 Preferred Stock and Series D Preferred Stock, $4.41 (the closing price of the holder, subject to receipt of stockholder approval as required by Nasdaq continued listing requirements.On December 29, 2015, the Company entered into a second agreement with the holders of its Debentures, which provides for the full automatic conversion of Debentures into shares of the Company’s Common Stock at a price of $5.00 per share, upon the receipt of requisite stockholder approval and the consummation of the Merger. If the Debentures are converted on these terms, it would result in the issuance of 1,369,293 shares of Common Stock and the elimination of $8.08 million in short-term debt obligations including accrued but unpaid interest which would be forfeited and cancelled upon conversion pursuant to the terms of the agreement.On June 23, 2016, pursuant to the terms of the Debenture Conversion Agreement, dated December 29, 2015, the Company's remaining outstanding 8% Convertible Debentures (the “Debentures”) of approximately $6,846,000 converted automatically upon consummation of the Merger. The conversion price was modified from $20.00 per share to $5.00 per share, resulting in the issuance of 1,369,293 shares of Common Stock. In exchange for the reduction in conversion price, all accrued but unpaid interest of approximately $1,835,000 was forgiven by the Debenture holders, resulting in a net gain on the modification and conversion of the Debentures of approximately $602,000 and recorded as other income and expenses in the accompanying consolidated statements of operations. Upon the conversion of the Debentures, the associated conversion liability of approximately $43,000 was reclassified to additional paid-in capital. There were no unamortized deferred financing costs and debt discount at December 31, 2016 and 2015, respectively.Interest ExpenseInterest expense for the years ended December 31, 2016 and 2015 was approximately $4.9 million and $1.7 million, respectively. The non-cash interest expense during the years ended December 31, 2016 and 2015 was approximately $4.2 million and $1.3 million, respectively. The non-cash interest expenses consisted of non-cash interest expense and amortization of the deferred financing costs, accretion of the Debentures payable discount, and Debentures interest paid in Common Stock.NOTENYSE American on October 9, – COMMITMENTS AND CONTINGENCIESEnvironmental and Governmental RegulationAt December 31, 2016, there were no known environmental or regulatory matters which are reasonably expected to result in a material liability to the Company. Many aspects of the oil and gas industry are extensively regulated by federal, state, and local governments in all areas in which the Company has operations. Regulations govern such things as drilling permits, environmental protection and air emissions/pollution control, spacing of wells, the unitization and pooling of properties, reports concerning operations, land use, and various other matters including taxation. Oil and gas industry legislation and administrative regulations are periodically changed for a variety of political, economic, and other reasons. As of December 31, 2016 the Company had not been fined or cited for any violations of governmental regulations that would have a material adverse effect upon the financial condition of the Company.Legal ProceedingsThe Company may from time to time be involved in various legal actions arising in the normal course of business. In the opinion of management, the Company’s liability, if any, in these pending actions would not have a material adverse effect on the financial position of the Company. The Company’s general and administrative expenses would include amounts incurred to resolve claims made against the Company.The Company believes there is no litigation pending that could have, individually or in the aggregate, a material adverse effect on its results of operations or financial condition.Operating LeasesThe Company has a two-year operating lease for office space in San Antonio, Texas and various other operating leases on a month-to-month basis which include office leases in Denver, Colorado and New York City, New York and corporate apartment leases in San Antonio, Texas. Rent expense for the years ended December 31, 2016 and 2015, was approximately $201,000 and $73,000, respectively. As of December 31, 2016, the Company has approximately $0.4 million of minimum lease payments on its operating lease which consists of annual minimum lease payments of approximately $0.2 million in 2017 and $0.2 million in 2018.
2018).F-2210 – RELATED PARTY TRANSACTIONSDuring the years ended December 31, 2016 and 2015, the Company has engaged in the following transactions with related party: December 31, Related Party Transactions 2016 2015 More than 5% Shareholder: (In thousands) T.R. Winston & Company LLC ("TRW") Cash paid for Series B Preferred Stock offering fees $ 500 $ - Reinvest fee for 150 shares of Series B Preferred Stock and 68,182 warrants at exercise price of $2.50 150 - Cash paid for advisory fee on Convertible Notes 350 - Sublet office space in New York to Lilis Energy, Inc for rent of $10,000 per month 15 - Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 400 - Cashless net exercised warrants to purchase 80,000 shares of Common Stock at a reset exercise price of $0.10, resulting in the issuance of 75,820 shares. - - Total: $ 1,415 $ - Steven B. Dunn and Laura Dunn Revocable Trust dated 10/28/10 Conversion of convertible debentures into common stock $ 1,020 $ 1,017 Bryan Ezralow (EZ Colony Partners, LLC) Conversion of convertible debentures into common stock $ 1,540 $ - Participated in the Series B Preferred offering 1,300 - Total: $ 2,840 $ - Pierre Caland (Wallington Investment Holdings, Ltd.) Conversion of convertible debentures into common stock $ 2,090 $ 2,090 Participated in the Series B Preferred offering 250 - Conversion of Series A Preferred stock into common stock 125 - Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 300 - Total: $ 2,765 $ 2,090 Directors and Officers: Nuno Brandolini (Director) Conversion of Series A Preferred stock into common stock $ 100 $ - Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 250 150 Total: $ 350 $ 150 F-23General Merrill McPeak (Director) Conversion of Series A Preferred stock into common stock $ 250 $ - Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 250 250 Total: $ 500 $ 250 R. Glenn Dawson (Director) Participated in the Series B Preferred offering $ 125 $ - Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 50 50 Total: $ 175 $ 50 Ronald D Ormand (Executive Chairman) Participated in the Series B Preferred offering through Perugia Investments LP(1) $ 1,000 $ - Conversion of convertible debentures into common stock through Perugia Investments LP 500 - Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 through Brian Trust(2) 1,150 1,150 Consulting fee paid to MLV & Co. LLC (“MLC”) which Mr. Ormand previously was the Managing Director and Head of the Energy Investment Banking Group at MLV 100 150 Total: $ 2,750 $ 1,300 Abraham Mirman (Chief Executive Officer and Director) Participated in the Series B Preferred offering through Bralina Group, LLC(3) $ 1,650 $ - Conversion of Series A Preferred stock into common stock 250 - Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 through Bralina Group, LLC 750 1,000 Total: $ 2,650 $ 1,000 Kevin Nanken (former Executive Vice President and Chief Financial Officer) Participated in the Series B Preferred offering through KKN Holdings LLC(4) $ 200 $ - Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 through KKN Holdings LLC 100 - Total: $ 300 $ - (1)Mr. Ormand is the manager of Perugia Investments L.P. ("Perugia") and has sole voting and dispositive power over the securities held by Perugia(2)An irrevocable trust managed by Jerry Ormand, Mr. Ormand's brother, as trustee and whose beneficiaries are adult children of Mr. Ormand(3)Mr. Mirman has shared voting and dispositive power over the securities held by The Bralina Group, LLC with Susan Mirman.(4)Mr, Nanke is the natural person with sole voting and dispositive power over the securities held by KKN Holdings LLC.F-24NOTE 11 – INCOME TAXESThe income tax provision (benefit) for the years ended December 31, 2016 and 2015 consisted of the following: December 31, 2016 2015 (In thousands) U.S. Federal: Current $ - $ - Deferred (2,971 ) (10,560 ) State and local: Current - - Deferred (124 ) (914 ) (3,095 ) (11,474 ) Change in valuation allowance 3,095 11,474 Income tax provision $ - $ - The tax effects of temporary differences that give rise to the Company’s deferred tax asset as of December 31, 2016 and 2015 consisted of the following: December 31, 2016 2015 (In thousands) Deferred tax assets: Oil and gas properties and equipment $ 5,156 $ 3,848 Net operating loss carry-forward 42,017 41,389 Share based compensation 2,135 1,279 Abandonment obligation 445 77 Derivative instruments - 21 Accrued liabilities - 37 Debt conversion costs 482 488 Other 28 29 Total deferred tax asset 50,263 47,168 Valuation allowance (50,263 ) (47,168 ) Deferred tax asset , net of valuation allowance $ - $ - Deferred tax liabilities: Oil and gas properties and equipment $ - $ - Total deferred tax liability - - Net deferred tax asset (liability) $ - $ - Reconciliation of the Company’s effective tax rate to the expected U.S. federal tax rate is: For the Year Ended
December 31, 2016 2015 Effective federal tax rate 34.00 % 34.00 % State tax rate, net of federal benefit 1.42 % 2.94 % Change in fair value derivative liability -1.32 % 1.42 % Debt discount amortization -4.11 % -0.01 % Share based compensation differences and forfeitures -2.28 % -4.18 % Change in rate -5.90 % 2.34 % Other permanent differences -12.29 % -1.07 % Other -0.10 % 0.01 % Valuation allowance -9.42 % -35.45 % Net - % - % F-25The net operating losses for these years will not be available to reduce future taxable income until the returns are filed. Assuming these returns are filed, as of December 31, 2016 and 2015, the Company had net operating loss carry-forwards for federal income tax purposes of approximately $118.6 million and $112.0 million, respectively, available to offset future taxable income. To the extent not utilized, the net operating loss carry-forwards as of December 31, 2016 will expire beginning in 2027 through 2036. The net operating loss carryovers may be subject to reduction or limitation by application of Internal Revenue Code Section 382 from the result of ownership changes. A full Section 382 analysis has not been prepared and the Company's net operating losses could be subject to limitation under Section 382.In assessing the need for a valuation allowance on the Company’s deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon whether future book income is sufficient to reverse existing temporary differences that give rise to deferred tax assets, as well as whether future taxable income is sufficient to utilize net operating loss and credit carryforwards. Assessing the need for, or the sufficiency of, a valuation allowance requires the evaluation of all available evidence, both positive and negative. Management had no positive evidence to consider. Negative evidence considered by management includes cumulative book and tax losses in recent years, forecasted book and tax losses, no taxable income in available carryback years, and no tax planning strategies contemplated to realize the valued deferred tax assets.As of December 31, 2016 and 2015, management assessed the available positive and negative evidence to estimate if sufficient future taxable income would be generated to use the Company’s deferred tax assets and determined that it is not more-likely-than-not that the deferred tax assets would be realized in the near future. Therefore, the Company recorded a full valuation allowance of approximately $50. million and $47.2 million on its deferred tax assets as of December 31, 2016 and 2015, respectively.NOTE 12 –14 - STOCKHOLDERS’ EQUITYMay 2014 Private Placement - Series A 8% Convertible Preferred StockOn May 30, 2014, the Company consummated a private placement of 7,500 shares of Series A Preferred Stock, along with detachable warrants to purchase up to 155,602 shares at an exercise price of $28.90 per share, for aggregate gross proceeds of $7.50 million. The Series A Preferred Stock has a par value of $0.0001 per share, a stated value of $1,000 per share, a conversion price of $24.10 per share, and a liquidation preference to any junior securities. Except as otherwise required by law, holders of Series A Preferred Stock shall not be entitled to voting rights, exceptrespect to proposals to alter or change 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 A Preferred Stock as to dividends, redemption or distribution of assets upon liquidation, amend its certificate of incorporation or other charter documents in any manner that adversely affects any rights of the Preferred Stock holder, or increase the number of authorized Series A Preferred Stock. The holders of the Series A Preferred Stock are entitled to receive a dividend payable, at the election of the Company (subject to certain conditions as set forth in the Certificate of Designations), in cash or shares of Common Stock, at a rate of 8% per annum payable a day after the end of each quarter. The Series A Preferred Stock is convertible at any time at the option of the holders, or at the Company’s discretion when the Common Stock trades above $75.00 for ten consecutive days with a daily dollar trading volume above $300,000. In addition, the Company has the right to redeem the shares of Series A Preferred Stock, along with any accrued and unpaid dividends, at any time, subject to certain conditions as set forth in the Certificate of Designations. In addition, holders of the Series A Preferred Stock can require the Company to redeem the Series A Preferred upon the occurrence of certain triggering events, including (i) failure to timely deliver shares of Common Stock after valid delivery of a notice of conversion by the holder; (ii) failure to have available a sufficient number of authorized and unreserved shares of Common Stock to issue upon conversion; (iii) the occurrence of certain change of control transactions; (iv) the occurrence of certain events of insolvency; and (v) the ineligibility of the Company to electronically transfer its shares via the Depository Trust Company or another established clearing corporation.In connection with issuance of the Series A Preferred Stock, the beneficial conversion feature (“BCF”) was valued at $2.21 million and the fair value of the warrant was valued at $1.35 million. The aggregate value of the Series A Preferred Stock and warrant, valued at $3.56 million, was considered a deemed dividend and the full amount was expensed immediately. The Company determined the transaction created a beneficial conversion feature which is calculated 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 inputs for the pricing model are: $24.80 market price per share; exercise price of $28.90 per share; expected life of 3 years; volatility of 70%; and risk free rate of 0.20%. 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 for the warrants. The Company deemed the value of the beneficial conversion feature to be $2.21 million and immediately accreted that amount as a deemed dividend. As of December 31, 2015, the Company has accrued a cumulative dividend for approximately $0.6 million.F-26On June 23, 2016, in connection with the completion of the Merger, each outstanding share of the Company’s Series A Preferred Stock (the “Series A Preferred Stock”) automatically converted into Common Stock at a conversion price of $5.00, resulting in the issuance of 1,500,000 shares of Common Stock with a market value of $1.20 per share. As consideration for the automatic conversion, the Company reduced the conversion price on the Series A Preferred Stock from $24.10 to $5.00. The modification of such conversion price and forgiveness of accrued but unpaid dividend of approximately $0.9 million resulted in a net loss on the conversionreduction of the Series A Preferred Stock of approximately $0.5 million.Conditionally Redeemable 6% Preferred StockIn August 2014, the Company designated 2,000 shares of its authorized preferred stock as Conditionally Redeemable 6% Preferred Stock, or the Redeemable Preferred. All 2,000 shares of Redeemable Preferred were issued in September 2014, pursuant to the Settlement Agreement with Hexagon. The Redeemable Preferred has the same par value and stated value characteristics as the Series A Preferred Stock, yet the Conditionally Redeemable 6% Preferred Stock is not convertible into Common Stock or any other securitiesoutstanding principal amount of the Company. Exceptterm loan under the Second Credit Agreement as otherwise required by law, holders of the Redeemable Preferred shall not be entitled to voting rights.The Redeemable Preferred Stock bears a 6% dividend per annum, payable quarterly, and is redeemable at face value (plus any accrued and 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. These thresholds include, the Company’s annualized gross production average for 90 consecutive days at 2,500 BOE per day or higher or the Company’s PV-10 value of its producing developed properties filed with the Securities and Exchange Commission exceeds $50 million. As of December 31, 2016 and 2015, the Company has accrued a cumulative dividend of $240,000 and $120,000, respectively. The total outstanding Redeemable Preferred was valued at approximately $1.9 million and $1.2 million at December 31, 2016 and 2015, respectively.Series B 6% Convertible Preferred StockOn June 15, 2016, the Company entered into a purchase agreement for the private placement of 20,000 shares of its Series B Preferred Stock, along with detachable warrants to purchase up to 9,090,926 shares of Common Stock, at an exercise price of $2.50 per share, for aggregate gross proceeds of $20 million.Each share of Series B Preferred Stock is convertible, at the option of the holder, subject to adjustment under certain circumstances into shares of Common Stock of the Company at a conversion price of $1.10. Except as otherwise required by law, holders of the Series B Preferred Stock shall not be entitled to voting rights. The Series B Preferred Stock is convertible at any time, subject to certain conditions, at the option of the holders, or at the Company’s discretion when the Company’s Common Stock trades above $10.00 (subject to any reverse or forward stock splits and the like) for ten consecutive days. In addition, the Company has the right to redeem the shares of Series B Preferred Stock, along with any accrued and unpaid dividends, at any time, subject to certain conditions as set forthdisclosed in the Certificate of Designation. The holders of the Series B Preferred Stock are entitled to receive a dividend payable (subject to certain conditions as set forth in the Certificate of Designation), in cash or shares of Common Stock of the Company, at the election of the Company, at a rate of 6% per annum.The Series B Preferred Stock is classified as equity based on the following criteria: i) the redemption of the instrument at the control of the Company; ii) the instrument is convertible into a fixed amount of shares at a conversion price of $1.10; iii) the instrument is closely related to the underlying Company’s Common Stock; iv) the conversion option is indexed to the Company’s stock; v) the conversion option cannot be settled in cash and only can be redeemed at the discretion of the Company; vi) and the Series B Preferred Stock is not considered convertible debt.Shares of the Series B Preferred Stock and related warrants were valued using the relative fair value method. The Company determined the transaction created a beneficial conversion feature of $7.9 million, which was expensed immediately and was calculated by taking the net proceeds of approximately $15.2 million and valuing the warrants as of June 15, 2016, utilizing a Black Scholes option pricing model. The inputs for the pricing model are: $1.20 market price per share; exercise price of $2.50 per share; contractual life of 2 years; volatility of 238%; and risk free rate of 0.78%. As of December 31, 2016, the total value of the issued and outstanding shares of Series B Preferred Stock was approximately $13.4 million.As of December 31, 2016, approximately 3,000 shares of the Series B Preferred Stock plus approximately $0.6 million of cumulative dividend payable were converted into approximately 2.7 million shares of the Company’s Common Stock at conversion price of $1.10 per share. As of December 31, 2016, the Company accrued approximately $0.6 million of cumulative dividend for Series B Preferred Stock.F-27WarrantsA summary of warrant activity for the twelve months ended December 31, 2016 and 2015 (adjusted to reflect 1-for10 reverse stock split on June 23, 2016): Warrants Weighted-
Average
Exercise Price Outstanding at January 1, 2015 1,700,707 $ 1.76 Warrants issued to consultants 60,000 16.30 Warrants issued to Heartland 22,500 8.70 Warrants issued with Convertible Notes 1,180,000 2.50 Exercised, forfeited, or expired (484,891 ) (61.30 ) Outstanding at December 31, 2015 2,478,316 $ 14.80 Warrants issued to Series B Preferred Stock 9,090,926 1.54 Warrants issued for fees 1,272,727 1.30 Warrants issued with Convertible Notes 1,145,238 2.47 Warrants issued to amend Convertible Notes 1,648,267 2.50 Additional warrants issued to Bristol 541,026 3.12 Warrants issued to SOS in connection with the Merger 200,000 2.50 Exercised, forfeited, or expired (460,989 ) (34.74 ) Outstanding at December 31, 2016 15,915,511 $ 3.34 The aggregate intrinsic value associated with outstanding warrants was approximately $18.3 million and zero at December 31, 2016 and 2015, respectively, as the strike price of all warrants exceeded the market price for Common Stock, based on the Company’s closing Common Stock price of $3.10 and $2.10, respectively. The weighted average remaining contract life was 1.64 years and 2.13 years as of December 31, 2016 and 2015.During the year ended December 31, 2016,Note 9 - Long-term Debts, the Company issued approximately 13.16 million warrants to purchase shares of Common Stock to Purchasers of the Convertible Notes, Purchasers of Series B Preferred Stock and placement agent fees in connection with the Series B Preferred Stock Offering. The Company also issued a warrant to purchase 200,000 shares of Common Stock to Brushy's subordinated lender in exchange for extinguishment of certain debt owed by Brushy.The fair value of each stock warrant issued is determined using the Black-Scholes-Merton pricing model based on the following variables as summarized in the table below(fair value in thousands): Fair Value
of Warrants Number
of
Warrants Stock Price Exercise
Price Expected
Volatility Risk Free
Rate Contractual
LifeAs of December 31, 2016: Warrants issued for Series B Preferred Stock $ 9,486 9,090,926 $ 1.30 $ 2.50 238 % 0.78 % 2 years Warrants issued for Series B Preferred Stock offering fees $ 1,590 1,272,724 $ 1.30 $ 1.30 238 % 0.92 % 3 years Warrants issued with Convertible Notes $ 1,446 975,051 $ 1.70 $ 1.00 245 % 0.75 % 2 years Warrants issued with Convertible Notes $ 277 170,187 $ 1.70 $ 1.10 245 % 0.75 % 3 years Warrants issued to amend convertible debts $ 1,625 1,648,270 $ 1.12 $ 2.50 203 % 0.76 % 3 years Warrants issued to SOS $ 170 200,000 $ 1.20 $ 25.00 199 % 0.76 % 3 years Additional warrants issued to Bristol $ 1,214 541,026 $ 3.10 $ 3.12 101 % 1.38 % 3 years As of December 31, 2015: Warrants issued for bridge term loan $ 1,222 1,180,000 $ 2.48 $ 2.89 170 % 0.20 % 3 years Warrants issued for consultants $ 425 60,000 $ 23.30 $ 42.50 99 % 1.29 % 5 years Warrants issued for Heartland Bank $ 56 22,500 $ 25.00 $ 25.00 99 % 1.29 % 5 years F-28In connection with the May Financing, in exchange for additional consideration in the form of participation in the May Convertible Notes offering, certain Purchasers received amended and restated warrants to purchase approximately 620,000 shares of Common Stock, which reduced the exercise price of the warrants issued to these Purchasers in each of the prior two Convertible Notes issuances from $2.50 to $0.10, 80,000 of which were subsequently exercised. Additionally, during the three months ended June 30, 2016, in exchange for several offers to immediately exercise a portion of each investor’s outstanding warrants issued between 2013 and 2014, the Company reduced the exercise price on warrants to purchase a total of 416,454 shares of Common Stock ranging from $42.50 to $25.00 per share to $0.10 per share, of which a total of 315,990 were subsequently exercised, resulting in the issuance of an aggregate amount of 300,706 shares of Common Stock due to certain cashless exercises. The Company accounted for the reduction in the exercise price as an inducement expense and recognized $1.72 million in other income (expense).Additionally, in connection with the Credit and Guarantee Agreement, as partial consideration to the Lenders, the Company also amended certain warrants issued in the Series B private placement held by the Lenders to purchase up to an aggregate amount of approximately 3.5 million shares of Common Stock to date, such that the exercise price per share was lowered from $2.50 to $0.01 on such warrants. The number of warrants amended for each Lender was based on the amount of each Lender’s respective participation in the initial Term Loan relative to the amount invested in the Series B private placement. All of the amended warrants are immediately exercisable from the original issuance date, for a period of two years, subject to certain conditions. For a more detailed description of the terms of the Credit and Guarantee Agreement and the warrant reprice see “Note 8—Loan Agreements—Credit and Guarantee Agreement.”NOTE 13 – SHARE BASED AND OTHER COMPENSATIONShare-Based CompensationOn April 20, 2016, the Company’s Board and the Compensation Committee of the Board approved the Company’s 2016 Omnibus Incentive Plan (the “2016 Plan”). On November 3, 2016, the Company’s stockholders voted to increase number of shares of Common Stock authorized for issuance under the 2016 Plan to 10.0 million.During the year ended December 31, 2016, the Company granted 120,000 shares of restricted Common Stock to certain nonemployee directors in connection with each of their appointment anniversaries pursuant to each director's nonemployee director award agreement and 85,000 shares of restricted Common Stock as Board fees for the quarter ended December 31, 2015, paid in stock in lieu of cash. During the year ended December 31, 2016, the Company also issued (i) 10,000 restricted stock units and options to purchase 45,000 shares of Common Stock under the 2016 Plan to a newly appointed director pursuant to his nonemployee director award and 32,052 shares of restricted common stock as compensation for consulting services. Additionally, during the year ended December 31, 2016, the Company granted options to purchase a total of 5,683,500 shares of Common Stock to management and employees under the 2016 Plan.During the year ended December 31, 2016, certain of the Company's employees, directors and consultants forfeited 26,483 restricted stock units and 335,000 options to purchase Common Stock previously granted in connection with various terminations and forfeitures.As a result, as of December 31, 2016, the Company had 149,584 restricted stock units, 1,068,305 restricted shares, and 5,956,833 options to purchase shares of Common Stock outstanding to employees and directors. Options issued to employees vest in equal installments over specified time periods during the service period or upon achievement of certain performance based operating thresholds.The Company requires that employees and directors pay the tax on equity grants in order to issue the shares and there is currently no cashless exercise option. As of December 31, 2016, 149,584 restricted stock units and 1,780,052 restricted shares have been granted, but have not been issued.F-29Compensation Costs (in thousands) As of December 31, 2016 As of December 31, 2015 Stock
Options Restricted
Stock Total Stock
Options Restricted
Stock Total Stock-based compensation expensed $ 4,475 $ 2,398 $ 6,873 $ 2,191 $ 469 $ 2,660 Unamortized stock-based compensation costs $ 5,200 $ 1,249 $ 6,449 $ 2,091 $ 266 $ 2,357 Weighted average amortization period remaining* 1.68 1.45 2.18 1.05 * Only includes directors and employees which the options vest over time instead of performance criteria which the performance criteria have not been met as of December 31, 2016 and 2015.Restricted StockSummary of non-cash compensation in Statement of Changes in Stockholders’ Equity: As of December 31, 2016 2015 (In thousands) Statement of Stockholder’s Equity: Common stock issued for directors’ fees $ 85 $ 215 Common stock issued for officer and Board compensation 120 - Stock based compensation for vesting of restricted stock - 469 Stock based compensation for issuance of stock options 4,475 2,191 Stock based compensation for issuance of restricted stock 2,398 - Common stock issued for professional services - 150 Fair value of warrants issued for professional services - 425 Total non-cash compensation in Statement of Changes in Stockholders’ Equity $ 7,078 $ 3,450 A summary of restricted stock grant activity pursuant to the 2016 Plan for the year ended December 31, 2016 is presented below: Number of
Shares Weighted
Average Grant
Date Price Outstanding at January 1, 2016 - $ - Granted 1,780,052 1.54 Vested and issued (711,747 ) (1.75 ) Forfeited - - Outstanding at December 31, 2016 1,068,305 $ 1.55 There was no restricted stock grant activity for the year ended December 31, 2015.A summary of restricted stock unit grant activity pursuant to the 2012 Plan for the years ended December 31, 2016 and 2015 is presented below. Share activities for the year ended December 31, 2015 have been adjusted for 1-for-10 reverse stock split on June 23, 2016.F-30 Number of
Shares Weighted
Average Grant
Date Price Outstanding at January 1, 2015 163,067 $ 24.40 Granted 114,501 9.00 Vested and issued (77,835 ) 6.60 Forfeited (12,833 ) 22.70 Outstanding at December 31, 2015 186,900 12.29 Granted - - Vested and issued (10,834 ) (18.75 ) Forfeited (26,482 ) (16.15 ) Outstanding at December 31, 2016 $ 149,584 $ 10.56 As of December 31, 2016, the total unrecognized compensation costs related to 1,217,889 unvested shares of restricted stock was approximately $1.2 million, which is expected to be recognized over a weighted-average remaining services period of 0.8 year. As of December 31, 2015, the Company had 151,900 shares vested but unissued and total unrecognized compensation cost related to the 34,999 unvested shares of restricted stock was approximately $266,000, which is expected to be recognized over a weighted-average remaining service period of 1.05 years.Stock OptionsA summary of stock options activity for the years ended December 31, 2016 and 2015 is presented below: Stock Options Outstanding and
Exercisable Number
of Options Weighted
Average
Exercise
Price Number
of Options
Vested/
Exercisable Weighted
Average
Remaining
Contractual Life
(Years) Outstanding at January 1, 2015 358,333 $ 21.60 138,333 4.24 Granted 480,000 $ 12.60 Exercised - Forfeited or cancelled (230,000 ) $ (24.60 ) Outstanding at December 31, 2015 608,333 $ 14.60 296,666 4.10 Granted 5,683,500 2.14 Exercised - Forfeited or cancelled (335,000 ) (5.34 ) Outstanding at December 31, 2016 5,956,833 $ 2.04 2,208,757 1.68 During 2016, option to purchase 5,683,5005,952,763 shares of the Company’s common stock, were granted under the 2016 Plan. The weighted average fair valuespar value $0.0001 per share which includes 5,802,763 shares of these optionscommon stock at an exchange price of $1.38. The fair values were determined using the Black-Scholes-Merton option valuation method assuming no dividends, a risk-free interest rate$5.00 per share of 1.08%, a weighted average expected lifecommon stock plus an additional 150,000 shares of 4.12 years and weighted-average volatility of 152%As of December 31, 2016, total unrecognized compensation costs relating to the outstanding options was $5.2 million, which is expected to be recognized over the remaining vesting period of approximately 3.68 years.The outstanding options have an intrinsic value of approximately $12.3 million at December 31, 2016.During the year ended December 31, 2016 and 2015,common stock.issued optionsentered into a share-repurchase agreement (the “SRA”) with an investment brokerage company (“Broker”) to purchase shares of Common Stock to certain officers and directors. The options are valued using a Black Scholes model and amortized over the liferepurchase $1.0 million of the option. DuringCompany’s common stock as part of the years ended December 31, 2016 and 2015, the Company amortized $4.5 million and $2.19 million, respectively relating to options outstanding.F-31NOTE 14 –Supplemental Non-cash TransactionsThe following table presents information about supplemental cash flows for the years ended December 31, 2016 and 2015(in thousands); 2016 2015 Non-cash investing and financing activities excluded from the statement of cash flows: Common stock issued for Series A Preferred Stock and accrued dividends 7,682 - Common stock issued for convertible notes and accrued interest 14,872 - Common stock issued for Brushy’s common stock 7,111 - Common stock issued for Series B Preferred Stock and accrued dividends 3,230 - Warrants issued for fees associated with Series B Preferred Stock issuance 1,590 - Warrants issued for Series B Preferred Stock issuance and recorded as a deemed dividend 7,879 - Fair value of warrants issued as debt discount and financing costs 2,192 1,222 Disposition of oil and gas assets for elimination of accrued expense for drilling - 5,198 NOTE 15 – SUBSEQUENT EVENTSCredit Agreement DrawdownOn February 7, 2017, pursuant toShare Repurchase Plan (the “Plan”). Under the terms of the Credit Agreement, we exercisedSRA, the accordion advance feature, increasingCompany paid cash directly to the aggregate principal amount outstandingBroker and received delivery of shares of the Company’s common stock. All of the shares acquired by the Company under the term loan from $31 millionSRA are recorded as treasury stock. For the nine months ended December 31, 2018 the Company purchased 253,598 shares of the Company’s common stock for approximately $1.0 million.$38.1 million. The total availability for borrowing remaining underincrease the Credit Agreement is $11.9 million. We intend to use the proceeds to fund its drilling and development program, for working capital and for general corporate purposes.As partial consideration, we also amended certain warrants issued in the June 2016 private placement held by the Lenders to purchase up to an aggregate amountnumber of approximately 738,638authorized shares of common stock such thatby 50 million from the exercise price per shareprior level of 100 million. This amendment was lowered from $2.50 to $0.01also approved by the Company’s stockholders on such warrants The number of warrants amended for each LenderJuly 13, 2017. There was based on the amount of each Lender’s respective participationno change in the initial Term Loan relative to the amount invested in the June 2016 private placement. Allstated par value of the amended warrants are immediately exercisable from the original issuance date, forshares as a periodresult of two years, subject to certain conditions.March 2017 this amendment.wethe Company entered into a Securities Subscription Agreement (the “Subscription Agreement”) with certain institutional and accredited investors in connection with a private placement (the “March 2017 Private Placement”) to sell 5.2 million units, consisting of approximately 5.2 million shares of common stock and warrants to purchase approximately an additional 2.6 million.million shares of common stock. Each unit consistsconsisted of one share of common stock and a warrant to purchase 0.50 shares of common stock, (each, a “Unit”), at a price per unit of $3.85. Each warrant has an exercise price of $4.50 and may be subject to redemption by the Company, upon prior written notice, if the price of the Company’s common stock closes at or above $6.30 for twenty trading days during a consecutive thirty trading day period. The closingAs of December 31, 2017, the Offering is subject to the satisfactionCompany received aggregate gross proceeds of customary closing conditions.We expect to use the net proceeds from the Offering to support our planned 2017 capital budget,$20.0 million and for general corporate purposes including working capital.The securities to be sold in the private placement have not been registered under the Securities Act or any state securities laws and may not be offered or sold in the United States absent registration or an applicable exemption from registration. However, in conjunction with the closing of the March 2017 Private Placement, we have also entered into a registration rights agreement whereby we agreed to use our reasonable best efforts to register, on behalf of the investors, theissued 5,194,821 shares of common stock underlyingand warrants to purchase 2,597,420 shares of common stock. Warrants Outstanding at January 1, 2017 15,915,511 $ 3.34 Warrants issued in connection with private placement 2,597,420 4.50 Warrants issued to Heartland 160,714 3.50 Exercised (6,144,176 ) (0.30 ) Forfeited or expired (646,669 ) (25.70 ) Outstanding at December 31, 2017 11,882,800 $ 3.34 Exercised (3,975,957 ) 2.21 Forfeited or expired (2,889,514 ) 3.35 Outstanding at December 31, 2018 5,017,329 $ 3.83 Year Warrants 2019 2,263,267 2020 174,642 2021 — 2022 2,579,420 5,017,329 UnitsCompany’s Board and the Compensation Committee of the Board approved the Company’s 2016 Omnibus Incentive Plan (the “2016 Plan”). On November 3, 2016 the Company’s stockholders voted to increase number of shares of common stock underlyingauthorized for issuance under the warrants no later than April 1, 2017.Our2016 Plan to 10 million. At the 2017 capital budget may require additional financing aboveAnnual Meeting of Stockholders of the levelCompany held on July 13, 2017, the Company’s stockholders approved the second amendment to its 2016 Plan to increase the number of cash generated by our operations and proceedsshares of common stock available for grant under the 2016 Plan from recent financing activities. We can provide no assurance that additional financing would be10 million to 13 million shares. As of December 31, 2018, 6.7 million shares of the 13 million shares of the Company’s common stock authorized for awards under the 2016 Plan remained available for future issuances. The Company generally issues new shares to us on acceptable terms, ifNOTE 16 – SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)informationthe stock based compensation expense recognized during the years ended December 31, 2018 and 2017 and the unamortized portion of the stock based compensation expense and weighted average amortization period of the remaining vesting period at December 31, 2018 and 2017: 2018 2017 (in thousands) Total Total Stock based compensation expense $ 2,158 $ 6,842 $ 9,000 $ 7,255 $ 14,283 $ 21,538 Unamortized stock based compensation costs $ 487 $ 3,501 $ 3,988 $ 4,267 $ 8,669 $ 12,936 Weighted average amortization period remaining (years) 0.3 0.5 0.7 0.8 December 31, 2018 2017 (In thousands) Common stock issued for directors’ fees $ 1,182 $ 959 Stock based compensation for issuance of stock options 1,933 7,255 Stock based compensation for issuance of restricted stock 4,372 13,227 Common stock issued for professional services 1,513 97 Total non-cash compensation in the Statement of Changes in Stockholders’ Equity $ 9,000 $ 21,538 Outstanding at January 1, 2017 1,068,305 $ — Granted 4,266,345 1.54 Vested and issued (2,162,915 ) (1.75 ) Forfeited or canceled (696,469 ) — Outstanding at December 31, 2017 2,475,266 $ 4.22 Granted 1,194,944 4.59 Vested and issued (1,436,146 ) (2.38 ) Forfeited or canceled (1,280,480 ) (4.44 ) Outstanding at December 31, 2018 953,584 $ 4.85 Outstanding at January 1, 2017 186,900 $ 12.29 Granted — — Vested and issued (150,419 ) (18.75 ) Forfeited (26,482 ) (16.15 ) Outstanding at December 31, 2017 9,999 6.57 Granted — — Vested and issued (9,999 ) (6.57 ) Forfeited — — Outstanding at December 31, 2018 $ — $ — 2018 2017 Expected Term in Years 6 2 Expected Volatility 66 % 101 % Expected Dividends — % — % Risk-Free Interest Rate 2.67 % 1.38 % Stock Options Outstanding and Exercisable Outstanding at December 31, 2016 5,956,833 $ 2.04 2,208,757 9.6 Granted 3,260,000 4.74 Exercised (304,896 ) (2.01 ) Forfeited or canceled (1,606,937 ) (3.06 ) Outstanding at December 31, 2017 7,305,000 3.74 3,534,484 8.9 Granted 352,500 4.07 Exercised (1,024,877 ) (2.67 ) Forfeited or canceled (1,601,045 ) (4.20 ) Outstanding at December 31, 2018 5,031,578 $ 3.81 5,035,317 7.9 2015 with respect to changes infinancing activities for the Company's proved (i.e. proved developedyears ended December 31, 2018 and undeveloped) reserves:2017: 2018 2017 (in thousands) Non-cash investing and financing activities excluded from the statement of cash flows: Conversion of Series B Preferred Stock and accrued dividends to common stock $ — $ 14,865 Fair value of warrants issued for financing costs and debt discount — 1,031 Common stock issued for acquisition of oil and natural gas properties 24,778 — Common stock issued for commitment fees associated with Private Placement — 250 Cashless exercise of warrants and stock options 359 370 Accrued drilling costs 7,850 3,615 Change in asset retirement obligation 1,495 99 Issuance of common stock for drilling services — 97 Issuance of common stock and preferred stock for debt conversion 64,504 — Reduction of fair value for converted embedded derivatives 12,406 — Accrued PIK dividends on Series C-1, C-2 and D Preferred Stock 10,687 — Transfer of warrant derivative instruments to equity 223 — Year Ended December 31, 2018 2017 (in thousands) Net loss $ (4,143 ) $ (80,082 ) Dividends on Series C-1, C-2 and D convertible preferred stock (10,687 ) — Dividends on redeemable preferred stock — (122 ) Dividend and deemed dividends on Series B convertible preferred stock — (4,635 ) Net loss attributable to common stockholders $ (14,830 ) $ (84,839 ) Weighted average common shares outstanding - basic 62,854,214 42,428,148 Net loss per common share - basic $ (0.24 ) $ (2.00 ) Numerator for diluted loss per share: Net loss attributable to common stockholders $ (14,830 ) $ (84,839 ) Add: interest expense on convertible Second Lien Loans 13,429 — Less: fair value change of embedded derivatives associated with Second Lien Loans (35,471 ) — Net loss attributable to common stockholders $ (36,872 ) $ (84,839 ) Denominator for diluted net loss per share: Weighted average number of common shares outstanding - basic 62,854,214 42,428,148 Dilution effect of if-converted Second Lien Loans (1) 15,597,127 — Weighted average number of common shares outstanding - diluted 78,451,341 42,428,148 Net loss per share - diluted: Net loss per common shares (diluted) $ (0.47 ) $ (2.00 ) F-32(1) The Company excluded the following shares from the diluted loss per share calculations because they are anti-dilutive at December 31, 2018 and 2017: December 31, 2018 2017 Stock Options 5,031,578 7,305,000 Restricted Stock Units — 9,999 Stock Purchase Warrants 5,017,329 11,882,800 If-converted Second Lien Term Loans — 24,202,016 If-converted Series C-1 9.75% Convertible Participating Preferred Stock 21,309,234 — If-converted Series C-2 9.75% Convertible Participating Preferred Stock 4,986,382 — If-converted Series D 8.25% Convertible Participating Preferred Stock 8,543,670 — Total 44,888,193 43,399,815 Crude Oil
(Bbls) Natural Gas
(Mcf) December 31, 2014 899,727 4,237,241 Purchase of reserves - - Revisions of previous estimates (859,230 ) (4,063,500 ) Extensions, discoveries - - Sale of reserves - - Production (7,067 ) (32,291 ) December 31, 2015 33,430 141,450 Purchase of reserves 93,972 292,018 Revisions of previous estimates 455,202 3,506,794 Extensions, discoveries Sale of reserves Production (31,899 ) (68,756 ) December 31, 2016 550,705 3,871,506 Proved Developed Reserves, included above: Balance, December 31, 2014 50,185 197,146 Balance, December 31, 2015 33,430 141,450 Balance, December 31, 2016 550,705 3,871,506 Proved Undeveloped Reserves, included above: Balance, December 31, 2014 849,542 4,040,095 Balance, December 31, 2015 - - Balance, December 31, 2016 - - 2016 and December 31, 2015,2018, the Company had estimated proved reservesnot been fined or cited for any violations of 550,705 and 33,430 barrelsgovernmental regulations that would have a material adverse effect upon the financial condition of oil, respectively and 3,871,506 and 141,450 thousand cubic feet (“MCF”)the Company.natural gas, respectively.business. In the opinion of management, the Company’s liability, if any, in these pending actions would not have a material adverse effect on the financial position of the Company. The Company’s reserves are comprisedgeneral and administrative expenses would include amounts incurred to resolve claims made against the Company.46%operations or financial condition.59% crude oil and 54% and 41% natural gas on an energy equivalent basis,Fort Worth, Texas, with minimum lease payments with commitments that have initial or remaining lease terms in excess of one year as of December 31, 20162018, comprising $0.2 million in 2019, $0.1 million in 2020 and less than $0.1 million in 2021. The Company recognizes rent expense on a straight-line basis over the noncancelable lease term. The leases for office space in Houston, Texas, and Fort Worth, Texas, expire in August 2021 and January 2020, respectively. There were no other noncancelable leases during the year ended December 31, 2015,2018. For the years ended December 31, 2018 and 2017, the Company recognized rent expense of $0.6 million, respectively.valuesis a description of the material terms of the Series F Preferred Stock and the Series E Preferred Stock, the material amended terms of the Series D Preferred Stock and the Series C Preferred Stock and the material terms of the 2019 Transaction Agreement. Except as otherwise noted in this Note 20, the material terms of the Series D Preferred Stock and the Series C Preferred Stock remain as in effect prior to the closing of the transactions contemplated by the 2019 Transaction Agreement as disclosed in Note 13 - Mezzanine Preferred Stock. The Series F Preferred Stock, the Series E Preferred Stock, the Series D Preferred Stock and the Series C Preferred Stock are referred to collectively in this Note 20 as the “Preferred Stock.”20162019.December 31, 2015combinations, dividends paid in stock and similar events affecting the outstanding Common Stock. Additionally, the Conversion Price will be adjusted, based on a broad-based weighted average formula, if the Company issues, or is deemed to issue, additional shares of Common Stock for consideration per share that is less than the Conversion Price then in effect, subject to certain exceptions and to the Share Cap (as defined below). December 31, 2018 2017 (In thousands) Acquisition costs: Unproved properties $ 93,926 $ 78,111 Proved properties 22,356 2,245 Exploration costs 89,351 42,033 Development costs 78,103 28,113 Total $ 283,736 $ 150,502 December 31, 2018 2017 (In thousands) Revenues $ 70,216 $ 21,612 Production costs (13,843 ) (6,199 ) Production taxes (3,709 ) (1,187 ) Accretion of asset retirement obligation (85 ) (82 ) Depletion, depreciation and amortization (25,159 ) (6,906 ) Full cost ceiling impairment — (10,505 ) Total $ 27,420 $ (3,267 ) January 1, 2017 550,705 3,871,506 3,211 Extensions and discoveries 6,791,945 14,438,471 1,455,620 Purchase of reserves — — — Sale of reserves (92,293 ) (364,712 ) (3,211 ) Revisions of previous estimates 292,975 (1,109,174 ) 222,825 Production (371,993 ) (776,165 ) (73,875 ) December 31, 2017 7,171,339 16,059,926 1,604,570 Extensions and discoveries 15,881,727 38,957,588 4,565,994 Purchase of reserves 1,883,047 8,897,115 682,964 Sale of reserves — — — Revisions of previous estimates (2,641,353 ) 17,690,723 1,769,448 Production (1,089,724 ) (2,855,739 ) (246,425 ) December 31, 2018 21,205,036 78,749,613 8,376,551 Proved Developed Reserves, included above: Balance, January 1, 2017 550,705 3,871,506 3,211 Balance, December 31, 2017 2,531,397 6,594,446 644,102 Balance, December 31, 2018 6,278,035 27,046,195 2,653,908 Proved Undeveloped Reserves, included above: Balance, January 1, 2017 — — — Balance, December 31, 2017 4,639,942 9,465,480 960,468 Balance, December 31, 2018 14,927,001 51,703,418 5,722,643 12 month arithmetic average firstlife of month price January through December 31; resulting in a natural gas price of $2.05 and $2.79 per MMBtu (NYMEX price), respectively, and crude oil price of $37.30 and $42.59 per barrel (West Texas Intermediate price), respectively.the properties. All wellhead prices are held flat over the forecast period for all reserve categories. The estimated future net cash flows are then further adjusted for transportation, quality and basis differentials.following summary sets forth the Company'sstandardized measure of discounted future net cash flows relating to proved oil, natural gas and NGL reserves is as follows: December 31, 2018 2017 (In thousands) Future cash inflows $ 1,500,263 $ 397,531 Future production costs (414,117 ) (151,456 ) Future development costs (346,225 ) (113,727 ) Future income tax expense (62,842 ) — Future net cash flows 677,079 132,348 10% discount to reflect timing of cash flows (384,345 ) (63,536 ) Total $ 292,734 $ 68,812 ( reported at the end of each year shown were based on costs determined at each such year-end, assuming the continuation of existing economic conditions.thousands): For the Year Ended
December 31, 2016 2015 Future oil and gas sales $ 28,514 $ 1,819 Future production costs (15,939 ) (983 ) Future development costs (3,388 ) - Future income tax expense (1) - - Future net cash flows 9,187 836 10% annual discount (2,531 ) (228 ) Standardized measure of discounted future net cash flows $ 6,656 $ 608
the determinations and no value may be assigned to probable or possible reserves.F-33The principal sources of changeare(in thousands): 2016 2015 Balance at beginning of period $ 608 $ 23,254 Sales of oil and gas, net (1,989 ) (146 ) Net change in prices and production costs (309 ) (26,115 ) Net change in future development costs 4,617 20,626 Extensions and discoveries - - Acquisition of reserves 7,919 - Sale / conveyance of reserves - - Revisions of previous quantity estimates 1,087 (19,336 ) Previously estimated development costs incurred (8,942 ) - Net change in income taxes - - Change in timing and other 3,630 - Accretion of discount 35 2,325 Balance at end of period $ 6,656 $ 608 (1)Calculations of the standardized measure of discounted future net cash flows include the effect of estimated future income tax expenses for all years reported. The Company expects that all of its Net Operating Loss’ (“NOL”) will be realized within future carry forward periods. All of the Company's operations, and resulting NOLs, are attributable to its oil and gas assets.A variety of methodologiesrelating to proved oil, natural gas and NGL reserves 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 of these methods is used to determine reserve estimates in substantially all of our fields.F-34 Year Ended December 31, 2018 2017 (In thousands) Balance at beginning of period $ 68,812 $ 6,656 Net changes in prices and production costs 24,261 (13,402 ) Sales of oil and gas produced during the year, net (49,271 ) 57,163 Changes in estimated future development costs (39,938 ) — Net change due to extensions and discoveries 161,785 (1,296 ) Net change due to purchases of minerals in place 55,278 8,311 Net change due to sales of minerals in place — 4,968 Previously estimated development costs incurred during the year 68,349 (1,580 ) Net changes due to revision of previous quantity estimates 28,350 1,683 Accretion of discount 6,881 666 Other - unspecified 3,252 5,643 Net change in income taxes (35,025 ) — Balance at end of period $ 292,734 $ 68,812