FORM 10-K ANNUAL REPORT

FISCAL YEAR ENDED DECEMBER 31, 20142016

LILIS ENERGY, INC.

FORWARD-LOOKING STATEMENTS

This annual reportAnnual Report on Form 10-K contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995.. All statements other than statements of historical fact are “forward-looking statements” for purposes of federal and state securities laws, including, but not limited to, any projections of earnings, revenue or other financial items; any statements of the plans, strategies and objectives of management for future operations; any statements concerning future production, reserves or other resource development opportunities; any projected well performance or economics, or potential joint ventures or strategic partnerships; any statements regarding future economic conditions or performance; any statements regarding future capital-raising activities; any statements of belief; and any statements of assumptions underlying any of the foregoing.

Forward-looking statements may include the words “may,” “should,” “could,” “estimate,” “intend,” “plan,” “project,” “continue,” “believe,” “expect” or “anticipate” or other similar words. These forward-looking statements present our estimates and assumptions only as of the date of this presentation. Except as required by law, we do not intend, and undertake no obligation, to update any forward-looking statement.

Although we believe that the expectations reflected in any of our forward-looking statements are reasonable, actual results could differ materially from those projected or assumed in any of our forward-looking statements. Our future financial condition and results of operations, as well as any forward-looking statements, are subject to change and inherent risks and uncertainties. The factors impacting these risks and uncertainties include, but are not limited to, the Risk Factors set forth in this Annual Report on Form 10-K in Part I, “Item 1A. Risk Factors” and the following factors:

Many of these factors are beyond our ability to control or predict. These factors are not intended to represent a complete list of the general or specific factors that may affect us.

For a detailed description of these and other factors that could cause actual results to differ materially from those expressed in any forward-looking statement, we urge you to carefully review and consider the disclosures made in the “Risk Factors” sections of our SEC filings, available free of charge at the SEC’s website (www.sec.gov)(www.sec.gov).

GLOSSARY

In this report,Annual Report on Form 10-K, the following abbreviation and terms are used:

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

Bcf. Billion cubic feet of natural gas.

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

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

BOE. BarrelsOne barrel of crude oil equivalent, determined using the .ratioratio of six mcfMcf of natural gas to one bblbarrel of crude oil, condensate or natural gas liquids.

BOE/d. BOEBarrels 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 natural gas or oil or in the case of a dry hole, the reporting to the appropriate authority that the well has been abandoned.natural gas.

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

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

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

Dry well;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 reservoirreservoir. Generally an exploratory well in any well that is not a field previously found to be productive of natural gasdevelopment well, an extension well, a service well or oil in another reservoir.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 the Company ownswe 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 the Company ownswe 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. ThousandOne thousand barrels of crude oil or other liquid hydrocarbons.

Mboe. ThousandOne thousand barrels of crude oil equivalent, determined using the ratio of six mcfMcf of natural gas to one bblBbl of crude oil, condensate or natural gas liquids.

Mcf. ThousandOne thousand cubic feet of natural gas.

Mcfe. ThousandOne thousand cubic feet equivalent, determined using the ratio of six mcfMcf of natural gas to one bblBbl of crude oil, condensate or natural gas liquids.

MMbtu. MillionOne million British Thermal Units.

MMcf. MillionOne million cubic feet of natural gas.

Net acres;acres or net wells. A “net acre” or “net well” is deemed to exist when theThe sum of fractional ownership working interests in gross acres or wells equals one.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. 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 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 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 Lilis Energyour 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.

PartPART I

Items 1 and 2. BUSINESS AND PROPERTIESBusiness and Properties

Lilis Energy, Inc. (NASDAQ: LLEX) (“we,and its consolidated subsidiaries (collectively, “we,” “us,” “our,” “Lilis Energy,” “Lilis,” or the “Company”) is a Denver-basedan upstream independent oil and gas company engaged in the acquisition, drilling and production of oil and natural gas properties and prospects. We were incorporated in August of 2007 in the State of Nevada as 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.

OurOn June 23, 2016, we 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 us, 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”), 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 Merger resulted in the acquisition of our properties in the Delaware Basin as well as the majority of our current operating activitiesactivity.

Additionally, in connection with the Merger on June 23, 2016, we effected a 1-for-10 reverse stock split (the “Reverse Split”). As a result of 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 majority of our acreage positions. Our goal is to earn economic returns to our shareholders through cash flow from new production of oil, natural gas and NGLs, as well as through derisking 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 but initially targeting the Wolfcamp formation. We drilled our first horizontal well in late 2016 and completed it in February 2017.

Overview of Our Business and Strategy

We are an oil and natural gas company, engaged in the acquisition, development and production of conventional and unconventional oil and natural gas properties. We have accumulated approximately 6,924 net acres in the Delaware Basin in Winkler and Loving Counties, Texas and Lea County, New Mexico. Our leasehold position is largely contiguous, allowing us to maximize development efficiency, manage full-cycle finding costs and potentially enabling us to generate higher returns for our shareholders. In addition, 66% of our acreage positions is held by production, and we are the named operator on 100% of our acreage. These characteristics give us control over the pace of development and the ability to design a more efficient and profitable drilling program that maximizes recovery of hydrocarbons. We expect that substantially all of our estimated 2017 capital expenditure budget will be focused 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.

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. As of December 31, 2016, on consolidated basis, we had proved reserves of 1,195 MBoe (46% oil and liquids).

Our Delaware Basin Properties

We have approximately 6,924 net acres in the Delaware Basin, comprised of 6,424 acres in Winkler and Loving Counties, Texas and 500 acres in Lea County, New Mexico. The aerial extent of the Delaware Basin stretches across Ward, Reeves, Loving, Winkler, Pecos, and Culberson Counties in Texas and also runs north into Lea and Eddy Counties in New Mexico. The Delaware Basin is comprised of 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 volumes of proppant. Our 2017 drilling program will primarily target the Wolfcamp formation in up to 10 wells. We are targeting horizontal lateral lengths of 5,000 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.

Our Denver-Julesburg Basin Properties

In addition to our core Delaware Basin focus area, we have approximately 14,254 net acres in the Denver-Julesburg Basin (“DJ Basin”) in Colorado, Wyoming and Nebraska.  Our business strategy is designed to maximize shareholder value by leveraging the knowledge, expertise and experiencecomprised of our management team and via the future exploration and development of the approximately 65,000280 net acres of developed and undeveloped acreage that are currently held by us, primarily in the northern DJ Basin.

Recent Developments

As previously disclosed, we had significant developments in 2014 through the date of this report, including substantial management changes, the consummation of private placement transactions in January and May of 2014 and the conveyance of the Hexagon Collateral (discussed below) to our primary lender Hexagon, LLC (“Hexagon”) in exchange for extinguishment of all outstanding debt and accrued interest obligations owed to Hexagon in September of 2014. Additionally, we successfully completed a conversion of more than half of our outstanding 8% Senior Secured Convertible Debentures (the “Debentures”) in January of 2014. The Debentures (as previously amended) mature on January 15, 2015; however, in connection with our entry into the Credit Agreement (discussed below) in January 2015, we entered into an extension agreement with the holders of the Debentures, which extends the maturity date of the outstanding Debentures until January 8, 2018. The maturity date now coincides with the maturity date of the Credit Agreement. For further discussion of our capital raising transactions, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview of 2014 and Recent Developments, and the notes to our financial statements.

Heartland Bank Credit Agreement

On January 8, 2015, we entered into a credit agreement with Heartland Bank (the “Credit Agreement”) which provides for a three-year senior secured term loan in an initial aggregate principal amount of $3.0 million, which principal amount may be increased to a maximum principal amount of $50.0 million at the request of us, subject to certain conditions, pursuant to an accordion advance provision in the Credit Agreement. The availability of additional funds is subject to the discretion of the lenders, and is generally based on the value of the Company’s proved developed producing (“PDP”) and proved undeveloped (“PUD”) reserves. We intends to use proceeds borrowed under the Credit Agreement to fund producing property acquisitions in North America, drill wells in the core of the Wattenberg field in Weld County, Colorado and 13,974 net acres in Laramie County, Wyoming, Nebraska and other parts of Colorado. Our acreage position has multi-zone potential with producing wells in the Niobrara, Codell, and J Sand. Our 2017 capital expenditure budget does not contemplate committing significant capital to our lease positionsDJ Basin project area, and we are currently reviewing strategic alternatives with respect to fund working capital.these properties.

Overview of Our Business Strengths and Strategy

We have acquired and developed a producing base of oil and natural gas proved reserves, as well as a portfolio of exploration and other undeveloped assets with conventional and non-conventional reservoir opportunities, with an emphasis on those with multiple producing horizons, in particular the Muddy “J” conventional reservoirs and the Niobrara shale and Codell resource plays. We believe these assets offer the possibility of repeatable year-over-year success and significant and cost-effective production and reserve growth. Our acquisition, development and exploration pursuits are principally directed at oil and natural gas properties in North America. Since early 2010, we have acquired and/or developed 25 producing wells. As of December 31, 2014 we owned interests in 8 economically producing wells and 67,000 gross (65,000 net) leasehold acres, of which 59,000 gross (57,000 net) acres are classified as undeveloped acreage and all of which are located in Colorado, Wyoming and Nebraska within the DJ Basin.   We are primarily focused on acquiring companies and production throughout North America and developing our North and South Wattenberg Field assets, which include attractive unconventional reservoir drilling opportunities in mature development areas with low risk Niobrara and Codell formation productive potential.  Strategies

Our intermediate goalprimary business objective is to create significant value via the investmentincrease our Delaware Basin leasehold position, reserves, production and cash flows at attractive rates of up to $50.0 million through acquisitions of producing assets and the development of our inventory of low and controlled-risk conventional and unconventional properties, while maintaining a low cost structure, and to acquire companies and production or producing properties (typically with accompanying prospective development opportunity) throughout North America. To achieve this, our business strategy includes the following elements:

Acquiring additional assets and companies throughout North America. We are targeting acquisitions in North America, which meet certain current and future production thresholds to increase shareholder value. We anticipate the acquisitions will be funded with funds borrowed under the Credit Agreement and equity to be accessed in capital markets transactions.

Pursuing the initial development of our Greater Wattenberg Field unconventional assets. We plan to drill several horizontal wells on our South Wattenberg property during 2015. Drilling activities will target the well established Niobrara and Codell formations.  Subject to the securing of additional capital, we expect to drill and operate up to 8 wells, with an expected investment of approximately $18.0 million.

Extending the development of certain conventional prospects within our inventory of other DJ Basin properties.  Subject to the securing of additional capital, we anticipate the expenditure of up to an additional $50.0 million in drilling and development costs on three of our DJ Basin assets where initial exploration has yielded positive results. Additional drilling activities will be conducted on each property in an effort to fully assess each property and define field productivity and economic limits.  

Retain Operational Control and Significant Working Interest.  In our principal development targets, we typically seek to maintain operational control of our development and drilling activities.   As operator, we retain more control over the timing, selection and process of drilling prospects and completion design, which enhances our ability to maximize our return on invested capital and gives us greater control over the timing, allocation and amounts of capital expenditures.  However, duein order to our recent liquidity difficulties, a significant amountenhance shareholder value. To achieve this objective, key elements of our current drilling activity on wells in which we own an interest is not operated by us. strategy include:

Leasing of Prospective Acreage.  In the course of our business, we identify drilling opportunities on properties that have not yet been leased.  Subject to securing additional capital, we may take the initiative to lease prospective acreage and we may sell all or any portion of the leased acreage to other companies that want to participate in the drilling and development of the prospect acreage.

Hedging. From time to time, we 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. As such, we will enter into futures contracts, collars and basis swap agreements, as well as fixed price physical delivery contracts. 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. In the future we may also be required by our lenders to hedge a portion of production as part of any financing.

Acreage.Currently, our inventory of developed and undeveloped acreage includes approximately 8,000 net acres that are held by production, approximately, 49,000, 2,000, 5,000 and 1,000 net acres that expire in the years 2015, 2016, 2017, and thereafter, respectively. Approximately 88% of our inventory of undeveloped acreage provides for extension of lease terms from two to five years, at the option of us, via payment of varying, but typically nominal, extension amounts. We’re currently evaluating the 2015 lease expirations to determine if this acreage is a focus for future development. If determined to be a focus for future development, we plan to re-lease if available. If not a focus, we plan to let the acreage expire. We plan to borrow additional funds under the Credit Agreement to acquire additional bolt-on properties, acquire other properties throughout North America, or drill wells on our core properties to hold the property by production.

Capital Raising.The business of oil and natural gas property acquisition, exploration and development is highly capital intensive and the level of operations attainable by oil and natural gas companies is directly linked to and limited by the amount of available capital. Therefore, a principal part of our plan of operations is to raise the additional capital required to finance the exploration and development of our current oil and natural gas prospects and the acquisition of additional properties. We will need to raise additional capital to fund our exploration and development, and operating, budget. We plan to seek additional capital through the sale of our securities, through debt and project financing, joint venture agreements with industry partners, and through sale of assets. Our ability to obtain additional capital through new debt instruments, project financing and sale of assets may be subject to the repayment of our existing obligations.

Outsourcing.We intend to continue to use the services of independent consultants and contractors to provide various professional services, including land, legal, environmental, technical, investor relations and tax services.  We believe that by limiting our management and employee costs, we may be able to better control lifting costs and retain G&A flexibility. 

Principal Oil and Gas Interests

All references to production, sales volumes and reserve quantities are net to our interest unless otherwise indicated.

As of December 31, 20142016, we owned interests in approximately 67,000 gross (65,000 net) leasehold19,968 net acres, of which 59,000 gross (57,000 net)14,994 net acres are classified as undeveloped acreage and all of which are located in west Texas and New Mexico within the Delaware Basin and Colorado, Wyoming and Nebraska within the DJ Basin. Our primary targets within the DJDelaware Basin are the conventional DakotaWolfcamp formation as well as the Bone Springs and Muddy “J” formations, and the developing unconventional Niobrara shale play.   Additional horizons include the Codell, Greenhorn and other potential resource formations.    Avalon Formations.

Effective asAs of December 31, 2014,2016 and March 1, 2017, we completed an assessment of our inventory of unevaluated acreage, which resulted in a transfer of $9.90 million from unevaluated acreage to evaluated properties.   In assessing the unevaluated acreage, we analyzed the expiration dates during the years ended December 31, 2014had 2 gross (1.2 net) and 2015 of leases that are not otherwise renewable, and transferred such acreage1 gross (0.6 net) wells in the amountprocess of $6.99 million.  In addition tobeing drilled, respectively, all in the transfer of near and intermediate term expirations, we assessed carrying value of our remaining acreage, and concluded that an additional transfer of $2.91 million was necessary. No proved reserves were associated with the transferred acreage.Delaware Basin.

During 2014, we made minimal capital expenditures on our oil and gas properties due to capital constraints.

On September 2, 2014, we entered into a Final Settlement Agreement (defined below) to convey its interest in 31,725 evaluated and unevaluated net acres located in the DJ Basin and the associated oil and natural gas (the “Hexagon Collateral”) to its primary lender, Hexagon in exchange for extinguishment of all outstanding debt and accrued interest obligations owed to Hexagon aggregating to $15.1 million. The conveyance assigned all assets and liabilities associated with the property, which includes PDP and PUD reserves, plugging and abandonment, and other assets and liabilities associated with the property. Pursuant to the Final Settlement Agreement, we also issued to Hexagon $2.0 million in 6% Conditionally Redeemable Preferred Stock valued at $1.69 million and considered as temporary equity for reporting purposes. See Item 7 Management Discussion and Analysis of Financial Condition and Results of Operations—Overview of 2014 and Recent Developments —Hexagon Settlement and —Results of Operations—Loss on Conveyance of oil and gas properties.

Reserves

The table below presents summary information with respect to the estimates of our proved oil and gas reserves for the yearyears ended December 31, 2014.2016 and 2015. We engaged Ralph E. DavisCawley, Gillespie & Associates, Inc. (“RE Davis”CG&A”) and Forrest A. Garb & Associates to audit internalinternally prepared engineering estimates for 100 percentall of our proved reserves at year-end 2014.  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 prices used in the calculation offollowing table provides summary information regarding our proved reserve estimatesreserves as of December 31, 2014, were $81.71 per Bbl2016 and $5.34 per MCF; as of December 31, 2013, were $89.57 per Bbl2015, and $4.74 per MCF and as of December 31, 2012, were $87.37 per Bbl and $2.75 per MCFproduction for oil and natural gas, respectively.  The prices were adjusted for basis differentials, pipeline adjustments, and BTU content.

We emphasize that reserve estimates are inherently imprecise and that estimates of all new discoveries and undeveloped locations are more imprecise than estimates of established producing oil and gas properties.  Accordingly, these estimates are expected to change as new information becomes available.  The PV-10 values shown in the following table are not intended to represent the current market value of the estimated proved oil and gas reserves owned by us.  Neither prices nor costs have been escalated (or reduced).  The following table should be read along with the section entitled “Risk Factors — Risks Related to Our Company”.  The actual quantities and present values of our proved oil and natural gas reserves may be less than we have estimated.

Changes in Proved Undeveloped Reserves

The 476 MBOE or 45% increase of proved undeveloped reserves to 1,523 MBOE at year end 2014 from 1,047 MBOE at year end 2013 reflects, in part, additional proved undeveloped locations, partially offset by the 347 MBOE conveyed to Hexagon described in detail above. An acreage block owned by us was determined to be proved undeveloped based on offset successful drilling activity of other operators. We did not incur any cost on our proved undeveloped acreage in 2014. 

Effective as of December 31, 2014, we completed an assessment of our inventory of unevaluated acreage, which resulted in a transfer of $9.90 million to evaluated properties.   In assessing the unevaluated acreage, we analyzed its expiration dates during the years ended December 31, 20142016 and 2015. 

Estimated Total Proved Reserves

During the years ended December 31, 2016 and 2015, which are not otherwise renewable,we recognized an impairment expense of approximately $4.7 million and transferred such acreage$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 amount of $6.99 million.  In additionDJ Basin and the $24.5 million impairment charge for the year ended December 31, 2015 was attributable to the transferlack of nearcapital to develop our undeveloped oil and intermediate term expirations, we assessed the carrying value of our remaining acreage,gas properties and concluded that an additional transfer of $2.91 million was necessary. No proved reserves were associated with the transferred acreage.lower commodity prices.

At December 31, 2014, we have no proved undeveloped reserves that are scheduled for development five years or more beyond the date the reserves were initially recorded.

Internal Controls over Reserves Estimate

Our policy regarding internal controls over the recording of reserves is structured to objectively and accurately estimate our oil and gas reserve quantities and values in compliance with the regulations of the SEC.Securities Exchange Commission (the “SEC”). Responsibility for compliance in reserve bookings is delegated to our Chief Financial Officer with assistance from our senior geologist consultant principal accounting officer, 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.

Technical reviews are performed throughout the year by our senior reserve engineering consultant and our geologist and other consultants who evaluate all available geological and engineering data, under the guidance of the 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 20142016 reserve process was overseen by Kent Lina,Chris Cantrell, our senior reserve engineering consultant. Mr. Lina was previously employed by us from October 2010 through December 2012, and prior to that employed by Delta Petroleum Corporation from March 2002 to September 2010 in various operations and reservoir engineering capacities culminating as the Senior V.P. of Corporate Engineering.  Mr. Lina receivedCantrell holds a Bachelor of Science degree in CivilPetroleum Engineering fromconferred by Texas A&M University in 1995. He is a registered professional engineer licensed in the State of Missouri at RollaTexas, license number 90521. He has been continuously involved in 1981.  Mr. Lina currently serves various industry clients asevaluating oil and gas properties since 1997, and is a senior reserve engineering consultant.member of the Society of Petroleum Engineers and the American Petroleum Institute.

Third-party Reserves Study

An independent third-party reserve study as of December 31, 20142016, was performed by RE DavisCG&A using its own engineering assumptions and other economic data provided by us. One hundred percentAll of our total calculated proved reserve PV-10 value was audited by RE Davis.  RE DavisCG&A. CG&A is an independent petroleum engineering consulting firm that has been providing petroleum engineering consulting services for over 20 years. The individual at RE DavisCG&A primarily responsible for overseeing our reserve audit is Allen C. Barron, theTodd Brooker, Senior Vice President and CEO,of CG&A, who received a Bachelor of Science degree in Chemical and Petroleum Engineering from the University of HoustonTexas and is a registered Professional Engineer in the States of Texas. He is also a member of the Society of Petroleum Engineers.

The RE DavisCG&A report dated March 10, 2015,January 12, 2017, is filed as Exhibit 99.1 to this Annual Report.Report on Form 10-K.

Oil and gas reserves and the estimates of the present value of future net cash flows therefrom were determined based on prices and costs as prescribed by the SEC and Financial Accounting Standards Board (“FASB”) guidelines. Reserve calculations involve the estimate of future net recoverable reserves of oil and gas and the timing and amount of future net cash flows to be received therefrom. Such estimates are not precise and are based on assumptions regarding a variety of factors, many of which are variable and uncertain. Proved reserves were estimated in accordance with guidelines established by the SEC and the FASB, which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalations except by contractual arrangements. For the yearyears ended December 31, 2014,2016 and 2015, commodity prices over the prior 12-month period and year end costs were used in estimating net cash flows in accordance with SEC guidelines.

In addition to a third partythird-party reserve study, our reserves and the corresponding report are reviewed by our Chief Financial Officer, geologist and principal accounting officer and the Audit Committee of our Board of Directors. Our Chief Financial Officer is responsible for reviewing and verifying that the estimate of proved reserves is reasonable, complete, and accurate. The Audit Committee of our Board of Directors reviews the final reserves estimate in conjunction with RE Davis’CG&A’s audit letter.

Production

The following table summarizes the average volumes and realized prices excluding the effects of our economic hedges, of oil and gas produced from properties in which we held an interest during the periods indicated.  Also presented is aindicated, and production cost per BOE summary: BOE:

Productive WellsOil and gas production costs, production taxes, depreciation, depletion, and amortization

Drilling Activity

As of December 31, 2014, after the conveyance on September 2, 2014,2016, we have drilled 1.2 net productive wells.

As of December 31, 2016 and 2015, we had working interests in 35 gross (21 net) wells and 6 gross (1.27 net) productive oil wells, and 2 gross (.14 net) productive gas wells.respectively. Productive wells are either wells producing in commercial quantities or wells capable of commercial production, althoughbut are currently shut-in. 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 gas well based on the ratio of gas to oil produced when it first commenced production, and such designation may not be indicative of current production.

Acreage

As of December 31, 2016, we owned 36 producing wells within the Delaware Basin in Texas and New Mexico and in the DJ Basin in Colorado, as well as approximately 34,858 gross (19,968 net) acres, of which 25,752 gross (14,994 net) acres were classified as undeveloped acreage. Our primary 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, 20142015, we owned 8 producing wells in Wyoming, Nebraska and Colorado within the DJ Basin, as well as approximately 67,00018,000 gross (65,000(16,000 net) acres, of which 59,00010,000 gross (57,000(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.

The following table sets forth certain information with respect to our gross and net developed and undeveloped acreage as of December 31, 2014.2016 and 2015:

At December 31, 2014,As of March 1, 2017, our inventory of developed and undeveloped acreage includes approximately 8,000 net40,618 gross (21,178 net) acres, of which 9,106 gross (5,248 net) acres that are held by production, approximately, 49,000, 2,000 and 5,000 and 1,000 net acres that expire in the years 2015, 2016, 2017, and thereafter, respectively. Approximately 89% of our inventory of undeveloped acreage provides for extension of lease terms from twoproduction. We will continue to five years, at the option of us, via payment of varying, but typically nominal, extension amounts. We’re currently evaluating the 2015 lease expirations to determine if this acreage is a focus for future development. If determined to be a focus for future development, we plan to re-lease if available. If not a focus, we plan to let the acreage expire. We plan to borrowpursue additional funds under the Credit Agreement and to seek additional debt or equity capital, if available, to acquire additional bolt-on properties, acquire other properties primarily targeted in the Delaware Basin, but potentially throughout North America, or drill wells on our core properties to hold the property by production.production if financing is available to us and the properties are economic.

Drilling ActivityTitle to Properties

The following table describes the development and exploratory wells we drilled from 2012 through 2014:

The number of wells drilled refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated.  As of December 31, 2014, we had no drilling activities on-going.

Title to Properties

Substantially allApproximately 66% of our leasehold interests are held pursuant to leases from third parties. Theby production, with the majority of our producing properties areDelaware Basin leasehold position subject to mortgages securing indebtedness under our Credit Agreementcredit and Debentures, which weguarantee 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 in our properties do not materially interfere with the use of, or affect the value of, such properties.

Capital Budget

We anticipate a capital budget of up to $50.0 million for 2015. The budget is allocated toward the acquisition of properties and companies in North America and to develop eight operated wells focused on unconventional reservoirs located in the Wattenberg field within the DJ Basin that will apply horizontal drilling in the Niobrara shale and Codell formations.

The entire capital budget is subject to the ability to secure additional capital through equity placement, utilizing borrowings under the Credit Agreement with Heartland Bank and additional debt instruments and funds contemplated by the agreement with Heartland Bank to acquire production in North America.

In addition to the need to secure adequate capital to fund our capital budget, the execution of, and results from, our capital budget are contingent on various factors, including, but not limited to, market conditions, oilfield services and equipment availability, commodity prices and drilling/ production results.  Results from the wells identified in the capital budget may lead to additional adjustments to the capital budget. Other factors that could impact our level of activity and capital expenditure budget include, but are not limited to, a reduction or increase in service and material costs, the formation of joint ventures with other exploration and production companies, and the divestiture of non-strategic assets.

As of December 31, 2014 and December 31, 2013, we had $6.04 million and $1.15 million of wells in progress, respectively. Wells in progress are related to certain wells in our core development program within the Northern Wattenberg field. We capitalized and accrued approximately $5.70 million of costs through December 31, 2014 associated with these wells, which are currently in dispute.

The dispute relates to our interest in certain producing wells and the well operator’s assertion that the Company’s interest was reduced and/or eliminated as a result of a default or a farm-out agreement. Underlying the dispute is a Joint Operating agreement (“JOA”), which provides the parties with various rights and obligations.

On March 6, 2015, the Company filed a lawsuit against the operator.  In its complaint, we seek monetary damages and declaratory relief on claims of breach of contract, breach of the implied covenant of good faith and fair dealing, tortious breach of the implied covenant of good faith and fair dealing, unjust enrichment, conversion and declaratory judgment related to the JOA. The operator has not yet responded to the complaint.

Marketing and Pricing

We derive revenue and cash flow principally from the sale of oil and natural gas. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil and natural gas. We sell our oil and natural gas on the open market at prevailing market prices or through forward 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:

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 circumstances where:instances in which:

In addition, hedging arrangements may limit the benefit we would receive from increases in the prices for oil and natural gas. We cannot assure you that any hedging transactions we may enter into will adequately protect us from declines in the prices of oil and natural gas.

As of December 31, 2014,2016, we had no hedging agreements in place.

Major Customers

We have oneOur major customer, Shell Trading (US)customers for the year ended December 31, 2016 include Noble Energy, Inc., whichTexican Natural Gas Company, and Energy Transfer Partners, L.P., who accounted for approximately 63%41%, 38%, and 83% of our revenues for the years ended December 31, 2014 and 2013, respectively.  PDC Energy, a new customer in 2014, accounted for 13%16% of our revenue for the year ended December 31, 2014.

However, we does2016, 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 aany single purchaser, including Shell Trading (US) and PDC Energy,customer would materially affect our business because there are numerous other potential purchasers in the area in which we sellof our production.

Seasonality

Generally, 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.

Competition

The oil and gas industry is intensely competitive, particularly with respect to acquiring prospective oil and natural gas properties. We believe 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, which have larger technical staffs and greater financial and operational resources than we do.  Many of these companies not only engage in the acquisition, exploration, development, and production of oil and natural gas reserves, but also have refining operations, market refined products, own drilling rigs, and generate electricity.

We also compete with other oil and gas companies in attempting to secure drilling rigs and other equipment and services necessary for the drilling, completion, production, processing and maintenance of wells. Consequently, we may face shortages or delays in securing these services from time to time. The oil and gas industry also faces competition from alternative fuel sources, including other fossil fuels such as coal and imported liquefied natural gas. Competitive conditions may also be affected by future new energy, climate-related, financial, and other policies, legislation, and regulations.

In addition, we compete for people, including experienced geologists, geophysicists, engineers, and other professionals and consultants. Throughout the oil and gas industry, the need to attract and retain talented people has grown at a time when the number of talented people available is constrained. We are not insulated from this resource constraint, and we must compete effectively in this market in order to be successful.

Government RegulationsRegulation of the Oil and Natural Gas Industry

General.Our operations covering the exploration, production and sale of oil and natural gas are subject to various types of federal, state and local laws and regulations. The failure to comply with these laws and regulations can result in substantial penalties. These laws and regulations materially impact our operations and can 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, etc.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 viathrough our strict attention to regulatory compliance, the requirements of such laws and regulations are frequently changed.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 the ultimate cost of compliance with these requirementswhen or their effect on our actual operations.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.

Federal Income TaxRegulation of Production of Oil and Natural Gas. Federal income tax laws significantly affect our operations.  The principal provisions that affect us are those that permit us,production of oil and natural gas is subject to certain limitations, to deduct as incurred, rather than to capitalizeregulation under a wide range of local, state and amortize/depreciate, our domestic “intangiblefederal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. We own interests in properties located in Texas, which regulates drilling and development costs”operating activities by requiring, among other things, permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and to claim depletion onregulating 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 portionnumber of our domesticconservation matters, including provisions for the unitization or pooling of oil and natural gas properties, based on 15%the establishment of ourmaximum allowable rates of production from oil and natural gas gross incomewells, 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 properties (upregulations or to an aggregate of 1,000 barrels per day of domestic crudehave reductions in well spacing or density. Moreover, Texas imposes a 4.6% severance tax on oil and/or equivalent units of domesticproduction and a 7.5% severance tax on natural gas). gas production. The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Environmental, Health, and Safety Regulations.Our operations are subject to stringent federal, state, and local laws and regulations relating to the protection of the environment and human health and safety (“EHS”). We are committed to strict compliance with these regulations and the utmost attention to EHS issues. Environmental laws and regulations may require that permits be obtained before drilling commences or facilities are commissioned, restrict the types, quantities, and concentration of various substances that can be released into the environment in connection with drilling and production activities, govern the handling and disposal of waste material, and limit or prohibit drilling and exploitation activities on certain lands lying within wilderness, wetlands, and other protected areas, including areas containing threatened or endangered animal species. As a result, these laws and regulations may substantially increase the 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 obligations in the event of any discharges or emissions in violation of these laws and regulations. Further, legislative and regulatory initiatives related to global warming or climate change could have an adverse effect on our operations and the demand for oil and natural gas. See “Risk Factors — Risks RelatedFactors-Risks Relating to the Oil and Gas Industry — LegislativeIndustry-Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for oil and natural gas.” The following is a summary of the more significant existing and proposed environmental and occupational health and safety laws and regulations to which our business operations are or may be subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position. 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.

The Resource Conservation and Recovery Act

The Resource Conservation and Recovery Act of 1976, as amended (“RCRA”), and the comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. The RCRA imposes stringent operating requirements, 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, the 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, 2016, moreover, the NRDC, along with other environmental organizations, commenced a lawsuit against the EPA, asking the U.S. District Court for the District of Columbia to order the agency to “revise” its RCRA regulations as they pertain to oil and gas wastes. On December 28, 2016, the court signed a consent decree, resolving the lawsuit, under which the EPA agreed that, by March 15, 2019, it will either sign a notice of proposed rulemaking for a revision of its RCRA regulations as they pertain to oil and gas wastes (in which case it will take a final action on the proposed rulemaking by July 15, 2021) or sign a determination that no such revision is necessary. 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, increased operating expenses.

Water Discharges

The Federal Water Pollution Control Act, also known as the Clean Water Act (the “Clean Water Act”) imposes restrictions and controls on the discharge of produced waters and other oil and natural gas wastes into navigable 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. The EPA and U.S. Army Corps of Engineers released a Connectivity Report in September 2013, which determined that virtually all tributary streams, wetlands, open water in floodplains and riparian areas are connected. This report supported the drafting of proposed rules providing updated standards 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 February 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 stay of the rules remains in place. 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.

The Oil Pollution Act of 1990 (“OPA”) and regulations thereunder impose 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 to each responsible party for oil removal costs and a variety of public and private damages, including 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

The 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. In response to recent seismic events near underground injection wells used for the disposal of oil and gas-related wastewaters, federal and some state agencies have begun 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 response to these concerns, regulators in some states are considering additional requirements related to seismic safety. For example, 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.

Air Pollutant Emissions

The federal Clean Air Act (the “Clean Air Act”) and comparable state and local air pollution laws adopted to fulfill its mandate provide a 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. 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.” 

On October 1, 2015, under the Clean Air Act, the EPA lowered the national ambient air quality standard for ozone from 75 ppb to 70 ppb. 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.

Regulation of “Greenhouse Gas” Emissions

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA, under the Clean Air Act, has adopted regulations that, among other things, establish Prevention of Significant Deterioration (“PSD”), construction, and Title V operating permit requirements for certain new and modified large stationary sources. Facilities required to comply 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, the EPA has adopted 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 certain 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 include gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells. The revisions also include the addition 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.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions 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 limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations 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.

Hydraulic Fracturing Activities

Hydraulic fracturing is an important and 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— RisksFactors-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.

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.

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.

Several states, 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. 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 RRC 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.

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.

A variety of federal 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 and to the temporary or permanent curtailment or cessation of all or a portion of our operations.

Comprehensive Environmental Response, Compensation and Liability Act

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

The Resource Conservation

We generate materials in the course of our operations that may be regulated as hazardous substances. Despite the “petroleum exclusion” of CERCLA, which currently encompasses natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, Recovery Actas a result, may be jointly and severally liable under CERCLA for all or part of 1976, as amended (“RCRA”) is the principal federal statute governingcosts required to clean up sites at which these hazardous substances have been released into the treatment, storage and disposal of solid and hazardous wastes.  RCRA imposes stringent operating requirements, and liabilityenvironment. In addition, we currently own, lease, or operate numerous properties that have been used 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, RCRA includes an exemption that allows certain oil and natural gas exploration, production and productionprocessing for many years. Although we believe that we have utilized operating and 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 timesdisposal practices that were standard in the past, proposalsindustry at the time, hazardous substances, wastes, or hydrocarbons may have been made to amend RCRA to rescindreleased on, under or from the exemption that excludes oilproperties 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 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 with the Environmental Protection Agency (“EPA”) requesting that the agency reassess its prior determination that certain E&P wastes are not subject to the RCRA hazardous waste requirements. EPA has not yet acted on the petition and it remains pending. Repeal or modification of the exemption by administrative, legislative or judicial process, or modification of similar exemptions in applicable state statutes, would increase the volumedisposal of hazardous waste we are required to managesubstances, wastes, or hydrocarbons was not under our control. These properties and dispose of and would cause us to incur, perhaps significantly, increased operating expenses.

The Oil Pollution Act of 1990 (“OPA”), and regulations thereunder impose a variety of regulationsthe substances disposed or released on, “responsible parties” related to the prevention of oil spills and liability for damages resultingunder or from such spills in United States waters.  The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages, including 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 OPA. In addition, to the extent we acquire offshore leases and those operations affect state waters, wethem may be subject to additional stateCERCLA, RCRA and local clean-up requirements or incur liability underanalogous state and local laws. OPA also imposes ongoing requirements on responsible parties, including proofUnder such laws, we could be required to undertake investigatory, response, or corrective measures, which could include soil and groundwater sampling, the removal of financial responsibilitypreviously disposed substances and wastes, the cleanup of contaminated property, or performance of remedial plugging or pit closure operations to cover at least someprevent future contamination, the 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 notof which could be any more adverse to us than it will be to other similarly situated owners or operators.substantial.

Endangered Species Act and Migratory Birds

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

NEPA

Additionally, 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.

The federal Clean Water Act (the “Clean Water Act”), imposes restrictions and controls on the discharge of produced waters and other oil and natural gas wastes into navigable 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 (“NPDES”) program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances relatedOSHA

We are subject 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 ("SPCC") requirements of the CWA require appropriate secondary containment loadout controls, piping controls, bermsOSHA and other measurescomparable state statutes whose purpose is to help preventprotect the contaminationhealth and safety of navigable waters inworkers. In addition, the event of a petroleum hydrocarbon spill, rupture or leak. The EPAOSHA hazard communication standard, the Emergency Planning and U.S. Army Corps of Engineers released a Connectivity Report in September 2013, which determined that virtually all tributary streams, wetlands, open water in floodplains and riparian areas are connected. This report supported the drafting of proposed rules providing updated standards for what will be considered jurisdictional waters of the U.S. The proposed rules have been submitted for public comment, and are expected to be finalized in 2015. The Clean WaterCommunity Right-to-Know 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 believeimplementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations comply in all material respects with the requirements of the Clean Water Act and that this information be provided to employees, state statutes enacted to control water pollution.

The Safe Drinking Water Act of 1974, as amended, establishes a regulatory framework for the underground injection of a variety of wastes, including bring produced and separated from crude oillocal governmental authorities 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.citizens. We believe that we are in substantial compliance inwith all material respects with the requirements of applicable state underground injection control programslaws and our permits.regulations relating to worker health and safety.

The federal Clean Air Act (the “Clean Air Act”) and comparable state and local air pollution laws adopted to fulfill its mandate provide a framework 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.  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.  EPA promulgated significant New Source Performance Standards (“NSPS OOOO”) in 2012, as amended in 2013 and 2014, which have added administrative and operational costs. EPA is reconsidering portions of NSPS OOOO and this process may result in additional federal control requirements. Colorado adopted NSPS OOOO in 2014. In addition, Colorado adopted new air regulations for the oil and gas industry effective April 14, 2014, that impose control and other requirements more stringent than NSPS OOOO. These new Colorado oil and natural gas air rules will likely increase our administrative and operational costs.

On December 17, 2014, the EPA proposed to revise and lower the existing 75 ppb national ambient air quality standard (“NAAQS”) for ozone under the federal Clean Air Act to a range within 65-70 ppb. EPA is also taking public comment on whether the ozone NAAQS should be revised as low as 60 ppb. A lowered ozone NAAQS in a range of 60-70 ppb could result in a significant 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 increase regulatory burdens in the form of more stringent emission controls, emission offset requirements, and increased permitting delays and costs.State Laws

There are numerous state laws and regulations in the states in whichwhere we operate whichthat relate to the environmental aspects of our business. These stateSome of those laws and regulations generallyare discussed above. They relate to, among other things, requirements to remediate spills of deleterious substances associated with oil and gas activities, the conduct of salt water disposal operations, and the methods of plugging and abandonment of oil and gas wells which have been unproductive. Numerous state laws and regulations also relate to air and water quality.

In 2014, Colorado Governor Hickenlooper created the Task Force on State and Local Regulation of Oil and Gas Operations (“Task Force”) to provide recommendations regarding the state and local regulation of oil and gas operations. The Task Force provided its final recommendations on February 27, 2015, which include recommendations for future Colorado rulemakings or legislation to address, among others, local government collaboration with oil and gas operators, operator registration requirements with local governments and submission of operational information for incorporation into local comprehensive plans, and creation of an oil and gas information clearinghouse. We cannot predict the ultimate outcome of the Task Force’s recommendations.

Additionally, the Colorado Oil and Gas Conservation Act was amended in 2014 to increase the potential sanctions for violating the Act or its implementing regulations, orders, or permits. These amendments increase the maximum penalty per violation per day from $1,000 to $15,000; eliminate a $10,000 maximum penalty for violations that do not result in significant waste of oil and gas resources, damage to correlative rights, or adverse impact to public health, safety, or welfare; require the Colorado Oil and Gas Conservation Commission (“COGCC”) to assess a penalty for each day there is evidence of a violation; and authorize the COGCC to prohibit the issuance of new permits and suspend certificates of clearance for egregious violations resulting from gross negligence or knowing and willful misconduct. In 2015, the COGCC, consistent with the amendments to the Act, amended its regulations governing enforcement and penalties. We cannot predict how such regulatory amendments will ultimately affect the penalties assessed by the COGCC in future enforcement cases involving us.General

We do not believe that our environmental risks will be materially different from those of comparable companies in the oil and gas industry. We believe our present activities substantially comply, in all material respects, with existing environmental laws and regulations. Nevertheless, we cannot assure you that environmental laws will notmay result in a curtailment of production or material increase in the cost of production, development or exploration orand 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.

Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted 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. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and release of our natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless 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.

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

Oil Sales and Transportation. Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Our crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is 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, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.

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

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

Federal Leases. For those operations on federal oil and gas leases, such operations must comply with numerous regulatory restrictions, including various non-discrimination statutes, and certain of such operations must be conducted pursuant to certain on-site security regulations and 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 severely limits the types of costs that are deductible transportation costs for purposes of royalty valuation of production sold off the lease. In particular, ONRR prohibits deduction of costs associated with marketer fees, cash out and other pipeline imbalance penalties, or long-term storage fees. Further, the ONRR has 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.

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

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.

Other Laws and Regulations. Various laws and regulations require permits for drilling wells and also cover spacing of wells, the prevention of waste of natural gas and oil 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 by 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 date we have not experienced any material adverse effect 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.

Employees

As of December 31, 2014,2016, we had threenineteen full-time employees and notwo part-time employees.  Subsequent to year end, we added two employees, including Kevin Nanke as Chief Financial Officer and Ariella Fuchs as General Counsel. For the foreseeable future, we intend to onlycontinue to add additional personnel as our operational requirements grow. In the interim, weWe plan to continue to leverage the use of independent consultants and contractors to provide various professional services, including additional land, legal, engineering, geology, environmental and tax services.  We believe that by limiting our management and employee costs, we are able to better control total costs and retain flexibility in terms of project management.

Executive Officers of the CompanyAvailable Information

Our executive officers of the Company at the time of this filing are as follows:

Available Information

Our executive offices are located at 216 16^th Street, Suite 1350, Denver, Colorado 80202,on February 28, 2017 and moved our corporate headquarter to 300 E. Sonterra Blvd., Suite No. 1220, San Antonio, Texas 78258, and our telephone number is (303) 893-9000.(210) 999-5400. Our web site is www.lilisenergy.com. Additional information that may be obtained through our web site does not constitute part of this annual reportAnnual Report on Form 10-K. Our annual reportAnnual 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 free of charge at our website. The SEC also maintains an internet site that contains reports, proxy and information statements and other information regarding our filings atwww.sec.gov. www.sec.gov.

Item 1A. Risk Factors

Investing in our shares of common stock involves significant risks, including the potential loss of all or part of your investment. These risks could materially affect our business, financial condition and results of operations and cause a decline in the market price of our shares. You should carefully consider all of the risks described in this annual report,Annual Report on Form 10-K, in addition to the other information contained in this annual report,Annual Report on Form 10-K, before you make an investment in our shares.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:

Risks RelatedRelating to Our CompanyBusiness

If we are not able to access additional capital in significant amounts, we may not be able to develop our current prospects and properties, or we may forfeit our interest in certain prospects and we may not be able to continue to operate our business.

We need significant additional capital to continue to operate our properties and continue operations. Currently, a significant portion of our revenue after field level operating expenses is required to be paid to our lenders as debt service.

In the near term, we intend to finance our capital expenditures with cash flow from operations, sales of non-core property assets, future issuance of debt and/or equity securities and entry into a new credit facility. Our cash flow from operations and access to capital is subject to a number of variables, including:

Our operations and other capital resources may not provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Further, our actual capital expenditures in 2017 could exceed our capital expenditure budget. In the event our capital expenditure requirements at any 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 and natural gas reserves, 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.

We 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 time

Oil, NGL and natural gas prices are volatile and have declined significantly from levels experienced in recent years. If commodity prices experience a further, substantial decline, our operations, financial condition, and level of expenditures for the development of our oil, NGL, and natural gas reserves may be materially and adversely affected.

The prices we receive for our oil, NGLs, and natural gas production heavily influence our revenue, operating results, profitability, access to capital, future rate of growth and carrying value of our properties. Oil, NGLs, and natural gas are commodities, and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the commodities markets have been volatile, and these markets will likely continue to be volatile in the future. If the prices of oil, NGLs, and natural gas experience a further, substantial decline, our operations, financial condition and level of expenditures for the development of our oil, NGLs, and natural gas 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 and include the following:

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, and natural gas that we can produce economically, 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 expenditures may be materially and adversely affected.

Our level of indebtedness could adversely affect our ability to raise additional capital to fund our operations, limit our ability to react to changes in the economy or our industry and prevent us from meeting our obligations under our indebtedness. As of December 31, 2014, our total outstanding debt under our convertible debentures equaled $6.84 million. We currently have

On September 29, 2016, we entered into the Credit Agreement that provides for a three-year senior secured term loan inwith an initial aggregate principal amount of $3.0 million.$31.0 million outstanding as of December 31, 2016, and $38.1 million outstanding as of March 1, 2017. We also have a $2.0may borrow up to an aggregate principal amount of $50 million mandatory redeemable preferred stock currently valued at $1.69 million. While transactions in 2014 have significantly reduced our debt, ourunder the Credit Agreement. Our degree of leverage could have important consequences, including the following:

We may incur additional debt, including secured indebtedness, or issue preferred stock in order to maintain adequate liquidity and develop ourand acquire properties to the extent desired. A higher level of indebtedness and/or preferred stock increases the risk that we may default on our obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, natural gas and oil prices and financial, business and other factors affect our operations and 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.

Our inability to access additional capital in significant amounts as needed,The Credit Agreement, guaranteed and further secured by substantially all our assets, contains restrictive covenants that may result in our inability to develop our current prospects and properties, cause us to forfeit our interest in certain prospects and inhibitlimit our ability to develop our business.respond to changes in market conditions or pursue business opportunities.We plan to seek to obtain additional capital through the sale of our equity or debt securities, the successful deployment of our cash on hand, bank lines of credit, joint ventures, and project financing. Consequently, there can be no assurance we will be able to obtain continued access to capital as and when needed or, if so, that the terms of any available financing will be commercially reasonable. Currently, a significant portion of our revenue after field level operating expenses is required to be paid to our lenders as debt service. If we are unable to access additional capital in significant amounts as needed, we may not be able to develop our current prospects and properties, may have to forfeit our interest in certain prospects and may not otherwise be able to develop our business. In such an event, our stock price could be materially adversely affected.

We have historically incurred losses and cannot assure investors as to future profitability. We have historically incurred losses from operations during our history in the oil and natural gas business.  We had a cumulative deficit of approximately $147.82 million and $115.53 million as of December 31, 2014 and 2013, respectively.  Many of our properties are in the exploration stage, and to date we have established a limited volume of proved reserves on our properties.  Our ability to be profitable in the future will depend on successfully addressing our near-term capital need to refinance our term loan indebtedness and fund our 2015 capital budget, and implementing our acquisition, exploration, development and production activities, all of which are subject to many risks beyond our control.  Even if we become profitable on an annual basis, we cannot assure youThe Credit Agreement contains restrictive covenants that our profitability will be sustainable or increase on a periodic basis.

We will require additional capital in order to achieve commercial success and, if necessary, to finance future losses from operations as we endeavor to build revenue, but we do not have any commitments to obtain such capital and we cannot assure you that we will be able to obtain adequate capital as and when required.  The business of oil and gas acquisition, drilling and development is capital intensive and the level of operations attainable by an oil and gas company is directly linked to and limited by the amount of available capital.  We believe thatlimit our ability to, achieve commercial success and our continued growth will be dependent on our continued access to capital either through the additional sale of our equity or debt securities, bank lines of credit, project financing, joint ventures, sale or lease of undeveloped acreage, or cash generated from oil and gas operations. We will seek to obtain additional capital through the sale of our equity or debt securities, the successful deployment of our cash on hand, bank lines of credit, joint ventures, and project financing.  Consequently, there can be no assurance we will be able to obtain continued access to capital as and when needed or, if so, that the terms of any available financing will be commercially reasonable.  If we are unable to access additional capital in significant amounts as needed, we may not be able to develop our current prospects and properties, may have to forfeit our interest in certain prospects and may not otherwise be able to develop our business. In such an event, our stock price could be materially adversely affected.  among other things:

We have limited management and staff and will be dependent upon partnering arrangements.We had three employees at the end of December 31, 2014.  Subsequent to year end, we hired Kevin Nanke as our Chief Financial Officer and Ariella Fuchs as our General Counsel. We leverage the services of independent consultants and contractors to perform various professional services, including engineering, oil and gas well planning and supervision, and land, legal, environmental and tax services. We also pursue alliances with partners in the areas of geological and geophysical services and prospect generation, evaluation and prospect leasing. Our dependence on third party consultants and service providers creates a number of risks, including but not limited to:

IfThe requirement that 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 becomply with these provisions may materially adversely affected.

The loss of our Chief Executive Officer or Chief Financial Officer could adversely affect us.We are dependent on the experience of our executive officers to guide the implementation of our operational objectives and growth strategy.  The loss of the services of any of these individuals could have a negative impact on our operations and our ability to implementreact 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 strategy. Our executive employment contracts include long term incentives to retain key personnel but retention of personnel is not guaranteed.business.

We may from time to time enter into alternative or additional debt agreements that contain covenant restrictions 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 may make it difficult for us to successfully execute our business strategy or effectively compete with companies that are not similarly restricted.

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

Our management including our chief executive officer and chief financial officer, does not expect that our disclosure controls and procedureprocedures and internal controls will 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 control system are being met. In addition, the design of a control system must reflect the fact that there are resource constraints, and the benefitbenefits of controls are evaluated relative to their costs. Because of the inherent limitations in all control systems, no evaluation of our controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected. The design of any system of controls is based in part upon the likelihood of future events, and there can be no assurance that any design willmay 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 itsour 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.

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

Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, and the rules and regulations promulgated by the Securities and Exchange Commission, or the SEC to implement Section 404, we are required to furnish a report by our management to include in our annual report on Form 10-K regarding the effectiveness of ouris responsible for establishing and maintaining adequate internal control over financial reporting. The report includes, among other things,Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external purposes in accordance with generally accepted accounting principles. Under the supervision and with the participation of our management, including the Chief Executive Officer and the Chief Financial Officer, we are required to conduct an assessmentevaluation of the effectiveness of our internal control over financial reporting asbased on framework of internal control issued by the Committee of Sponsoring Organizations of the endTreadway Commission (“COSO”). Because of our fiscal year, including a statement asits inherent limitations, internal controls over financial reporting may not prevent or detect misstatements. In addition, projections of any evaluation effectiveness to whetherfuture periods are subject to the risk that controls may become inadequate because of changes in conditions, or not ourthat the degree of compliance with the policies and procedures may deteriorate.

Through September 30, 2016, management had concluded that its internal control over financial reporting iswas not effective. This assessment must include disclosureDuring the fourth quarter of any material weaknesses in2016, we completed our internal control over financial reporting identified by management.

Weremediation efforts, but we may discover additional areas of our internal control over financial reporting in the future which may require improvement. If we are unable to assert that our internal control over financial reporting is effective now or in any future period, or if our auditors are unable to express an opinion on the effectiveness of our internal controls, we could lose investor confidence in the accuracy and completeness of our financial reports, which could have an adverse effect on our stock price.

In addition to acquiring producing properties, we expect to also attempt to grow our business through the acquisition and development of exploratory oil and gas prospects, which is the riskiest method of establishing oil and gas reserves.  In addition to acquiring producing properties, we expect to acquire, drill and develop exploratory oil and gas prospects that may or may not be profitable to produce.  Developing exploratory oil and gas properties requires significant capital expenditures and involves a high degree of financial, technical and operational risk.  The budgeted costs of drilling, completing, and operating exploratory wells are often exceeded due to subsurface uncertainties and can increase significantly when market drilling costs rise.  Drilling may be unsuccessful for many reasons, including unexpected geological issues, poor reservoir quality, title problems, weather, cost overruns, equipment shortages, and operational/mechanical difficulties.  Moreover, the successful drilling or completion of an exploratory oil or gas well does not ensure a profit on investment.  Exploratory wells bear a much greater investment and operational risk than development wells.  We cannot assure you that our exploration, exploitation and development activities will result in profitable operations.  If we are unable to successfully identify, acquire and develop commercial, exploratory oil and gas prospects, our results of operations, financial condition and stock price may be materially adversely affected

If oil or natural gas prices decrease or exploration and development efforts are unsuccessful, wells in progress are deemed unsuccessful, or major tracts of undeveloped acreage expire, or other similar adverse events occur, we may be required to write-down the carrying value of our developed properties.

We use the full cost method of accounting whereby all costs related to the acquisition and development of oil and natural gas properties are capitalized into 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. Under the 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. Should the capitalized costs of the full cost pool exceed this ceiling, we would recognize an impairment expense. DuringWe recognized an impairment expense of approximately $4.7 million and $24.5 million for the yearyears ended December 31, 2014, we did2016 and 2015, respectively. At December 31, 2016, the Company’s estimates of undiscounted future cash flows indicated that the carrying amounts were not recognize anexpected 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.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. Future write-downs could occur for numerous reasons, including, but not limited to continued reductions in oil and gas prices that lower the estimate of future net revenues from proved oil and natural gas reserves, revisions to reserve estimates, or from the addition of non-productive capitalized costs to the full cost pool that do not result in corresponding increase in oil and gas reserves. Impairments of undeveloped acreage and plugging and abandonment of wells in progress are other areas where costs may be capitalized into the full cost pool, without any corresponding increase in reserve values; as such, these situations could result in future additional impairment expenses.

If commodity prices stay at current early 2015 levels or decline further, we willcould incur full cost ceiling impairments in future quarters. Because the ceiling calculation uses rolling 12-month average commodity prices, the effect of lower quarter-over-quarter prices in 20152016 compared to 20142015 is a lower ceiling value each quarter. This willmay result in ongoing impairments each quarter until prices stabilize or improve. Impairment charges would not affect cash flow from operating activities, but would adversely affect our net income and stockholders’ equity.

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

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

Further, the present value of future net cash flows from proved reserves may not be the current market value of estimated oil and natural gas reserves. 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 value 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 oil 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, as well as the carrying value of our properties, are substantially dependent on prevailing prices of oil and natural gas.

Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production and the levels of our production depend on numerous factors beyond our control. These factors include the following:

Volatile oil and natural gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market 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.

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

In order to manage our exposure to price risks in the marketing of our oil and natural gas, from time to time, we may enter into derivative contracts 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:

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

As of December 31, 2014,2016, we had no hedging agreements in place.

Our large inventoryidentified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of undeveloped acreageour drilling.

Our management has specifically identified and large percentage of undeveloped proved reserves may create additional economic risk.  Our success is largely dependent upon our ability to develop our large inventoryscheduled drilling locations as an estimation of future multi-year drilling activities on existing acreage. These scheduled drilling locations undeveloped acreage and undeveloped reserves. As of December 31, 2014, approximately 95%represent a significant component of our total proved reserves and 88% of our total acreage were undeveloped.  To the extent our drilling results are not as successful as we anticipate, natural gas and oil prices decline, or sufficient funds are not available to drill these locations and reserves, we may not capture the expected or projected value of these properties. As previously disclosed, 49,000 of our 57,000 undeveloped acres are subject to lease expirations in 2015. We are currently evaluating the 2015 lease expirations to determine if this acreage is a focus for future development. If determined to be a focus for future development, we plan to re-lease if available. If not a focus, we plan to let the acreage expire. In addition, delays in the development of our reserves or increases in costsgrowth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability of capital, costs, drilling results, regulatory approvals and other factors. Because of these uncertainties, we do not know if the potential drilling locations previously identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, reserves will reduce the economic PV-10 value of and delay cash flowactual drilling activities may materially differ from our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic.

We may have difficulty managing growth in our business,those presently identified, 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.

business.

The actual quantities and present value of our proved reserves may be lower than we have estimated. In addition, the present value of future net cash flow from our proved reserves will not necessarily be the same as the current market value of our estimated provedDrilling for oil and natural gas reserves.is a speculative activity and involves numerous risks and substantial and uncertain costs that could adversely affect us.This annual report contains estimates

Our success will depend on the success of our proveddrilling program. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. 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 wells 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. Drilling for oil and natural gas reservesinvolves numerous risks, including the risk that no commercially productive natural gas or oil reservoirs will be discovered. The cost of drilling, completing, and the estimated futureoperating wells is substantial and uncertain, and drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors beyond our control, including:

If we decide to drill a certain location, there is a risk that (i) no commercially productive oil or natural gas reservoirs will be found or produced, or (ii) we may drill or participate in new wells that are not productive or drill wells that are productive, but that do not produce sufficient net revenues to return a profit after drilling, operating and other costs. 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 thesethe 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 harm 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 contained in our filings withfrom the SEC. The reserve estimate included in this annual report was preparedwell or abandonment of the well.

Financial difficulties encountered by our current reserve engineer consultant, reviewed by ourChief Financial Officer and Principal Accounting Officer/Controller and audited by RE Davis. The process of estimating oil and natural gas reserves is complexpurchasers, third party operators or other third parties could decrease cash flow from operations and requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering, cost basis, commodity pricing and economic data for each reservoir. Accordingly, these estimates are inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development and operating expenses, and quantities of recoverable oil and natural gas reserves most likely will vary from these estimates and vary over time. Such variations may be significant and could materiallyadversely affect the estimated quantities and present value of our proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, results of secondary and tertiary recovery applications, prevailing oil and natural gas prices and other factors, many of which are beyond our control. You should also not assume that our initial rates of productionactivities.

We derive essentially all of our wells are representative of future overall production from other wells or over the life of the wells, or that early results suggesting lack of reservoir continuity will prove to be accurate.

You should not assume that the present value of future net cash flow referred to in this annual report is the current market value of our estimated oil and natural gas reserves.  In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on the un-weighted average of the closing prices during the first day of each of the year preceding the end of the fiscal year.  Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate.  Any change in global markets consumption by oil or natural gas purchasers or in governmental regulations or taxation will also affect actual future net cash flows.  The timing of both the production and the expensesrevenues from the development and productionsale of our oil and natural gas to unaffiliated third party purchasers, independent marketing companies and mid-stream companies. Any delays in payments from such purchasers caused by financial problems encountered by them will have an immediate negative effect on our results of operations and cash flows.

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

Prospects 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.

Our industry is highly competitive, which may adversely affect the timing of actual future net cash flows from proved reserves and their present value.our performance, including our ability to participate in ready to drill prospects in our core areas.

We operate in a highly competitive environment. In addition to capital, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor nor does it necessarily reflect discount factors used in the marketplace to assess asset valuesprinciple resources necessary for the purchaseexploration and saleproduction of oil and natural gas.gas are:

We must compete for such resources with both major oil and natural gas companies and independent operators. Virtually all of these competitors have financial and other resources substantially greater than ours. Such capital, materials and resources may not be available when needed. If we are unable to access capital, material and resources when needed, we risk suffering numerous consequences, including:

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

One of our growth strategies is to pursue selective acquisitions of undeveloped acreage potentially containing oil and natural gas reserves. If we choose to pursue an acquisition, we will perform a review of the target properties; however, these reviews are inherently incomplete as they are based on the quality, availability and interpretation of the reviewed data, 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 each 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, financial condition, results of operations and cash flows could be adversely affected as claims are settled and cleanup costs related to these liabilities are incurred.

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

If an examination of the title history of a property that we purchased reveals an oil and natural gas lease has been purchased in error from a 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.

Prior to the drilling of an oil and natural gas well, however, it is the normal practice in the oil and natural gas industry the operator of the well 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, we will suffer a financial loss which could adversely affect our financial condition, results of operations and cash flows.

Our producing properties and operations are located in a limited number of geographic areas, which exposes us to various risks, including the DJ Basin region, making us vulnerable to risks associated with operating in one major geographic area.  risk of damage or business interruptions from natural disasters or weather events.

All of our estimated proved reserves at December 31, 2014, and2016, all of our 20142016 and 20132015 sales were generated in the Delaware Basin in Winkler and Loving Counties, West Texas and Lea County, New Mexico and the DJ Basin in southeastern Wyoming, northeastern Colorado and southwestern Nebraska.

Although the area is athese areas are well-established oilfield infrastructure, as a result,infrastructures, 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.

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

Our operational risk is concentrated due to our reliance on a small number of wells, operators and oil and gas purchasers.

We have concentrated operational risks both in terms of producing oil and gas properties, the operators we use and in the purchasers of our oil 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 will not be the operator on all of our drilling locations, and, therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated assets.

Currently, we are the operator of our Delaware assets, but do not control all our DJ Basin development. As we carry out our exploration and development programs, we may enter into arrangements with respect to existing or future drilling locations that result in a greater proportion of locations 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:

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.

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

The marketability of our production depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems, rail service, and processing facilities in addition to competing oil and gas production available to 3rd partythird-party purchasers. We deliver crude oil and natural gas produced from these areas through trucking, gathering systems and pipelines, some of which we do not own. The lack of availability of capacity on third-party systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Although we have some contractual control over the transportation of our production through firm transportation arrangements, third-party systems and facilities may be temporarily unavailable due to market conditions or mechanical reliability or other reasons, including adverse weather conditions or work-loads. Activist or other efforts may delay or halt the construction of additional pipelines or facilities. Third-party systems and facilities may not be available to us in the future at a price that is acceptable to us. Any significant change in market factors or other conditions affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities, could delay production, thereby harming our business and, in turn, our results of operations, cash flows, and financial condition.

Our ability to produce crude oil and natural gas economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling and completion operations. Drilling and completion activities require the use of water. For example, the hydraulic fracturing process requires the use and disposal of significant quantities of water. In certain areas, there may be insufficient local aquifer capacity to provide a source of water for drilling activities. Water must be obtained from other sources and transported to the drilling site. Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, could adversely impact our operations in certain areas.

Our success is influenced by oil, natural gas, and NGL prices in the specific areas where we operate, and these prices may be lower than prices at major markets.

Regional natural gas, condensate, oil and NGLs 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.

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

Producing oil and gas reservoirs generally are characterized by declining production rates and depletion that vary depending upon reservoir characteristics subsurface and surface pressures and other factors. Thus, our future oil and 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. The results of our planned exploratory and development drilling 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.Unconventional

Unconventional operations involve utilizing drilling and completion techniques as developed by ourselvesus and our service providers. Risks that we face while drilling include, but are not limited to, not reaching the desired objective due to drilling problems, not landing our wellbore in the desired drilling zone or specific target, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the wellbore and being able to run tools and other equipment consistently through the horizontal wellbore. Risks that we face while completing our wells include, but are not limited to, mechanical integrity, being able to hydraulic fracture stimulate the planned number of stages, being able to run tools the entire length of the wellbore during completion operations, proper design and engineering vs.versus reservoir parameters, and successfully 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 Niobrara and/or Codell 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, the success of these 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. 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 unavailability or high cost of drilling rigs, equipment supplies or personnel could adversely affect our ability to execute our exploration and development plans.

The oil and gas industry is cyclical and, from time to time, there are shortages of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs of and demand for rigs, equipment and supplies may increase substantially and their availability may be limited. In addition, the demand for, and wage rates of, qualified personnel, including drilling rig crews, may rise as the number of rigs in service increases. 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.

Covenants in our Credit Agreement impose significant restrictions and requirements on us.  Our Credit Agreement contains a number of covenants imposing significant restrictions on us, including the maximum monthly payment requirement, restrictions on our repurchase of, and payment of dividends on, our capital stock and limitations on our ability to incur additional indebtedness, make investments, engage in transactions with affiliates, sell assets and create liens on our assets. These restrictions may affect our ability to operate our business, to take advantage of potential business opportunities as they arise and, in turn, may materially andTerrorist attacks aimed at energy operations could adversely affect our business, financial conditions and results of operations.business.

WeThe continued threat of terrorism and the impact of military and other government action have led and may lead to further increased volatility in prices for oil and natural gas and could affect these commodity markets or the financial markets used by us. In addition, the U.S. government has issued warnings that energy assets may be requireda future target of terrorist organizations. These developments have subjected oil and natural gas operations to pay liquidated damages toincreased risks. Any future terrorist attack on our facilities, customer facilities, the infrastructure depended upon for transportation of products, and, in some cases, those of other energy companies, could have a material adverse effect on our investors due to our failure to maintain the effectiveness of a prior registration statement.  We could accrue liquidated damages under registration rights agreements covering a significant amount of shares of Common Stock if our investors declare a default, due to our failure to maintain the effectiveness of a prior registration statement as required in the agreements.  In such case, we would be required to pay monthly liquidated damages. If we do not make a monthly payment within seven days after the date payable, we are required to pay interest at an annual rate of 18% on the unpaid amount. If our investors declare a default under the registration rights agreement and accrue liquidated damages, we could be required to either raise additional outside funds through financing or curtail operations.business.

We are exposed to operating hazards and uninsured risks.

Our operations are subject to the risks inherent in the oil and natural gas industry, including the risks of:

These events may result in substantial losses to usour company from:

We maintain insurance against some, but not all, of these risks. We cannot assure you that ourOur insurance willmay not be adequate to cover these losses or liabilities. We do not carry business interruption insurance. Losses and liabilities arising from uninsured or underinsured events may have a material adverse effect on our financial condition 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, etc. and weather conditions. These curtailments can last from a few days to many months.months, any of which could have an adverse effect on our results of operations.

FailureWe 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. We may elect not to carry insurance if 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 and natural gas operations are subject to particular hazards incident to the drilling and production of oil and natural gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, natural gas or well fluids, fires and pollution and other environmental risks. These hazards can 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 in the loss of our total investment in a particular prospect which could have a material adverse effect on financial condition and results of operations.

Failure to adequately protect critical data and technology systems could materially affect our operations..

Information technology solution failures, network disruptions and breaches of data security could disrupt our operations by causing delays 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. There can be no assurance that aA system failure or data security breach will notcould have a material adverse effect on our financial condition, results of operations or cash flows.

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

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

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

As of December 31, 2016, we had nineteen full-time employees and two part-time employees. We leverage the services of independent consultants and contractors to perform various professional services, including engineering, oil and gas well planning and supervision, and land, legal, environmental and tax services. We also pursue alliances with partners in the areas of geological and geophysical services and prospect generation, evaluation and prospect leasing. Our dependence on third-party consultants and service providers creates a number of risks, including but not limited to:

If we experience significant delays in obtaining the services of such third parties or poor performance by such parties, our results of operations and stock price could be materially adversely affected.

Our business may suffer with the loss of key personnel.

We depend to a large extent on the services of certain key management personnel, including 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.

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

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

Our business strategy is based on our ability to acquire additional reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy.leaseholds.  The successful acquisition of producing properties requires an assessment of several factors, including:

The 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"“as is” basis.

Significant acquisitions and other strategic transactions may involve other risks, including:

The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business.  Members of our senior management and other staff may be required to devote considerable amounts of time to this 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.

Prospects in which we decide to participateWe 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.  We cannot assure you that the analysis we perform using data from other wells, more fully explored prospects or producing fields will be useful in predicting the characteristics and potential reserves associated with our drilling prospects.

Our reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracieshave difficulty managing growth in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.The process of estimating oil and natural gas reserves is complex.  It requires interpretations of available technical data and many assumptions, including assumptions ranging from subsurface parameters to economic/market factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and the calculation of the present value of reserves shown in these reports.

In order to prepare reserve estimates in its reports, our independent petroleum consultant projected production rates and timing of development expenditures.  Our independent petroleum consultant also analyzed available geological, geophysical, production and engineering data.  The extent, quality and reliability of this data can vary and may not be in our control.  The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, infrastructure, taxes and availability of funds.  Therefore, estimates of oil and natural gas reserves are inherently imprecise.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from our estimates.  Any significant variance could materially affect the estimated quantities and present value of our reserves.  In addition, our independent petroleum consultant may adjust estimates of proved reserves to reflect production history, drilling results, prevailing oil and natural gas prices and other factors, many ofbusiness, which are beyond our control due in-part to SEC guidelines. 

Risks Relating to the Oil and Gas Industry

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, as well as the carrying value of our properties, are substantially dependent on prevailing prices of oil and natural gas.  Historically, the markets for oil and natural gas have been volatile.  These markets will likely continue to be volatile in the future.  The prices we receive for our production and the levels of our production depend on numerous factors beyond our control. These factors include the following: 

Volatile oil and natural gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market 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, financialcondition and results cash flows, access to capital and ability to grow.of operations.

OurSignificant 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 is highly competitive, which may adversely affectcould have a material adverse effect on our performance, includingbusiness, financial condition and results of operations and our ability to participate in ready to drill prospects intimely execute our core areas.  We operate in a highly competitive environment. In addition to capital, the principle resources necessary for the exploration and production of oil and natural gas are: business plan.

We must compete for such resources with both major oil and natural gas companies and independent operators. Virtually all of these competitors have financial and other resources substantially greater than ours.  We cannot assure you that such capital, materials and resources will be available when needed.  If we are unable to access capital, material and resources when needed, we risk suffering a number of adverse consequences, including:

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

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

Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with operating in one 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.

We operate in areas of high industry activity, which may affect our ability to hire, train or retain qualified personnel needed to manage and operate 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.

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

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

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.

In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to 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 adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions ofgases. Relatively recently, the CAA.  The EPA recently adopted two sets of rules regulating greenhouse gas emissions under the CAA,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 is also considering direct regulation of methane emissions from oil and gas facilities. On January 14, 2015,issued regulations (effective August 2, 2016) that build on the White House and EPA indicated that they plan to amend 40 C.F.RC.F.R. Part 60, Subpart OOOO (Subpart(NSPS OOOO) standards to achieve additionalby directly regulating methane and volatile organic compound reductionsVOC emissions from thevarious types of new and modified oil and natural gas industry. These potential amendments to Subpartsources. Some of those sources are already regulated under NSPS OOOO, could result in additional regulatory requirements and standards for completions ofwhile others, like hydraulically fractured oil wells, pneumatic pumps, and leakscertain 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 new and modifiedexisting oil and gas exploration, production, and gathering facilities. A proposed rule is expected in 2015,sources. The agency said that it will “begin with a final rule expectedformal process (i.e., an Information Collection Request) to require companies operating existing oil and gas sources to provide information to assist in 2016.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 GHGgreenhouse 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 (“BACT”) 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. Upon remand,As a result, on August 12, 2015, the EPA is considering howeliminated from its PSD and Title V regulations the provisions that subjected sources to implement the Court’s decision.PSD or Title V programs based solely on GHG emission levels. The Court’s holdingEPA 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.

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

The adoption of legislation or regulatory programs to reduce GHG emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil, NGLs, and natural gas we produce. Consequently, legislation and regulatory programs to reduce GHG emissions of greenhouse gases 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 greenhouse gasesGHG 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 legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The process involves the injection of water, sand 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. We routinely use 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, has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel under the federal Safe Drinking Water Act.  In addition, legislation has been introduced before Congress to provide for federal regulationfuel.

The Bureau of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process.  Under the proposed legislation, this information would be available to the public via the internet, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater.   As discussed above, the BLM,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 new regulations become effectiveappeal is pending.

In addition, on June 24, 2015. In addition, EPA intends to propose regulations in 201513, 2016, under the federal Clean Water Act, the EPA finalized a rule (effective August 29, 2016) that prohibits the discharge of oil and gas wastewaters to develop standards for wastewater discharges from hydraulic fracturing and other natural gas production activities. publicly-owned treatment works.

At the state level, someseveral states have adopted and other statesor are considering adopting legal requirements that could impose more stringent permitting, public disclosure orand well construction requirements on hydraulic fracturing activities. Some countiesFor example in Colorado,May 2013, the RRC adopted new rules governing well casing, cementing and other standards for instance, have amendedensuring that hydraulic fracturing operations do not contaminate nearby water resources. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. 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 regulations to impose new requirements on oil and gas development, while other local governments have entered memoranda of agreement with oil and gas producers to accomplish the same objective. Beyond that, in 2012, Longmont, Colorado prohibited the use of hydraulic fracturing. The oil and gas industry filed a lawsuit challenging that ban in court. The industry prevailed on summary judgment against Longmont and the environmental intervenors. That decision is currently on appeal. In November 2013, four other Colorado cities and counties passed voter initiatives either placing a moratorium on hydraulic fracturing or banning new oil and gas development. These initiatives too are the subject of pending legal challenge or appeal. While these initiativesrestrictions generally cover areas with little recent or ongoing oil and gas development, they could lead opponents of hydraulic fracturing to push for similar statewide referendums, especially in Colorado.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 of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices and a committee of the U.S. House of Representatives has conducted an investigation of hydraulic fracturing practices. Furthermore, a

A number of federal agencies are analyzing, or have been requested to review, environmental issues associated with hydraulic fracturing. The EPA, has commencedfor 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 draft results expected by 2015..inadequate mechanical integrity, allowing gases or liquids to move to groundwater resources.” These ongoingtypes of studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water ActSDWA or other regulatory mechanisms.

The EPA has also issued an advance notice of proposed rulemaking and initiatedundertook a public participation process under the Toxic Substances Control Act (“TSCA”) 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 (“EPCRA”) Toxics Release Inventory, (“TRI”)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.

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

Hydraulic fracturing 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. In order to source water from the local water supply for hydraulic fracturing we may need to pay premium rates and be subject to a lower priority if the local area becomes subject to water restrictions. We may also seek water from alternative providers supporting the hydraulic fracturing industry. If we have an insufficient water supply, we will be unable to engage in hydraulic fracturing until such supply is located.

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

Moreover, as part of the Budget of the United States Government for Fiscal Year 2017, there was a proposal to impose an “oil fee” of $10.25 on a 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.

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

. 

Our operations are subject to extensive federal, state and local laws and regulations relating to the exploration, production and sale of oil and natural gas, and operating safety. 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, results of operations and financial condition. We may be required to make large and unanticipated capital expenditures to comply with governmental regulations, such as:

Under these laws and regulations, we could be liable for:

Our operations could be significantly delayed or curtailed and our cost of operations could significantly increase as a result of regulatory requirements or restrictions. We are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations.  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“Business—Regulation of the Oil and Properties—Government Regulations”Natural Gas Industry” for a more detailed description of regulatory laws covering our regulatory risks.business.

Our operations may incur substantial expenses and resulting liabilities from compliance with environmental laws and regulations..  

Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations:

Failure to comply with these laws and regulations may result in:

Changes in environmental laws and regulations occur frequently and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to reach and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination or if our operations met previous standards in the industry at the time they were performed. Our permits require that we report any incidents that cause or could cause environmental damages. See “Business“Business— Regulation of the Oil and Properties—Government Regulations”Natural Gas Industry” for a more detailed description of the environmental laws covering our environmental risks.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.”

Risks Relating to Our Common StockSecurities

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 sharescommon stock and we cannot assure you that an active trading market or a specific share price willmay not be established or maintained.Our Common Stock

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 Nasdaq Global Market,OTCQB, trading activity in our common stock generally occurs in small volumes each day.  The value of our Common Stockcommon stock could be affected by:

In a volatile market, you may experience wide fluctuations in the market price of our Common Stock.common stock.  These fluctuations may have an extremely negative effect on the market price of our Common Stockcommon stock and may prevent you from obtaining a market price equal to your purchase price when you attempt to sell our Common Stockcommon 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 Stockcommon 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 Common Stockour common stock as consideration.

We may

If an orderly and active trading market for our securities does not satisfydevelop or is not sustained, the NASDAQ Capital Market’s requirementsvalue 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 continued listing. If we cannot satisfy these requirements, NASDAQ could delist our Common Stock. Our Common Stock is listedcommon 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 NASDAQ Capital Market, underOTCQB 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 symbol LLEX. To continuecurrent 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 NASDAQ,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 requiredunable to satisfysell their securities at or above their purchase price.

If an active public market for our common stock develops, we expect the market price of our securities to fluctuate substantially for the foreseeable future, primarily due to a number of conditions. factors, including:

In past years,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 future, some of 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 volume and by wide fluctuations in trading prices due to many factors that may have little to do with our operations or business prospects. The availability of buyers and sellers represented by this volatility could lead to a market price for our common stock that is unrelated to operating performance. Moreover, the OTCQB is not a stock exchange, and trading of securities quoted on the OTCQB is often more sporadic than the trading of securities listed on a national securities exchange like The NASDAQ Stock Market or the New York Stock Exchange. While we defaultedare currently seeking to list our securities on several of these requirements and regained compliance only after we carried out capital-raising and other transactions. We cannot assure you thata national securities exchange, there is no assurance we will be able to satisfy the NASDAQ listing requirementsdo so, and if we do so, many of these same forces and limitations may still impact our trading volumes and market price in the future. If we are delisted from NASDAQ, trading in our Common Stocknear term. Additionally, the sale or attempted sale of a large amount of common stock into the market may be conducted, if available,also have a significant impact on the “OTC Bulletin Board Service” or, if available, via another market.trading price of our common stock.

Many of these factors are beyond our control and may decrease the market price of our common stock, regardless of our operating performance. In the eventpast, securities class action litigation has often been brought against companies that experience high volatility in the market price of such delisting, an investor would likely find it significantly more difficult to dispose of,their securities. Whether or to obtain accurate quotations as to the value of our Common Stock, and our ability to raise future capital through the sale of our Common Stock or other securities convertible into our Common Stock could be severely limited. In addition, if our Common Stock were delisted from NASDAQ, our Common Stock could be considered a “penny stock” under the U.S. federal securities laws. Additional regulatory requirements apply to trading by broker-dealers of penny stocks thatnot meritorious, litigation brought against us could result in the losssubstantial costs, divert management’s attention and resources and harm our financial condition and results of an effective trading market for our Common Stock.operations. 

Our Common Stock may be subject to penny stock rules which limit the market for our Common Stock.  The SEC has adopted Rule 15g-9 which establishes the definition of a “penny stock,” for the purposes relevant to us, as any equity security that has a market price of less than $5.00 per share or with an exercise price of less than $5.00 per share, subject to certain exceptions. For any transaction involving a penny stock, unless exempt, the rules require:

In order to approve a person’s account for transactions in penny stocks, the broker or dealer must:

The broker or dealer must also deliver, prior to any transaction in a penny stock, a disclosure schedule prescribed by the SEC relating to the penny stock market, which, in highlight form:

Disclosure also has to be made about the risks of investing in penny stocks in both public offerings and in secondary trading and about the commissions payable to both the broker-dealer and the registered representative, current quotations for the securities and the rights and remedies available to an investor in cases of fraud in penny stock transactions. Finally, monthly statements have to be sent disclosing recent price information for the penny stock held in the account and information on the limited market in penny stocks.

Generally, brokers 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.

Sales of a substantial number of shares of our Common Stock, or the perception that such sales might occur, could have an adverse effect on the price of our Common Stock. As of December 31, 2014, six investors each hold more than 5% beneficial ownership of our Common Stock, and together, hold beneficial ownership of approximately 75% of our Common Stock. Thus, any sales by our large investors of a substantial number of shares of our Common Stock into the public market, or the perception that such sales might occur, could have an adverse effect on the price of our Common Stock.

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

Our articles of incorporation authorize our board of directors to issue one or more series of preferred stock and set the terms of the preferred stock without seeking any further approval from our stockholders.shareholders. Any preferred stock that is issued may rank ahead of our Common Stock,common stock, in terms of dividends, liquidation rights and voting rights. We currently have two series of preferred stock issued and outstanding, both of which provide its holders with a liquidation preference and prohibit the payment of dividends on junior securities, including our Common Stock, amongst other preferences and rights.

There may be future dilution of our Common Stock.common stock. If we sell additional equity

We have a significant amount of derivative securities outstanding, which upon exercise or convertible debt securities, such salesconversion, would result in substantial dilution. For example, the conversion of the remaining Series B preferred stock in full could result in increased dilution to our existing stockholdersthe issuance of 15,454,545 shares of common stock, and cause the priceexercise of our outstanding securities to decline.warrants could result in the issuance of 15,915,511 shares of common stock. To the extent outstanding restricted stock units, warrants or options to purchase Common Stockour common stock under our employee and director stock option plans are exercised, the price vesting triggers under the performance shares granted to our executive officers are satisfied, or additional shares of restricted stock are issued to our employees, holders of our Common Stock will experience dilution. Furthermore, if we sell 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.

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

We have never paid dividends with respect to our Common Stock,common stock, and we do not expect to pay any dividends, in cash or otherwise, in the foreseeable future. We intend to retain any earnings for use in our business. In addition, the credit agreement relating to our credit facilityCredit Agreement prohibits 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 shareholders will therefore be limited to the appreciation of their stock.

Our Common Stock is an unsecured equity interest in our Company. As an equity interest, our Common Stock is not secured by any of our assets. Therefore, in the event we are liquidated, the holders of the Common Stock will receive a distribution only after all of our secured and unsecured creditors have been paid in full. There can be no assurance that we will have sufficient assets after paying our secured and unsecured creditors to make any distribution to the holders of the Common Stock.

Securities analysts may not initiate coverage of our shares or may issue negative reports, which may adversely affect the trading price of the shares.We cannot assure you that securities

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

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.

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

Though not now, in the future we may become subject to Nevada’s control share law. A corporation is subject to Nevada’s control share law if it 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 power of the corporation in the election of directors: (i) one-fifth or more but less than one-third, (ii) one-third or more but less than a majority, or (iii) a majority or more. The ability to exercise such voting 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 majority 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 the 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.

Item 1B. Unresolved Staff Comments

Not applicable.

Item 3. Legal Proceedings

The CompanyWe 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 wouldHowever, we do 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.

Parker v. Tracinda Corporation, Denver District Court, Case No. 2011CV561.  In November 2012, the Company filed a motion to intervene in garnishment proceedings involving Roger Parker, the Company’s former Chief Executive Officer and Chairman.  The Defendant, Tracinda, served various writs of garnishment on the Company to enforce a judgment against Mr. Parker seeking, among other things, shares of unvested restricted stock.  The Company asserted rights to lawful set-offs and deductions in connection with certain tax consequences, which may be material to the Company.  The underlying judgment against Mr. Parker was appealed to the Colorado Court of Appeals and, by Order dated October 17, 2013, that Court reversed the trial court with respect to Mr. Parker’s claims of waiver, estoppel and mitigation of damages and remanded with instruction to enter judgment for Mr. Parker. The Court of Appeals also ordered the trial court to conduct further proceedings to determine the amount of damages to award Mr. Parker on his breach of contract claim. The trial court conducted a later hearing and found in its Findings of Fact, Conclusions of Law and Order dated January 9, 2015, in favor of Mr. Parker on his claim for breach of contract, awarding him $6,981,302.60. Tracinda’s Motion for Amendment of the Court’s January 9 Findings and Conclusions is pending.

In re Roger A. Parker: Tracinda Corp. v. Recovery Energy, Inc. and Roger A. Parker, United States Bankruptcy Court for the District of Colorado, Case No. 13-10897-EEB. On June 10, 2013, Tracinda Corp. (“Tracinda”) filed a complaint (Adversary No. 13-011301 EEB) against the Company and Roger Parker in connection with the personal bankruptcy proceedings of Roger Parker, alleging that the Company improperly failed to remit to Tracinda certain property in connection with a writs of garnishment issued by the Denver District Court (discussed above). The Company filed an answer to this complaint on July 10, 2013. A trial date has not been set and, by Order dated February 2, 2015, the Bankruptcy Court ordered that the Adversary Proceeding be held in abeyance pending final resolution of the state-court action (2011CV561). The Company is unable to predict the timing and outcome of this matter.

Lilis Energy, Inc. v. Great Western Operating Company LLC, Eighth Judicial District Court for Clark County, Nevada, Case No. A-15-714879-B. On March 6, 2015, the Company filed a lawsuit against the operator.  The dispute relates to the Company’s interest in certain producing wells and the well operator’s assertion that the Company’s interest was reduced and/or eliminated as a result of a default or a farm-out agreement. Underlying the dispute is the JOA which provides the parties with various rights and obligations. In its complaint, the Company seeks monetary damages and declaratory relief on claims of breach of contract, breach of the implied covenant of good faith and fair dealing, tortious breach of the implied covenant of good faith and fair dealing, unjust enrichment, conversion and declaratory judgment related to the JOA. The operator has not yet responded to the complaint.

The Company believesbelieve there is no otherany currently pending litigation pending that could have, individually or in the aggregate, a material adverse effect on itsour results of operations or financial condition.

Item 4. Mine Safety Disclosures

Not applicable.

PartPART II

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

Recent Market Prices

On November 2, 2011We began trading on the OTCQB Venture Marketplace under the symbol “LLEX” on May 27, 2016. From February 11, 2016 to May 26, 2016, our Common Stock began tradingcommon stock traded on The Nasdaq Capital Market (“Nasdaq”) under the symbol “LLEX.” Prior February 11, 2016, our common stock traded on the Nasdaq Global Market under the symbol "RECV."  Between September 25, 2009 and November 1, 2011 our stock traded on the OTC Bulletin Board under the symbol "RECV.OB." On December 1, 2013, in connection with our name changes our Common Stock began trading“LLEX.” We have applied for relisting on the Nasdaq Global Market under the symbol "LLEX." 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 Stockcommon 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.