UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

x    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the fiscal year ended December 31, 2016

 

or

 

¨    TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from __________to_________

 

Commission file number: 001-35330

 

Lilis Energy, Inc.

(Name of registrant as specified in its charter)

 

Nevada   74-3231613

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

 

300 E. Sonterra Blvd., Suite No. 1220, San Antonio, TX 78258

(Address of principal executive offices, including zip code)

 

Registrant’s telephone number including area code: (210) 999-5400

 

Securities registered under Section 12(b) of the Act:

 

None

 

 

Common Stock, $0.0001 par value

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. Yes ¨ No x

 

Indicate by check mark if the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x     No ¨

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x     No ¨

 

Indicate by check mark if disclosure of delinquent filers in response to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company (as defined in Rule 12b-2 of the Act):

 

Large accelerated filer ¨ Accelerated filer ¨
Non-accelerated filer    ¨ Smaller reporting company x

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

 

As of June 30, 2016, the aggregate market value of the voting and non-voting shares of common stock of the registrant issued and outstanding on such date, excluding shares held by affiliates of the registrant as a group was $8,249,960. This figure is based on the closing sales price of $2.00 per share of the registrant’s common stock on June 30, 2016 on the OTCQB.

 

As of March 1, 2017, 24,387,793 shares of the registrant’s Common Stock were issued and outstanding.

 

 

 

 

FORM 10-K ANNUAL REPORT

YEAR ENDED DECEMBER 31, 2016

LILIS ENERGY, INC.

 

    Page
PART I
 
Items 1 and 2. Business and Properties 6
Item 1A. Risk Factors 20
Item 1B. Unresolved Staff Comments 40
Item 3. Legal Proceedings 40
Item 4. Mine Safety Disclosures 40
     
PART II
 
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 41
Item 6. Selected Financial Data 41
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 42
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 52
Item 8. Financial Statements and Supplementary Data 53
Item 9. Changes in and disagreements with Accountants on Accounting and Financial Disclosure 53
Item 9A. Controls and Procedures 53
Item 9B. Other Information 53
     
PART III
 
Item 10. Directors, Executive Officers and Corporate Governance 54
Item 11. Executive Compensation 60
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 70
Item 13. Certain Relationships and Related Transactions, and Director Independence 75
Item 14. Principal Accounting Fees and Services 78
     
PART IV
 
Item 15. Exhibits, Financial Statement Schedules 80

 

 

 

 

FORWARD-LOOKING STATEMENTS

 

This Annual Report on Form 10-K contains “forward-looking statements”. 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 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:

 

·our estimates regarding operating results, future revenues and capital requirements;
·our ability to successfully integrate our acquisition of Brushy Resources, Inc. and realize anticipated benefits from such acquisition;
·availability of capital on an economic basis, or at all, to fund our capital or operating needs;
·our level of debt, which could adversely affect our ability to raise additional capital, limit our ability to react to economic changes and make it more difficult to meet our obligations under our debt;
·restrictions imposed on us under our credit agreement or other debt instruments that limit our discretion in operating our business;
·potential default under our material debt agreements;
·failure to meet requirements or covenants under our debt instruments, which could lead to foreclosure of significant core assets;
·failure to fund our authorization for expenditures from other operators for key projects which will reduce or eliminate our interest in the wells/asset;
·the inability of management to effectively implement our strategies and business plans;
·estimated quantities and quality of oil and natural gas reserves;
·exploration, exploitation and development results;
·fluctuations in the price of oil and natural gas, including further reductions in prices that would adversely affect our revenue, cash flow, liquidity and access to capital;
·availability of, or delays related to, drilling, completion and production, personnel, supplies (including water) and equipment;
·the timing and amount of future production of oil and natural gas;
·the timing and success of our drilling and completion activity;
·lower oil and natural gas prices negatively affecting our ability to borrow or raise capital, or enter into joint venture arrangements;
·declines in the values of our natural gas and oil properties resulting in further write-down or impairments;
·inability to hire or retain sufficient qualified operating field personnel;
·our ability to successfully identify and consummate acquisition transactions;
·our ability to successfully integrate acquired assets or dispose of non-core assets;
·the occurrence of natural disasters, unforeseen weather conditions, or other events or circumstances that could impact our operations or could impact the operations of companies or contractors we depend upon in our operations;
·inability to successfully develop our large inventory of undeveloped acreage we currently hold on a timely basis;
·constraints, interruptions or other issues affecting the Delaware Basin, including with respect to transportation, marketing, processing, curtailment of production, natural disasters, and adverse weather conditions;
·deterioration in general or regional economic conditions;
·inability to acquire or maintain mineral leases at a favorable economic value that will allow us to expand our development efforts;
·technical risks inherent in drilling in existing or emerging unconventional shale plays using horizontal drilling and complex completion techniques;
·delays, denials or other problems relating to our receipt of operational consents, approvals and permits from governmental entities and other parties;

 

 1 

 

 

·unanticipated recovery or production problems, including cratering, explosions, blow-outs, fires and uncontrollable flows of oil, natural gas or well fluids;
·loss of senior management or technical personnel;
·litigation and the outcome of other contingencies, including legal proceedings;
·adverse state or federal legislation or regulation that increases the costs of compliance, or adverse findings by a regulator with respect to existing operations, including those related to climate change and hydraulic fracturing;
·anticipated trends in our business;
·effectiveness of our disclosure controls and procedures and internal controls over financial reporting; and
·changes in generally accepted accounting principles in the United States or in the legal, regulatory and legislative environments in the markets in which we operate.

 

Many of these factors are beyond our ability to control or predict. These factors are not intended to represent a complete list of the general or 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).

 

 2 

 

 

GLOSSARY

 

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

 

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

 

Bcf. Billion cubic feet of natural gas.

 

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

 

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

 

BOE. One barrel of crude oil equivalent, determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.

 

BOE/d. Barrels of oil equivalent per day.

 

BO/d. Barrel of oil per day.

 

BTU or British Thermal Unit. The quantity of heat required to raise the temperature of one pound mass of water by 28.5 to 59.5 degrees Fahrenheit.

 

Completion. Installation of permanent equipment for production of oil or natural gas.

 

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

 

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

 

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

 

Dry well or dry hole. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

 

Exploratory well. A well drilled to find a new field or to find a new reservoir. Generally an exploratory well in any well that is not a development well, an extension well, a service well or a stratigraphic well.

 

FERC. The Federal Energy Regulatory Commission.

 

Field. An area consisting of either a single reservoir or multiple reservoirs all grouped on or related to the same geological structural feature and/or stratigraphic condition.

 

Formation. An identifiable layer of subsurface rocks named after its geographical location and dominant rock type.

 

Gross acres, gross wells, or gross reserves. A well, acre or reserve in which we own a working interest, reported at the 100% or 8/8ths level. For example, the number of gross wells is the total number of wells in which we own a working interest.

 

Lease. A legal contract that specifies the terms of the business relationship between an energy company and a landowner or mineral rights holder on a particular tract of land.

 

Leasehold. Mineral rights leased in a certain area to form a project area.

 

Mbbls. One thousand barrels of crude oil or other liquid hydrocarbons.

 

Mboe. One thousand barrels of crude oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

 

 3 

 

 

Mcf. One thousand cubic feet of natural gas.

 

Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

 

MMbtu. One million British Thermal Units.

 

MMcf. One million cubic feet of natural gas.

 

Net acres or net wells. The sum of fractional ownership working interests in gross acres or gross wells. The number of net acres or wells is the sum of the fractional working interests owned in gross acres or wells expressed as whole numbers and fractions of whole numbers.

 

NGL. Natural gas liquids, or liquid hydrocarbons found as a by-product of natural gas.

 

Overriding royalty interest. Is similar to a basic royalty interest except that it is created out of the working interest. For example, an operator possesses a standard lease providing for a basic royalty to the lessor or mineral rights owner of 1/8 of 8/8. This then entitles the operator to retain 7/8 of the total oil and natural gas produced. The 7/8 in this case is the 100% working interest the operator owns. This operator may assign his working interest to another operator subject to a retained 1/8 overriding royalty. This would then result in a basic royalty of 1/8, an overriding royalty of 1/8 and a working interest of 3/4. Overriding royalty interest owners have no financial or other obligation or responsibility for developing and operating the property. The only expenses borne by the overriding royalty owner are a share of the production or severance taxes and sometimes costs incurred to make the oil or gas salable.

 

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

 

Production. Natural resources, such as oil or gas, flowed or pumped out of the ground.

 

Productive well. A producing well or a well that is mechanically capable of production.

 

Proved developed oil and gas reserves. Proved developed oil and gas reserves are proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

 

Proved reserves. Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

 

Proved undeveloped reserves. Proved undeveloped oil and gas reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

 

Project. A targeted development area where it is probable that commercial oil and/or gas can be produced from new wells.

 

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

 

PV-10 (Present value of future net cash flow). The present value of estimated future revenues to be generated from the production of estimated proved reserves, net of capital expenditures and operating expenses, using the simple 12 month arithmetic average of first of the month prices and current costs (unless such prices or costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expenses, depreciation, depletion and amortization or impairment, discounted using an annual discount rate of 10%. While this non-GAAP measure does not include the effect of income taxes as would the use of the standardized measure calculation, we believe it provides an indicative representation of the relative value of our company on a comparative basis to other companies and from period to period.

 

 4 

 

 

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.

 

 5 

 

 

PART I

 

Items 1 and 2. Business and Properties

 

Lilis Energy, Inc. and its consolidated subsidiaries (collectively, “we,” “us,” “our,” “Lilis Energy,” “Lilis,” or the “Company”) is an 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 2007 in the State of Nevada as Universal Holdings, Inc. In October 2009, we changed our name to Recovery Energy, Inc. and in December 2013, we changed our name to Lilis Energy, Inc.

 

On June 23, 2016, we completed the merger transaction contemplated by the Agreement and Plan of Merger dated as of December 29, 2015, 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 activity.

 

Additionally, in connection with the Merger on June 23, 2016, we effected a 1-for-10 reverse stock split (the “Reverse Split”). As a result of 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.

 

 6 

 

 

Our Denver-Julesburg Basin Properties

 

In addition to our core Delaware Basin focus area, we have approximately 14,254 net acres in the Denver-Julesburg Basin (“DJ Basin”) comprised of 280 net acres in the core of the Wattenberg field in Weld County, Colorado and 13,974 net acres in Laramie County, Wyoming, Nebraska and other parts 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 DJ Basin project area, and we are currently reviewing strategic alternatives with respect to these properties.

 

Business Strengths and Strategies

 

Our primary business objective is to increase our Delaware Basin leasehold position, reserves, production and cash flows at attractive rates of return on invested capital in order to enhance shareholder value. To achieve this objective, key elements of our strategy include:

 

·Geographic focus in one of North America’s leading unconventional oil plays. We have accumulated a leasehold position of approximately 6,924 net acres in the Delaware Basin as of March 1, 2017. We believe the Delaware Basin has one of the highest rates of return among such formations in North America based on results of offset operators. In addition to leveraging our technical expertise in this core area, our geographically-concentrated acreage position allows us to capitalize on economies of scale with respect to drilling and production costs. Based on our drilling and production results to date and well-established offset operator activity in and around our project areas, we believe there are relatively low geologic risks and ample repeatable drilling opportunities across our core Delaware Basin operating area. We plan on allocating all of our 2017 capital budget to our Delaware Basin activities.

 

·Develop our Delaware Basin leasehold position. We intend to focus on developing our acreage position in the Delaware Basin in order to maximize the value of our resource potential through utilizing the best-in-class drilling and completion techniques at the lowest possible costs. Through the development of our properties, we will seek to derisk our acreage position and drilling program and substantially increase our production and cash flow, thereby increasing the value of our properties. Our current leasehold position in the Delaware Basin has significant stacked-pay potential. We currently estimate our properties include at least seven productive zones and hold approximately 500 future drilling locations across all of the productive zones within this position. Initially, we intend to focus our horizontal development on the Wolfcamp formation, followed by the Bone Spring and Avalon formations through a combination of re-entering existing vertical wellbores and new drilling locations.

 

·Pursue strategic acquisitions, organic leasing, and other creative structures to continue to develop and grow our production and leasehold position. We continue to identify and seek to acquire additional acreage and producing assets in the Delaware Basin. We believe that we can continue our successful track record of growing our acreage position in and around our core area at attractive costs. Since entering the Delaware Basin in June 2016, we have grown our acreage position 98% from 3,500 net acres to 6,924. We have accomplished this through buying smaller packages that are complementary to our core position and also by acquiring smaller, fragmented working interest positions on existing leaseholds.

 

·Leverage our extensive operational expertise to reduce costs and enhance returns. We are focused on continuously improving our operating costs and metrics. We evaluate our operating metrics against those of other operators in our area in order to measure our performance and optimize our drilling and completion techniques. We utilize this process to make informed decisions about our capital expenditure program and drilling and completion activity. We intend to leverage our contiguous acreage position and our knowledge of the Delaware Basin to capture operational and economic efficiencies.

 

·Employ leading drilling and completion techniques. We intend to employ industry best practices well design drilling and completion techniques by replicating leading Delaware Basin operators. Our contiguous acreage position is offset by RSP Permian, Matador, Devon, Shell, Anadarko, and XTO, among other operators, and we will continue to observe and monitor their drilling activity and well results in the area as we execute on our development plan.

 

·Maintain financial liquidity and flexibility. We intend to utilize cash flow from operations, available working capital, borrowings under our multiple-draw term loan and access the capital markets in order to fund and execute our capital expenditure and development program. We believe this financial liquidity and flexibility will result in steady growth in leasehold, production, cash flow and proved reserves.

 

·Hedging. We intend to opportunistically use commodity price hedging instruments to reduce our exposure to oil and natural gas price fluctuations and to help ensure that we have adequate cash flow to fund our debt service costs and capital programs. We intend to use hedging primarily to manage price risks and returns on certain acquisitions and drilling programs. Our policy is to consider hedging an appropriate portion of our production at commodity prices we deem attractive.

 

 7 

 

 

Principal Oil and Gas Interests

 

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

 

As of December 31, 2016, we owned interests in approximately 19,968 net acres, of which 14,994 net acres are classified as undeveloped 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 Delaware Basin are the Wolfcamp formation as well as the Bone Springs and Avalon Formations.

 

As of December 31, 2016 and March 1, 2017, we had 2 gross (1.2 net) and 1 gross (0.6 net) wells in the process of being drilled, respectively, all in the Delaware Basin.

 

Reserves

 

The table below presents summary information with respect to the estimates of our proved oil and gas reserves for the years ended December 31, 2016 and 2015. We engaged Cawley, Gillespie & Associates, Inc. (“CG&A”) and Forrest A. Garb & Associates to audit internally prepared engineering estimates for all of our proved reserves at year-end 2016 and 2015, respectively. Of these reserves, approximately 50% were classified as Proved Developed Producing (“PDP”). Proved Undeveloped (“PUD”) and Proved Non-Producing (“PNP”) included in this estimate are from 0 vertical well locations and 2 horizontal well locations. As of December 31, 2016, total proved reserves were approximately 46% oil and NGLs and 54% natural gas. As of December 31, 2015, total proved reserves were approximately 59% oil and NGLs and 41% natural gas.

 

The following table provides summary information regarding our proved reserves as of December 31, 2016 and 2015, and production for the years ended December 31, 2016 and 2015. 

 

Estimated Total Proved Reserves

 

   December 31, 
   2016   2015 
   Delaware
Basin
  

DJ

Basin

   Total   Delaware
Basin
  

DJ

Basin

   Total 
Oil (MMBBL)   0.455    0.096    0.551    -    0.033    0.033 
Natural Gas (BCF)   3.507    0.365    3.872    -    0.141    0.141 
Total (MMBOE)   1.04    0.156    1.196    -    0.057    0.057 
% Oil   44%   61%        -    59%     
% Developed   100%   100%        -    100%     
Avg. Net Production (BOE/D)   317    87    404    -    215    215 

 

During the years ended December 31, 2016 and 2015, we recognized an impairment expense of approximately $4.7 million and $24.5 million, respectively. The $4.7 million impairment charge during the year ended December 31, 2016 was primarily due to the lower commodity prices sustained for the majority of 2016 in the DJ Basin and the $24.5 million impairment charge for the year ended December 31, 2015 was attributable to the lack of capital to develop our undeveloped oil and gas properties and lower commodity prices.

 

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 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 and a senior reserve engineering consultant. In 2016, we established a Reserves Committee to provide additional oversight of 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.

 

 8 

 

 

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 2016 reserve process was overseen by Chris Cantrell, our senior reserve engineering consultant. Mr. Cantrell holds a Bachelor of Science degree in Petroleum Engineering conferred by Texas A&M University in 1995. He is a registered professional engineer licensed in the State of Texas, license number 90521. He has been continuously involved in evaluating oil and gas properties since 1997, and is a member of the Society of Petroleum Engineers and the American Petroleum Institute.

 

Third-party Reserves Study

 

An independent third-party reserve study as of December 31, 2016, was performed by CG&A using its own engineering assumptions and other economic data provided by us. All of our total calculated proved reserve PV-10 value was audited by CG&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 CG&A primarily responsible for overseeing our reserve audit is Todd Brooker, Senior Vice President of CG&A, who received a Bachelor of Science degree in Petroleum Engineering from the University of Texas and is a registered Professional Engineer in the States of Texas. He is also a member of the Society of Petroleum Engineers.

 

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

 

Oil and gas reserves and the estimates of the present value of future net cash flows therefrom were determined based on prices and costs as 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 years ended December 31, 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-party reserve study, our reserves and the corresponding report are reviewed by our Chief Financial Officer, geologist 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 CG&A’s audit letter.

 

Production

 

The following table summarizes the average volumes and realized prices of oil and gas produced from properties in which we held an interest during the periods indicated, and production cost per BOE:

 

   For the Year Ended
December 31,
 
   2016   2015 
Product          
Oil (Bbl.)   61,088    7,067 
Oil (Bbls)-average price  $39.59   $41.36 
           
Natural Gas (MCFE)-volume   400,775    32,291 
Natural Gas  (MCFE)-average price  $2.54   $2.39 
           
Barrels of oil equivalent (BOE)   127,863    12,449 
Average daily net production (BOE)   350    34 
Average Price per BOE  $26.87   $29.67 

 

(1)Includes proceeds from the sale of natural gas liquids (“NGL’s”)

 

 9 

 

 

   For the Year Ended
December 31,
 
   2016   2015 
Production costs per BOE  $9.75   $15.70 
Production taxes per BOE   (1.30)   2.24 
Depreciation, depletion, and amortization per BOE   12.25    46.93 
Total operating costs per BOE  $20.70   $64.87 
Gross margin per BOE  $6.17   $(35.20)
Gross margin percentage   23%   (119)%

 

Oil and gas production costs, production taxes, depreciation, depletion, and amortization

 

Drilling Activity

 

As of December 31, 2016, we have drilled 1.2 net productive wells.

 

As of December 31, 2016 and 2015, we had working interests in 35 gross (21 net) wells and 6 gross (1.27 net) wells, respectively. Productive wells are either wells producing in commercial quantities or wells capable of commercial production, but 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, 2015, we owned 8 producing wells in Wyoming, Nebraska and Colorado within the DJ Basin, as well as approximately 18,000 gross (16,000 net) acres, of which 10,000 gross (8,000 net) acres were classified as undeveloped acreage. Our primary assets included acreage located in Laramie and Goshen Counties in Wyoming; Banner, Kimball, and Scotts Bluff Counties in Nebraska; and Weld, Arapahoe and Elbert Counties in Colorado.

The following table sets forth our gross and net developed and undeveloped acreage as of December 31, 2016 and 2015:

 

   Undeveloped   Developed 
   Gross   Net   Gross   Net 
DJ Basin   16,678    13,576    1,923    678 
Delaware Basin   9,074    1,418    7,183    4,295 
Total acreage as of December 31, 2016   25,752    14,994    9,106    4,973 
                     
DJ Basin   10,000    8,000    8,000    8,000 
Total acreage as of December 31, 2015   10,000    8,000    8,000    8,000 

 

As of March 1, 2017, our inventory of developed and undeveloped acreage includes approximately 40,618 gross (21,178 net) acres, of which 9,106 gross (5,248 net) acres that are held by production. We will continue to pursue additional 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 if financing is available to us and the properties are economic.

 

 10 

 

 

Title to Properties

 

Approximately 66% of our leasehold interests are held by production, with the majority of our Delaware Basin leasehold position subject to mortgages securing indebtedness under our credit and guarantee agreement. The credit agreement was entered into on September 29, 2016 (the “Credit Agreement”) by and among our wholly-owned subsidiaries, Brushy, ImPetro Operating, LLC, a Delaware limited liability company (“Operating”) and ImPetro Resources, LLC, a Delaware limited liability company (“Resources”, and together with Brushy and Operating, the “Borrowers”), and the lenders party thereto (each a “Lender” and together, the “Lenders”) and T.R. Winston & Company, LLC acting as collateral agent. We believe the security interests granted in our properties do not materially interfere with the use of, or affect the value of, such properties.

 

Marketing and Pricing

 

We derive revenue and cash flow principally from the sale of oil and natural gas. As a result, our revenues are determined, to a large degree, 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:

 

·changes in global supply and demand for oil and natural gas;
·the actions of the Organization of Petroleum Exporting Countries;
·the price and quantity of imports of foreign oil and natural gas;
·acts of war or terrorism;
·political conditions and events, including embargoes, affecting oil-producing activity;
·the level of global oil and natural gas exploration and production activity;
·the level of global oil and natural gas inventories;
·weather conditions;
·technological advances affecting energy consumption;
·transportation options from trucking, rail, and pipeline; and
·the price and availability of alternative fuels.

 

Furthermore, regional natural gas, condensate, oil and NGL prices may move independently of broad industry price trends. Because some of our operations are located outside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTI or other major market pricing.

 

From time to time, we may enter into derivative contracts. These contracts economically hedge our exposure to decreases in the prices of oil and natural gas. Hedging arrangements may expose us to risk of significant financial loss in some circumstances, including instances in which:

 

·there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received;
·our production and/or sales of oil or natural gas are less than expected;
·payments owed under derivative hedging contracts come due prior to receipt of the hedged month’s production revenue; or
·the other party to the hedging contract defaults on its contract obligations.

 

In addition, hedging arrangements may limit the benefit we would receive from increases in the prices for oil and natural gas. As of December 31, 2016, we had no hedging agreements in place.

 

 11 

 

 

Major Customers

 

Our major customers for the year ended December 31, 2016 include Noble Energy, Inc., Texican Natural Gas Company, and Energy Transfer Partners, L.P., who accounted for approximately 41%, 38%, and 16% of our revenue for the year ended December 31, 2016, respectively. Our major customers for the year ended December 31, 2015 include, Shell Trading (US) Company, PDC Energy, Inc., and Noble Energy, Inc., who accounted for approximately 43%, 26%, and 21% of our revenue for the year ended December 31, 2015, respectively. We do not believe that the loss of any single customer would materially affect our business because there are numerous other potential purchasers of our production.

 

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.

 

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.

 

Regulation of the Oil and Natural Gas Industry

 

General. Our operations covering the exploration, production and sale of oil and natural gas are subject to various types of federal, state and 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. At various times, regulatory agencies have imposed price controls and limitations on production. In order to conserve supplies of oil and natural gas, these agencies have restricted the rates of flow of oil and natural gas wells below actual production capacity, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding production. Federal, state and local laws regulate production, handling, storage, transportation and disposal of oil and natural gas, by-products from oil and natural gas and other substances and materials produced or used in connection with oil and natural gas operations. While we believe that we will be able to substantially comply with all applicable laws and regulations through our strict attention to regulatory compliance, the requirements of such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the FERC and the courts. We cannot predict when or whether any such proposals may become effective. We do not believe that we would be affected by any such action materially differently than similarly situated competitors.

 

 12 

 

 

Regulation of Production of Oil and Natural Gas. The production of oil and natural gas is subject to regulation under a wide range of local, state and federal 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 operating activities by requiring, among other things, permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The laws of Texas also govern a number of conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing or density, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing or density. Moreover, Texas imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural 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 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.” 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.

 

 13 

 

 

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.” 

 

 14 

 

 

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

 

 15 

 

 

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-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.

 

 16 

 

 

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 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-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.

 

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, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. In addition, we currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration, production and processing for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state and local laws. Under such laws, we could be required to undertake investigatory, response, or corrective measures, which could include soil and groundwater sampling, the removal of previously disposed substances and wastes, the cleanup of contaminated property, or performance of remedial plugging or pit closure operations to prevent future contamination, the costs of which could be substantial.

 

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.

 

 17 

 

 

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.

 

OSHA

 

We are subject to the requirements of the OSHA and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

 

State Laws

 

There are numerous state laws and regulations in the states where we operate that relate to the environmental aspects of our business. Some of those laws and regulations are 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 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, environmental laws may result in a curtailment of production or material increase in the cost of production, development or exploration and may otherwise adversely affect our financial condition and results of operations. Although we maintain liability insurance coverage for liabilities from pollution, environmental risks, generally are not fully insurable.

 

In addition, because we have acquired and may acquire interests in properties that have been operated in the past by others, we may be liable for environmental damage, including historical contamination, caused by such former operators. Additional liabilities could also arise from continuing violations or contamination not discovered during our assessment of the acquired properties.

 

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.

 

 18 

 

 

Federal Income Tax. Federal income tax laws significantly affect our operations. The principal provisions that affect us are those that permit us, subject to certain limitations, to deduct as incurred, rather than to capitalize and amortize/depreciate, our domestic “intangible drilling and 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 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, 2016, we had nineteen full-time employees and two part-time employees, and intend to continue to add additional personnel as our operational requirements grow. We 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.

 

 19 

 

 

Available Information

 

We have closed our offices in Denver, Colorado on February 28, 2017 and moved our corporate headquarter to 300 E. Sonterra Blvd., Suite No. 1220, San Antonio, Texas 78258, and our telephone number is (210) 999-5400. Our web site is www.lilisenergy.com. Additional information that may be obtained through our web site does not constitute part of this Annual Report on Form 10-K. Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports are accessible free of charge at our website. The SEC also maintains an internet site that contains reports, proxy and information statements and other information regarding our filings at www.sec.gov.

 

Item 1A. Risk Factors

 

Investing in our shares of common stock involves significant risks, including the potential loss of all or part of your investment. These risks could 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 on Form 10-K, in addition to the other information contained in this Annual Report on Form 10-K, before you make an investment in our common stock. Additional risks not presently known to us or that we currently deem immaterial may also adversely affect our business. In addition to other matters identified or described by us from time to time in filings with the SEC, there are several important factors that could cause our future results to differ materially from historical results or trends, results anticipated or planned by us, or results that are reflected from time to time in any forward-looking statement. Some of these important factors, but not necessarily all important factors, include the following:

 

Risks Relating to Our Business

 

If we are not able to access additional capital in significant amounts, we may not be able to develop our current prospects and properties, or 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 estimated proved oil and natural gas reserves;
·the amount of oil and natural gas we produce from existing wells;
·the prices at which we sell our production;
·the costs of developing and producing our oil and natural gas reserves;
·our ability to acquire, locate and produce new reserves;
·the ability and willingness of banks to lend to us; and
·our ability to access the equity and debt capital markets.

 

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

 

 20 

 

 

We have substantial liquidity needs and may be required to seek additional financing to fund our 2017 capital budget.  If we are unable to 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:

 

·the level of global exploration and production;

 

·the level of global inventories;

 

·the ability and willingness of members of the Organization of the Petroleum Exporting Countries to agree to and maintain oil price and production controls;

 

·worldwide and regional economic conditions affecting the global supply and demand for oil, NGLs and natural gas;

 

·the price and quantity of imports of foreign oil, NGLs and natural gas;

 

·political and economic conditions in or affecting other producing countries, including conflicts in the Middle East, Africa, South America and Russia;

 

·prevailing prices on local price indexes in the areas in which we operate and expectations about future commodity prices;

 

·the proximity, capacity, cost and availability of gathering and transportation facilities, and other factors that result in differentials to benchmark prices;

 

·localized and global supply and demand fundamentals and transportation availability; the cost of exploring for, developing, producing and transporting reserves;
weather conditions and other natural disasters;
technological advances affecting energy consumption;

 

 21 

 

 

·the price and availability of alternative fuels;
expectations about future commodity prices; and
domestic, local and foreign governmental regulation and taxes.

 

Lower commodity prices may reduce our cash flows and borrowing ability. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our reserves as existing reserves are depleted. Lower commodity prices may also reduce the amount of oil, NGLs, 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.

 

On September 29, 2016, we entered into the Credit Agreement that provides for a three-year senior secured term loan with an aggregate principal amount of $31.0 million outstanding as of December 31, 2016, and $38.1 million outstanding as of March 1, 2017. We may borrow up to an aggregate principal amount of $50 million under the Credit Agreement. Our degree of leverage could have important consequences, including the following:

 

·it may limit our ability to obtain additional debt or equity financing for working capital, capital expenditures, further exploration, debt service requirements, acquisitions and general corporate or other purposes;
·a substantial portion of our cash flows from operations will be dedicated to the payment of principal and interest on our indebtedness and will not be available for other purposes, including our operations, capital expenditures and future business opportunities;
·the debt service requirements of other indebtedness in the future could make it more difficult for us to satisfy our financial obligations;
·we could be vulnerable to any downturn in general economic conditions and in our business, and we could be unable to carry out capital spending and exploration activities that are currently planned; and
·we may from time to time be out of compliance with covenants under our debt agreements, which will require us to seek waivers from our lenders, which may be difficult to obtain.

 

We may incur additional debt, including secured indebtedness, or issue preferred stock in order to maintain adequate liquidity and develop and 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.

 

The Credit Agreement, guaranteed and further secured by substantially all our assets, contains restrictive covenants that may limit our ability to respond to changes in market conditions or pursue business opportunities.

 

The Credit Agreement contains restrictive covenants that limit our ability to, among other things:

 

·incur additional indebtedness;
·create additional liens;
·sell certain of our assets;
·merge or consolidate with another entity;
·pay dividends or make other distributions;
·engage in transactions with affiliates; and
·enter into certain swap agreements.

 

The requirement that we comply with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.

 

 22 

 

 

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 fraud.

 

Our management does not expect that our disclosure controls and procedures 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 benefits 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 any design may not succeed in achieving its intended goals under all potential future conditions. Over time, a control may become inadequate because of changes in conditions, or the degree of compliance with our policies or procedures may deteriorate. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur without detection.

 

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

 

Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, and the rules and regulations promulgated by the SEC to implement Section 404, our management is responsible for establishing and maintaining adequate internal control over financial reporting. 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 evaluation of the effectiveness of our internal control over financial reporting based on framework of internal control issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Because of its inherent limitations, internal controls over financial reporting may not prevent or detect misstatements. In addition, projections of any evaluation effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.

 

Through September 30, 2016, management had concluded that its internal control over financial reporting was not effective. During the fourth quarter of 2016, we completed our remediation 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 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.

 

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. We recognized an impairment expense of approximately $4.7 million and $24.5 million for the years ended December 31, 2016 and 2015, respectively. At December 31, 2016, the Company’s estimates of undiscounted future cash flows indicated that the carrying amounts were not expected to be recovered due to a decrease in proved reserves. During 2016, commodity prices continued to trade in a low range. With low commodity prices sustained for the majority of 2016 in the DJ Basin, some of our properties became uneconomic triggering impairment charge of $4.7 million at December 31, 2016. The impairment charge of $24.5 million in 2015 was due to the lower commodity prices and lack of capital to develop our undeveloped oil and gas properties. 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 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.

 

 23 

 

 

If commodity prices stay at current levels or decline further, we could 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 2016 compared to 2015 is a lower ceiling value each quarter. This may 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:

 

·changes in global supply and demand for oil and natural gas;
·the actions of the Organization of Petroleum Exporting Countries;
·the price and quantity of imports of foreign oil and natural gas;
·acts of war or terrorism;
·political conditions and events, including embargoes, affecting oil-producing activity;
·the level of global oil and natural gas exploration and production activity;
·the level of global oil and natural gas inventories;
·weather conditions;
·technological advances affecting energy consumption;
·the price and availability of alternative fuels; and
·market concerns about global warming or changes in governmental policies and regulations due to climate change initiatives.

 

 24 

 

 

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

 

·there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received;
·our production and/or sales of oil or natural gas are less than expected;
·payments owed under derivative hedging contracts come due prior to receipt of the hedged month’s production revenue; or
·the other party to the hedging contract defaults on its contract obligations.

 

Hedging transactions we may enter into may not adequately protect us from declines in the prices of oil and natural gas. In addition, the counterparties under any future derivatives contracts may fail to fulfill their contractual obligations to us. As of December 31, 2016, we had no hedging agreements in place.

 

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

 

Our management has specifically identified and scheduled drilling locations as an estimation of future multi-year drilling activities on existing acreage. These scheduled drilling locations represent a significant component of our growth 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, actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

 

Drilling for oil and natural gas is a speculative activity and involves numerous risks and substantial and uncertain costs that could adversely affect us.

 

Our success will depend on the success of our drilling program. There is no way to predict in advance of drilling and testing whether any 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 involves numerous risks, including the risk that no commercially productive natural gas or oil reservoirs will be discovered. The cost of drilling, completing, and operating wells 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:

 

 25 

 

 

·unexpected or adverse drilling conditions;
·elevated pressure or irregularities in geologic formations;
·equipment failures or accidents;
·adverse weather conditions;
·compliance with governmental requirements; and
·shortages or delays in the availability of drilling rigs, crews, and equipment.

 

If we decide to drill a certain location, there is a risk that (i) no commercially productive oil or natural gas reservoirs will be found or produced, or (ii) we may drill or participate in new wells that are not productive or drill wells that are productive, but that do not produce sufficient net revenues to return 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 the well. Our overall drilling success rate or drilling success rate for activity within a particular project area may decline. Unsuccessful drilling activities could result in a significant decline in production and revenues and materially 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 from the well or abandonment of the well.

 

Financial difficulties encountered by our oil and natural gas purchasers, third party operators or other third parties could decrease cash flow from operations and adversely affect exploration and development activities.

 

We derive essentially all of our revenues from the sale of our oil and natural gas to unaffiliated third party purchasers, independent 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 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 principle resources necessary for the exploration and production of oil and natural gas are:

 

·leasehold prospects under which oil and natural gas reserves may be discovered;
·drilling rigs and related equipment to explore for such reserves; and
·knowledge personnel to conduct all phases of oil and natural gas operations.

 

We must compete for such resources with both major oil and natural gas companies and independent operators. Virtually all of these 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:

 

 26 

 

 

·the breach of our obligations under the oil and gas leases by which we hold our prospects and the potential loss of those leasehold interests;
·loss of reputation in the oil and gas community;
·inability to retain staff or attract capital;
·a general slowdown in our operations and decline in revenue; and
·decline in market price of our common stock.

 

Seismic studies do not guarantee that hydrocarbons are present or, if present, will produce in economic quantities.

 

We may use seismic studies to assist with assessing prospective drilling opportunities on current properties, as well as on properties that we may acquire. Such seismic studies are merely an interpretive tool and do not necessarily guarantee that hydrocarbons are present or if present will produce in economic quantities.

 

Properties 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.

 

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

 

If an examination of the title history of a property that we purchased reveals an oil and natural gas lease has been purchased in error from a 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 risk of damage or business interruptions from natural disasters or weather events.

 

All of our estimated proved reserves at December 31, 2016, all of our 2016 and 2015 sales were generated in the Delaware Basin in Winkler and Loving Counties, West Texas and Lea County, New Mexico and the DJ Basin in southeastern Wyoming, northeastern Colorado and southwestern Nebraska.

 

Although these areas are well-established oilfield infrastructures, we may be disproportionately exposed to the impact of delays or interruptions 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.

 

 27 

 

 

In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and gas producing areas, which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Due to the concentrated nature of our portfolio 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:

 

·the timing and amount of capital expenditures;
·the operator’s expertise and financial resources;
·approval of other participants in drilling wells;
·selection of technology; and
·the rate of production of reserves, if any.

 

This limited ability to exercise control over the operations of some of drilling locations may cause a material adverse effect on results of 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 third-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 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.

 

 28 

 

 

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 operations involve utilizing drilling and completion techniques as developed by us 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 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 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.

 

Terrorist attacks aimed at energy operations could adversely affect our business.

 

The continued threat of terrorism and the impact of military and other government action have led and may lead to further increased volatility 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 a future target of terrorist organizations. These developments have subjected oil and natural gas operations to increased 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 business.

 

 29 

 

 

We are exposed to operating hazards and uninsured risks.

 

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

 

·fire, explosions and blowouts;
·negligence of personnel;
·inclement weather;
·pipe or equipment failure;
·abnormally pressured formations; and
·environmental accidents such as oil spills, natural gas environment (including groundwater contamination).

 

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

 

·injury or loss of life;
·significantly increased costs;
·severe damage to or destruction of property, natural resources and equipment;
·pollution or other environmental damage;
·clean-up responsibilities;
·regulatory investigation;
·penalties and suspension of operations; or
·attorney’s fees and other expenses incurred in the prosecution or defense of litigation.

 

We maintain insurance against some, but not all, of these risks. Our insurance may not be adequate to cover these losses or liabilities. We do 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. These curtailments can last from a few days to many months, any of which could have an adverse effect on our results of operations.

 

We may not have enough insurance to cover all of the risks faced and operators of prospects in which we participate may not maintain or may fail to obtain adequate insurance.

 

In accordance with customary industry practices, we maintain insurance coverage against some, but not all, potential losses in order to protect against the risks faced. We do not carry business interruption insurance. 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. A system failure or data security breach could have a material adverse effect on our financial condition, results of operations or cash flows.

 

 30 

 

 

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

 

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products 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:

 

·the possibility that such third parties may not be available to us as and when needed; and
·the risk that we may not be able to properly control the timing and quality of work conducted with respect to our projects.

 

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

 

Our business strategy is based on our ability to acquire additional reserves, properties, prospects and leaseholds.  The successful acquisition of producing properties requires an assessment of several factors, including:

 

·recoverable reserves;
·future oil and natural gas prices and their appropriate differentials;
·well and facility integrity;
·development and operating cost;
·regulatory constraints and plans; and
·potential environmental and other liabilities.

 

 31 

 

 

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” basis.

 

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

 

·diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;
·challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of ours while carrying on our ongoing business;
·difficulty associated with coordinating geographically separate organizations;
·challenge of attracting and retaining capable personnel associated with acquired operations; and
·failure to realize the full benefit that we expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition, or to realize these benefits within the expected time frame.

 

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.

 

We may have difficulty managing growth in our business, which could adversely affect our financial condition and results of operations.  

 

Significant growth in the size and scope of our operations would place a strain on our financial, technical, operational and management resources.  The failure to continue to upgrade our technical, administrative, operating and financial staff and control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, geologists, engineers and other professionals in the oil and gas industry could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.

 

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.

 

 32 

 

 

We operate in areas of high industry activity, which may affect our ability to hire, train or retain qualified personnel needed to manage and operate 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. Relatively recently, the EPA adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States on an annual basis, including petroleum refineries, as well as certain onshore oil and natural gas production facilities.

 

Also, on May 12, 2016, EPA issued regulations (effective August 2, 2016) that build on the 40 C.F.R. Part 60, Subpart OOOO (NSPS OOOO) standards by directly regulating methane and VOC emissions from various types of new and modified oil and gas sources. Some of those sources are already regulated under NSPS OOOO, while others, like hydraulically fractured oil wells, pneumatic pumps, and certain equipment and components at compressor stations, are covered for the first time. On March 10, 2016, moreover, the EPA announced that it is moving towards issuing performance standards for methane emissions from existing oil and gas sources. The agency said that it will “begin with a formal process (i.e., an Information Collection Request) to require companies operating existing oil and gas sources to provide information to assist in the development of comprehensive regulations to reduce methane emissions.” On November 10, 2016, the EPA issued the Information Collection Request (“ICR”) and explained that “[r]ecipients of the operator survey (also referred to as Part 1) will have 60 days after receiving the ICR to complete the survey and submit it to EPA….Recipients of the more detailed facility survey (also referred to as Part 2) will have 180 days after receiving the ICR to complete that survey and submit it to the agency.”

 

In June 2014, the United States Supreme Court’s holding in Utility Air Regulatory Group v. EPA upheld a portion of EPA’s greenhouse gas (“GHG”) stationary source permitting program, but also invalidated a portion of it. The Court held that stationary sources already subject to the Prevention of Significant Deterioration (“PSD”) or Title V permitting programs for non-GHG criteria pollutants remain subject to GHG Best Available Control Technology and major source permitting requirements, but ruled that sources cannot be subject to the PSD or Title V major source permitting programs based solely on GHG emission levels. As a result, on August 12, 2015, the EPA eliminated from its PSD and Title V regulations the provisions that subjected sources to the PSD or Title V programs based solely on GHG emission levels. The EPA likewise said that it will “further revise the PSD and Title V regulations in a separate rulemaking to fully implement” the Utility Air Regulatory Group judgment. On October 3, 2016, EPA published a proposed rulemaking for that purpose. The Utility Air Regulatory Group judgment does not prevent states from considering and adopting state-only major source permitting requirements based solely on GHG emission levels.

 

 33 

 

 

In addition, the U.S. Congress has from time to time considered adopting legislation to reduce GHG emissions and almost one-half of the states have already taken legal measures to reduce GHG emissions, primarily through the planned development of GHG emission inventories and/or regional GHG 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 GHG emission reduction goal.

 

The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase 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 could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHG in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

 

Federal and state 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.

 

The Bureau of Land Management (“BLM”), on March 20, 2015, issued its final regulations for hydraulic fracturing on federal and tribal lands. The new regulations require, among other things, disclosure of chemicals, annulus pressure monitoring, flow back and produced water management and storage, and more stringent well integrity measures associated with hydraulic fracturing operations on public land. On June 21, 2016, however, the U.S. District Court for the District of Wyoming enjoined BLM from enforcing the regulations, concluding that the agency lacked the authority to issue them. BLM appealed that decision to the U.S. Court of Appeals for the Tenth Circuit. The appeal is pending.

 

In addition, on June 13, 2016, under the Clean Water Act, the EPA finalized a rule (effective August 29, 2016) that prohibits the discharge of oil and gas wastewaters to publicly-owned treatment works.

 

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example in May 2013, the RRC adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

 

While these state and local land use restrictions generally cover areas with little recent or ongoing oil and gas development, they could lead opponents of hydraulic fracturing to push for similar statewide regimes. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

 

A number of federal agencies are analyzing, or have been requested to review, environmental issues associated with hydraulic fracturing. The EPA, for example, recently completed a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. In June of 2015, the EPA released an “external review draft” of the study and, in it, said that shale development had not led to “widespread, systemic” problems with groundwater. On August 11, 2016, however, the EPA Science Advisory Board issued comments on the external review draft, finding that “the EPA did not support quantitatively its conclusion about lack of evidence for widespread, systemic impacts of hydraulic fracturing on drinking water resources, and did not clearly describe the system(s) of interest (e.g., groundwater, surface water), the scale of impacts (i.e., local or regional), nor the definitions of ‘systemic’ and ‘widespread.’” In December of 2016, the EPA released the final version of the study, finding, among other things, that there are “certain conditions under which impacts from hydraulic fracturing activities can be more frequent or severe,” including “[i]njection of hydraulic fracturing fluids into wells with inadequate mechanical integrity, allowing gases or liquids to move to groundwater resources.” These types of studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.

 

 34 

 

 

The EPA also issued an advance notice of proposed rulemaking and undertook a public participation process under the Toxic Substances Control Act to seek comment on the information that should be reported or disclosed for hydraulic fracturing chemical substances and mixtures and the mechanisms for obtaining this information. Additionally, on January 7, 2015, several national environmental advocacy groups filed a lawsuit requesting that the EPA add the oil and gas extraction industry to the list of industries required to report releases of certain “toxic chemicals” under the Emergency Planning and Community Right-to-Know Act’s Toxics Release Inventory, or TRI, program. On October 22, 2015, the EPA took action on the Environmental Integrity Project’s October 24, 2012 petition to impose TRI reporting requirements on various oil and gas facilities. The EPA granted the petition in part, by agreeing to propose to add natural gas processing facilities to the scope of the TRI program, but rejected the rest of the petition. On December 15, 2015, in light of that decision, the environmental advocacy groups that had commenced the lawsuit opted to voluntarily dismiss it. On January 6, 2017, EPA issued a proposed rulemaking that would add natural gas processing facilities to the scope of the TRI program.

 

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.

 

 35 

 

 

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

 

Our operations are subject to extensive federal, state and local laws and regulations relating to the exploration, production and sale of oil and natural gas, 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:

 

·land use restrictions;
·lease permit restrictions;
·drilling bonds and other financial responsibility requirements, such as plugging and abandonment bonds;
·spacing of wells;
·unitization and pooling of properties;
·safety precautions;
·operational reporting; and
·taxation.

 

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

 

·personal injuries;
·property and natural resource damages;
·well reclamation cost; and
·governmental sanctions, such as fines and penalties.

 

Our operations could be significantly delayed or curtailed and our cost of operations could significantly increase as a result of regulatory requirements or restrictions. It is also possible that a portion of our oil and gas properties could be subject to eminent domain proceedings or other government takings for which we may not be adequately compensated. See “Business—Regulation of the Oil and Natural Gas Industry” for a more detailed description of regulatory laws covering our business.

 

Our 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:

 

·require the acquisition of a permit before drilling or facility mobilization and commissioning, or injection or disposal commences;
·restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production and processing activities, including environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells;
·limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and
·impose substantial liabilities for pollution resulting from our operations.

 

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

 

·the assessment of administrative, civil and criminal penalties;
·incurrence of investigatory or remedial obligations; and
·the imposition of injunctive relief.

 

 36 

 

 

Changes in environmental laws and regulations occur frequently and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to reach and maintain compliance and may otherwise have 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— Regulation of the Oil and Natural Gas Industry” for a more detailed description of the environmental laws covering our business.

 

Should we fail to comply with all applicable regulatory agency administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

 

Under the Domenici-Barton Energy Policy Act of 2005, the FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting requirements. We also must comply with the anti-market manipulation rules enforced by FERC. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Additionally, the Federal Trade Commission has regulations intended to prohibit market manipulation in the petroleum industry with authority to fine violators of the regulations civil penalties of up to $1 million per day, and the CFTC prohibits market manipulation in the markets regulated by the CFTC, including similar anti-manipulation authority with respect to crude oil swaps and futures contracts as that granted to the CFTC with respect to crude oil purchases and sales. The CFTC rules subject violators to a civil penalty of up to the greater of $1 million or triple the monetary gain to the person for each violation. Failure to comply with those regulations in the future could subject us to civil penalty liability, as described in “Business-Regulation of the Oil and Natural Gas Industry.”

 

Risks Relating to Our Securities

 

Our common stock may be subject to penny stock rules which limit the market for our common stock.

 

Our shares of common stock likely qualify as “penny stock” under the SEC rules. Sales and purchases of “penny stock” generally require more disclosures by broker-dealers and satisfaction of other administrative requirements. As a result, broker-dealers may be less willing to execute transactions in securities subject to the “penny stock” rules. This may make it more difficult for investors to dispose of our common stock and cause a decline in the market value of our stock.

 

There is a limited public market for our common stock and an active trading market or a specific share price may not be established or maintained.

 

On May 26, 2016, our common stock was suspended from trading on the Nasdaq and immediately began trading on the OTCQB Venture Marketplace, or the OTCQB. On July 29, 2016, the Nasdaq announced that it will delist our common stock and file a Form 25 with the Securities and Exchange Commission. The Form 25 was subsequently filed on August 1, 2016, and the delisting became effective on August 11, 2016. We have applied for relisting on the Nasdaq and are working to show full compliance with all applicable Nasdaq initial listing criteria.

 

While our common stock trades on the OTCQB, trading activity in our common stock generally occurs in small volumes each day.  The value of our common stock could be affected by:

 

·actual or anticipated variations in our operating results;
·the market price for crude oil;
·changes in the market valuations of other oil and gas companies;
·announcements by us or our competitors of significant acquisitions, strategic partnerships, joint ventures or capital commitments;
·adoption of new accounting standards affecting our industry;
·additions or departures of key personnel;
·sales of our common stock or other securities in the open market;
·actions taken by our lenders or the holders of our convertible debentures;
·changes in financial estimates by securities analysts;
·conditions or trends in the market in which we operate;
·changes in earnings estimates and recommendations by financial analysts;
·our failure to meet financial analysts’ performance expectations; and
·other events or factors, many of which are beyond our control.

 

 37 

 

 

In a volatile market, you may experience wide fluctuations in the market price of our common stock.  These fluctuations may have an extremely negative effect on the market price of our common stock and may prevent you from obtaining a market price equal to your purchase price when you attempt to sell our common stock in the open market.  In these situations, you may be required either to sell at a market price which is lower than your purchase price, or to hold our common stock for a longer period of time than you planned.  An inactive market may also impair our ability to raise capital by selling shares of capital stock and may impair our ability to acquire other companies or oil and gas properties by using our common stock as consideration.

 

 

If an orderly and active trading market for our securities does not develop or is not sustained, the value and liquidity of your investment in our securities could be adversely affected.

 

An active or liquid market in our common stock or securities exercisable or convertible for our common stock does not currently exist and might not develop or, if it does develop, it might not be sustainable. The last reported sale price of our common stock on the OTCQB on March 1, 2017 was $4.00 per share. The historic bid and ask quotations for our common stock, however, should not be viewed as an indicator of the current or historical market price for our common stock nor as an indicator of the market price for our common stock if our common stock were to be listed on a national securities exchange. The offering price for our securities as issued by us from time to time is determined through discussions between us and the prospective investor(s), with reference to the most recent closing price of our common stock on the OTCQB, and may vary from the market price of our securities following any offering. Further, our trading volume on the OTCQB has been generally very limited.

 

If an active public market for our common stock develops, we expect the market price may be volatile, which may depress the market price of our securities and result in substantial losses to investors if they are unable to sell their securities at or above their purchase price.

 

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

 

·our status as a company with a limited operating history and limited revenues to date, which may make risk-averse investors more inclined to sell their shares on the market more quickly and at greater discounts than would be the case with the shares of a seasoned issuer in the event of negative news or lack of progress;
·announcements of technological innovations or new products by us or our existing or future competitors;
·the timing and development of our products;
·general and industry-specific economic conditions;
·actual or anticipated fluctuations in our operating results;
·liquidity;
·actions by our stockholders;
·changes in our cash flow from operations or earnings estimates;
·changes in market valuations of similar companies;
·our capital commitments; and
·the loss of any of our key management personnel.

 

In addition, market prices of the securities of energy companies, particularly companies like ours without consistent revenues and earnings, have been highly volatile and may continue to be highly volatile in the 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 are currently seeking to list our securities on a national securities exchange, there is no assurance we will be able to do so, and if we do so, many of these same forces and limitations may still impact our trading volumes and market price in the near term. Additionally, the sale or attempted sale of a large amount of common stock into the market may also have a significant impact on the 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 past, securities class action litigation has often been brought against companies that experience high volatility in the market price of their securities. Whether or not meritorious, litigation brought against us could result in substantial costs, divert management’s attention and resources and harm our financial condition and results of operations. 

  

 38 

 

 

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

 

Our articles of incorporation authorize our board of directors to issue one or more series of preferred stock and set the terms of the preferred stock without seeking any further approval from our shareholders. Any preferred stock that is issued may rank ahead of our common stock, in terms of dividends, liquidation rights and voting rights. We currently have two series of preferred stock issued and outstanding, both of which provide its holders with 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.

 

We have a significant amount of derivative securities outstanding, which upon exercise or conversion, would result in substantial dilution. For example, the conversion of the remaining Series B preferred stock in full could result in the issuance of 15,454,545 shares of common stock, and the exercise of outstanding 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 our 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.

 

We have never paid dividends with respect to our common stock, and we do not expect to pay any dividends, in cash or otherwise, in the foreseeable future. We intend to retain any earnings for use in our business. In addition, our Credit Agreement prohibits us from paying any dividends and the 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.

 

Securities analysts may not initiate coverage of our shares or may issue negative reports, which may adversely affect the trading price of the shares.

 

Securities analysts may not provide research reports on our company. If securities analysts do not cover our company, this lack of coverage may 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.

 

 39 

 

 

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

 

Though not now, in the future we may become subject to Nevada’s control share law. A corporation is subject to Nevada’s control share law if it 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

 

We may from time to time be involved in various legal actions arising in the normal course of business. However, we do not believe there is any currently pending litigation that could have, individually or in the aggregate, a material adverse effect on our results of operations or financial condition.

 

Item 4. Mine Safety Disclosures

 

Not applicable.

 

 40 

 

 

PART II

 

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

 

Recent Market Prices

 

We began trading on the OTCQB Venture Marketplace under the symbol “LLEX” on May 27, 2016. From February 11, 2016 to May 26, 2016, our common 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 “LLEX.” We have applied for relisting on the Nasdaq and are working to show full compliance with all applicable Nasdaq initial listing criteria.

 

The following table shows the high and low reported sales prices of our common stock for the periods indicated. The prices reported in this table have been adjusted to reflect the 1-for-10 reverse split of our issued and outstanding common stock, which took effect on June 23, 2016.

 

   High   Low 
   2016 
Fourth Quarter  $3.75   $2.10 
Third Quarter  $3.51   $1.08 
Second Quarter  $2.33   $0.50 
First Quarter  $3.70   $1.00 

 

   2015 
Fourth Quarter  $7.00   $0.70 
Third Quarter  $31.50   $4.80 
Second Quarter  $19.00   $7.40 
First Quarter  $12.60   $6.00 

 

As of March 1, 2017, there were 135 owners of record of our common stock. We estimate that there are approximately 1,833 beneficial holders of our common stock

 

Dividend Policy

 

We have never paid any cash dividends on our common stock and do not anticipate paying any dividends in the foreseeable future. Our current business plan is to retain any future earnings to finance the expansion and development of our business. Any future determination to pay cash dividends will be at the discretion of our Board of Directors, and will be dependent upon our financial condition, results of operations, capital requirements and other factors as our board may deem relevant at that time. In addition, we are currently restricted from declaring any dividends pursuant to the terms of our Credit Agreement and outstanding preferred stock. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—“Liquidity and Capital Resources.”

 

Recent Sales of Unregistered Securities

 

We have previously disclosed by way of Quarterly Reports on Form 10-Q and Current Reports on Form 8-K filed with the SEC all sales by us of our unregistered securities during the year ended December 31, 2016.

 

Equity Compensation Plans

 

Information regarding equity compensation plans is set forth in Item 12 of this Annual Report on Form 10-K and is incorporated herein by reference.

 

Item 6. Selected Financial Data

 

Not applicable.

 

 41 

 

 

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes in “Part II, Item 8. Financial Statements and Supplementary Data.” The following discussion and analysis contains forward-looking statements, including, without limitation, statements relating to our plans, strategies, objectives, expectations, intentions and resources. Please see “Cautionary Statement Concerning Forward-Looking Statements” and “Part I, Item 1A. Risk Factors” in this Annual Report on Form 10-K.

 

General

 

We are an independent oil and gas company engaged in the acquisition, drilling and production of oil and natural gas properties and prospects. We were incorporated in August of 2007 in the State of Nevada as Universal Holdings, Inc. In October 2009, we changed our name to Recovery Energy, Inc. and in December 2013, we changed our name to Lilis Energy, Inc.

 

On June 23, 2016, we completed a merger (the “Merger”) with Brushy Resources, Inc. (“Brushy”), which resulted in the acquisition of our properties in the Delaware Basin as well as the majority of our current operating activity.

 

Additionally, in connection with the Merger on June 23, 2016, we effected a 1-for-10 reverse stock split. 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 across multiple productive horizons. Our primary focus is drilling horizontal wells in the Delaware Basin of West Texas, which we believe will provide attractive returns on a majority of our acreage position. Our goal is to earn economic returns to our shareholders through cash flow from new production of oil, 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, with an initial focus on targeting the Wolfcamp formation. We drilled our first horizontal well in late 2016 and completed it in 2017.

 

Overview of Our Business and Strategy

 

We are an oil and natural gas company, engaged in the acquisition, development and production of unconventional oil and natural gas properties. We have accumulated approximately 6,924 net acres in what we believe to be the core of the Delaware Basin in Winkler and Loving Counties, Texas and 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, 68% of our acreage position is held by production, and we are the named operator on 100% of our acreage. These two 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 in the Delaware Basin.

 

We generate the vast majority of our revenues from the sale of oil for our producing wells. The prices of oil and natural gas are critical factors to our success. Volatility in the prices of oil and natural gas could be detrimental to our results of operations. Our business requires substantial capital to acquire producing properties and develop our non-producing properties. As the price of oil declines and causes our revenues to decrease, we generate less cash to acquire new properties or develop our existing properties and the price decline may also make it more difficult for us to obtain any debt or equity financing to supplement our cash on hand.

 

Our Board has approved a drilling program of up to 10 gross Delaware Basin wells (6 net) that is contingent upon our access to sufficient capital to fully execute. In the first quarter of 2017, we completed two wells, and we have begun drilling a third well.  We expect our 2017 horizontal drilling program will be focused almost exclusively on the Wolfcamp zone of the Delaware Basin, with lateral lengths ranging from approximately 5,000’ laterals to 7,000’ laterals. 

 

 42 

 

 

Based upon current commodity price expectations for 2017, we believe that our cash flow from operations, combined with the proceeds of our recently completed equity offering, proceeds from the conversion of in-the-money warrants to equity, and availability under our Credit Facility, will be sufficient to fund our operations for 2017, including working capital requirements.  However, future cash flows are subject to a number of variables, including uncertainty in forecasted production volumes and commodity prices.  We are the operator for 100% of our 2017 operational capital program and, as a result, the amount and timing of a substantial portion of our capital expenditures is discretionary.  Accordingly, we may determine it prudent to curtail drilling and completion operations due to capital constraints or reduced returns on investment as a result of commodity price weakness.

 

The results of operations of Brushy are included with those of ours from June 23, 2016 through December 31, 2016. As a result, results of operations for the year ended December 31, 2016 are not necessarily comparable to the results of operations for prior periods. Additionally, all discussion related to historical representations of common stock, unless otherwise noted, give retroactive effect to the reverse split for all periods presented.

 

Results of Operations

 

Results of operations for the year ended December 31, 2016 compared to the year ended December 31, 2015

 

The following table compares operating data for the years ended December 31, 2016 and 2015 (in thousands):

 

   Years Ended December 31,         
   2016   2015   Variance   % 
   (In Thousands)         
Revenue:                    
Oil  $2,418   $292   $2,126    728%
Gas   1,012    77    935    1214%
Other   5    27    (22)   -81%
   $3,435   $396   $3,039    767%

 

Total Revenue

 

Total revenue was approximately $3.4 million ($1.8 million from Brushy) for the year ended December 31, 2016 as compared to $0.4 million for the year ended December 31, 2015, representing an increase of approximately $3.0 million or 767%. The increase in revenue was primarily attributable to approximately $1.8 million in revenues from Brushy’s operations during the second half of 2016 and increase of approximately $1.2 million in revenues from the DJ Basin due to increase in production volumes.

 

The following table compares production volumes and average prices for the years ended December 31, 2016 and 2015:

 

   For the Year Ended
December 31,
 
   2016   2015 
Product          
Oil (Bbl.)   61,088    7,067 
Oil (Bbls)-average price  $39.59   $41.36 
           
Natural Gas (MCFE)-volume   400,775    32,291 
Natural Gas  (MCFE)-average price  $2.54   $2.39 
           
Barrels of oil equivalent (BOE)   127,863    12,449 
Average daily net production (BOE)   350    34 
Average Price per BOE  $26.87   $29.67 

 

 43 

 

 

Oil and Gas Production Costs, Production Taxes, Depreciation, Depletion, and Amortization

 

The following tables compares oil and gas production costs, production taxes, depreciation, depletion, and amortization for the years ended December 31, 2016 and 2015:

 

   For the Year Ended
December 31,
 
   2016   2015 
Production costs per BOE  $9.75   $15.70 
Production taxes per BOE   (1.30)   2.24 
Depreciation, depletion, and amortization per BOE   12.25    46.93 
Total operating costs per BOE  $20.70   $64.87 
Gross margin per BOE  $6.17   $(35.20)
Gross margin percentage   23%   (119)%

 

   Years Ended December 31,         
   2016   2015   Variance   % 
   (In Thousands)         
Costs and expenses:                    
Production costs  $1,247   $195   $1,052    539%
Production taxes   (167)   28    (195)   -696%
General and administrative   14,570    7,930    6,640    84%
Depreciation, depletion and amortization   1,566    574    992    173%
Accretion of asset retirement obligations   132    10    122    1220%
Impairment of evaluated oil and gas properties   4,718    24,478    (19,760)   -81%
Total operating expenses   22,066    33,215    (11,149)   -34%
                     
Loss from operations  $(18,631)  $(32,819)  $14,188    -43%

 

Production Costs

 

Production costs were $1.2 million for the year ended December 31, 2016, compared to $0.2 million for the year ended December 31, 2015, an increase of $1 million or 539%. The increase is primarily attributable to Brushy’s operations. Production costs per BOE decreased to $9.75 for the year ended December 31, 2016 from $15.70 in 2015, a decrease of $5.95 per BOE, or 38%, primarily due to Brushy’s lower production costs. The Company anticipates that its production costs in the near term would be closer to the level of Brushy’s historical production costs.

 

Production Taxes

 

Production taxes were $(0.2) million for the year ended December 31, 2016, compared to $0.03 million for the year ended December 31, 2015, a decrease of $(0.2) million or -696%. Currently, ad valorem, severance and conservation taxes range from 1% to 13% based on the state and county from which production is derived. Production taxes per BOE decreased to $(1.30) during the year ended December 31, 2016 from $2.24 in 2015, a decrease of $(3.54) or -158%. Subsequent to the issuance of our consolidated financial statements for the year ended December 31, 2016, we determined that certain ad valorem and severance tax estimates were higher than the actual amount billed, resulting in a tax benefit to us.

 

General and Administrative Expenses

 

General and administrative expenses were $14.5 million during the year ended December 31, 2016, compared to $7.9 million during the year ended December 31, 2015, an increase of $6.6 million, or 84%. The increase of $6.6 million in general and administrative expenses was attributable to an increase of $3.9 million to $7.1 million in non-cash stock-based compensation expense, a $0.6 million increase in legal fees associated with the Merger, an increase of $1.5 million in payroll primarily due to the addition of 18 former Brushy employees, bonuses paid to officers at the completion of the Merger and an increase of $0.6 million in other administrative office expenses.

 

 44 

 

 

Depreciation, Depletion, and Amortization

 

Depreciation, depletion, and amortization (“DD&A”) was $1.6 million during the year ended December 31, 2016, compared to $0.6 million during the year ended December 31, 2015, an increase of $1.0 million, or 173%. The increase in DD&A was the result of the increase in production associated with the acquisition of the oil and gas properties in the Delaware Basin, New Mexico and Winkler County, Texas after the Merger. As a result of the Merger, our DD&A rate decreased to $12.25 per BOE in 2016 from $46.93 per BOE in 2015. The DD&A rate decreased primarily due to the volumes increase of 115,414 barrels, or 927% from 12,449 BOE in 2015.

 

Impairment of Evaluated Oil and Gas Properties

 

Total impairment charges of $4.7 million were recorded during year ended December 31, 2016 as compared to $24.5 million during the year ended December 31, 2015, a decrease of $19.8 million or 81%.  The decrease of $19.8 million was primarily due to full cost limitations recognized in the first and third quarter of 2015. The impairment expense of $24.5 million in 2015 was attributable to the write off of our proved undeveloped oil and gas properties in the DJ Basin due to lack of available capital to fund development coupled with significant decrease in oil prices, and to a lesser extent, natural gas prices, that started in late 2014 and continued throughout 2015.

 

   Years Ended December 31,         
   2016   2015   Variance   % 
   (In Thousands)         
Other income (expenses):                    
Other income   90    3    87    2900%
Debt conversion inducement expense   (8,307)   -    (8,307)   -% 
Gain on extinguishment of debt   250    -    250    -% 
Gain (loss) in fair value of derivative instruments   (1,222)   1,638    (2,860)   -175%
Gain (loss) in fair value of conditionally redeemable 6% preferred stock   (701)   514    (1,215)   -236%
Gain on modification of convertible debts   602    -    602    -% 
Interest expense   (4,924)   (1,697)   (3,227)   190%
Total other income (expenses)   (14,212)   458    (14,670)   -3203%
                     
Net loss   (32,843)   (32,361)   (482)   1%

 

Inducement Expense

 

During the year ended December 31, 2016, an inducement expense of approximately $8.3 million was incurred as a result of debt and equity restructuring associated with the Merger. The inducement expense resulted from the repricing of our warrants to induce conversion of our convertible debt and our Series A preferred stock into common stock.

 

Gain on Extinguishment of Debt

 

During the year ended December 31, 2016, we recognized a gain of approximately $0.3 million attributed to a discount from Heartland Bank to settle the outstanding balance we owed under the Heartland Credit Agreement.

 

Change in Fair Value in Derivative Instruments

 

The change in fair values of derivative instruments comprised a loss of approximately $1.2 million during the year ended December 31, 2016, as compared to an approximately $1.6 million gain during the year ended December 31, 2015, is as follows:

 

·Bristol Warrant Liabilities. On September 2, 2014, we entered into a Consulting Agreement with Bristol Capital, LLC (“Bristol”), pursuant to which we issued to Bristol a warrant to purchase up to 100,000 shares of our common stock at an exercise price of $20.00 per share (or, in the alternative, 100,000 options, but in no case both). The agreement has a price protection feature that will automatically reduce the exercise price if we enter into another consulting agreement pursuant to which warrants are issued with a lower exercise price, which triggered in year 2016 and accordingly, the Company agreed to issue additional warrants/options to purchase 541,026 shares of common stock at a revised exercise price of $3.12. The change in fair value of this warrant provision was a loss of $1.2 million and a gain of $0.4 million for the years ended December 31, 2016 and 2015, respectively.

 

 45 

 

 

·Heartland Warrant Liability. On January 8, 2015, we entered into the Heartland Credit Agreement. In connection with the Heartland Credit Agreement, we issued to Heartland a warrant to purchase up to 22,500 shares of our common stock at an exercise price of $25.00. The warrant contains a price protection feature that will automatically reduce the exercise price if we enter into another agreement pursuant to which warrants are issued with a lower exercise price. The change in fair value valuation from issuance was $0.03 million and $0.01 million for the year ended December 31, 2016 and 2015, respectively.

 

·SOSV Investments LLC Warrant Liability. On June 23, 2016, in conjunction with the Merger, we issued to SOSV Investments LLC (“SOS”) a warrant to purchase up to 200,000 shares of our common stock at an exercise price of $25.00. The warrant contains a price protection feature that will automatically reduce the exercise price if we enter into another agreement pursuant to which warrants are issued with a lower exercise price. For the year ended December 31, 2016, we incurred a change in the fair value of the derivative liability related to the warrant of approximately $0.1 million.

 

Interest Expense

 

For the years ended December 31, 2016 and 2015, we incurred an interest expense of approximately $4.9 million and $1.7 million, respectively, of which approximately $4.2 million and $1.3 million was classified as non-cash interest expense in 2016 and 2015, respectively. The details of the non-cash interest expense for the year ended December 31, 2016 are as follows: (i) accretion of $3.9 million of discount associated with bridge loans, convertible notes, the credit facility and term loan and (ii) amortization of the deferred financing costs of $0.3 million. The non-cash interest expense for the year ended December 31, 2015 was primarily attributable to the amortization of the deferred financing costs of approximately $0.1 million.

 

At the current levels of net oil and gas production, cash balances, interest rates, and oil and gas prices, our revenue is unlikely to exceed our expenses. Unless and until we invest a substantial portion of our cash balances in interests in producing oil and gas wells or in one or more other ventures that produce revenue and net income, we are likely to experience net losses. With the exception of unanticipated environmental expenses and possible changes in interest rates and oil and gas prices, we are not aware of any other trends, events, or uncertainties that have had or that are reasonably expected to have a material impact on net sales or revenues or income from continuing operations.

 

Liquidity and Capital Resources

 

Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions and investors, the sale of equity derivative securities and asset dispositions. Our primary uses of capital have been for the acquisition, development, exploration and exploitation of oil and natural gas properties, in addition to refinancing of debt instruments. In 2016, we entered into a new Credit Agreement and completed a preferred stock offering to raise additional capital. We regularly evaluate alternative sources of capital to complement our cash flow from operations and other sources of capital as we pursue our long-term growth plans in the Delaware Basin. In order to fully fund our 2017 capital budget, we may be required to access to new capital through one or more offerings of equity.

 

We have reported net operating losses during the year ended December 31, 2016 and for the past five years. As a result, we funded our operations in 2016 and the merger with Brushy Resources, Inc. through additional debt and equity financing. On September 29, 2016, we entered into a new Credit and Guaranty Agreement (the “Credit Agreement”) that provides for a three-year, senior, secured term loan with initial aggregate principal commitments of $31 million and a maximum facility size of $50 million. The initial commitment on the term loan was funded with $25 million collected as of September 30, 2016 and the additional $6 million collected as of November 11, 2016.

 

As of December 31, 2016, the Company had a working capital balance and a cash balance of approximately $5.7 million and $11.5 million, respectively. As of March 1, 2017, after giving effect to a drawdown of $7.1 million in additional term loan debt under the Credit Agreement on February 7, 2017, but excluding, the commitments entered into in connection with the March 2017 Private Placement (defined below) our cash balance was approximately $9.0 million. We believe that we will have sufficient capital to operate over the next 12 months. However, it is possible that we will seek to raise additional debt and equity capital depending on the pace of our drilling and leasing activity.

 

 46 

 

 

Information about our year-end cash flows are presented in the following table (in thousands):

 

   Year ended
December 31,
 
   2016   2015 
Cash provided by (used in):          
Operating activities  $(6,309)  $(3,951)
Investing activities   (19,130)   (1,703)
Financing activities   37,067    5,254 
Net change in cash  $11,628   $(400)

 

Operating activities. For the year ended December 31, 2016, net cash used in operating activities was $6.3 million, compared to $4.0 million for the same period in 2015. The increase of $2.3 million cash used in operating activities was primarily attributable to the increase in operating costs and changes in working capital.

 

Investing activities. For the year ended December 31, 2016, net cash used in investing activities was $19.1 million compared to $1.7 million for the same period in 2015. The $17.4 million increase in cash used in investing activities was primarily attributable to the following:

 

·a $7.5 million increase in drilling and completion costs on the Grizzly and Bison wells;
·a $4.2 million increase in oil and gas lease extension fees;
·a $2.3 million cash consideration for the Merger, net of cash acquired; and
·a $3.4 million increase on other capital expenditures relating to the DJ Basin and the Delaware Basin properties.

 

Financing activities. For the year ended December 31, 2016, net cash provided by financing activities was $37.1 million compared to cash provided by financing activities of $5.3 million during the same period of 2015. The increase of $31.8 million in net cash provided by financing activities was primarily attributable to the following:

 

·an $18.2 million increase in net proceeds from the issuance of the Series B preferred stock;
·a $30.0 million increase in net proceeds from the term loan facility executed during the third quarter of 2016;
·a $0.3 million increase in proceeds received from the exercise of stock warrants;
·offset by a $3.1 million decrease in net proceeds from the Bridge Loans; and
·offset by an increase of $13.6 million in repayment of principal balances due to the Heartland Bank and Independent Bank.

 

 

Merger with Brushy

 

We paid deposits and operating expenses of Brushy toward completion of the Merger of approximately $3.0 million, net of $0.7 million cash acquired, which is recorded as additional consideration.

 

In connection with the closing of the Merger, we entered into the following financing transactions:

 

Series A Preferred Stock Conversion

 

On June 23, 2016, after receiving the requisite shareholder approval and upon consummation of the Merger, each outstanding share of our Series A preferred stock automatically converted into common stock at a conversion price of $5.00 resulting in the issuance of 1,500,000 shares of common stock. In exchange for the reduction in price to convert into our common stock, all accrued, but unpaid dividends were forfeited.

 

 47 

 

 

Series B 6% Preferred Stock

 

On June 15, 2016, we entered into a private placement to sell 20,000 shares of our Series B 6% convertible preferred stock (the “Series B Preferred Stock”) with a conversion price of $1.10 and warrants to purchase up to 9,090,926 shares of common stock at an exercise price of $2.50, exercisable immediately for a period of two years under certain circumstances, for gross proceeds of $20 million. For a more detailed description of the terms of the Series B Preferred Stock see Note 13-Shareholders Equity.

 

In connection with the Series B Preferred Stock offering, we also paid a fee of $350,000 and $900,000 to T.R. Winston & Company, LLC (“TRW”) and KES 7 Capital Inc. (“KES 7”), respectively, who acted as co-placement agents with TRW also acting as administrative agent. Each of TRW and KES 7 also received fee warrants to purchase up to 452,724 and 820,000 shares of common stock, respectively, at an exercise price of $1.30, exercisable on or after September 17, 2016, for a period of two years. In addition, TRW received 150 shares of Series B Preferred Stock and the related warrants to purchase 68,182 shares of common stock at an exercise price of $2.50.

 

Debentures

 

On June 23, 2016, pursuant to the terms of the Debenture Conversion Agreement, dated as of December 29, 2015, our remaining outstanding 8% Convertible Debentures converted automatically upon consummation of the Merger at $5.00 per share, resulting in the issuance of 1,369,293 shares of common stock. In exchange for the lowering the conversion price, all accrued but unpaid interest was forfeited. The modification of such conversion rate resulted in an immaterial gain. The Convertible Debentures and associated derivative liability was then reclassified to additional paid-in capital.

 

Heartland Bank

 

On January 8, 2015, we entered into the Credit Agreement with Heartland Bank (the “Heartland Credit Agreement”), as administrative agent and the Lenders party thereto. The Heartland Credit Agreement provided for a three-year senior secured term loan in an initial aggregate principal amount of $3,000,000 (the “Heartland Term Loan”).

 

In connection with the consummation of the Merger, on June 22, 2016, we repaid the balance of our outstanding indebtedness with Heartland at a discount of $250,000, resulting in the elimination of $2.75 million in senior secured debt and the extinguishment of Heartland’s security interest in our assets.

 

Independent Bank and Promissory Note

 

On June 22, 2016, in connection with the completion of the Merger, we entered into an amendment with Brushy and its senior secured lender, Independent Bank (the “Lender”), to Brushy’s Forbearance Agreement with the Lender (the “Fourth Amendment”), which, among other things, provided for a pay-down of $6.0 million of the principal amount outstanding on the loan (the “Loan”), plus fees and other expenses incurred in connection with the Loan, in exchange for an extension of the maturity date through December 15, 2016, at an interest rate of 6.5%, payable monthly. Additionally, we agreed to (i) guaranty the approximately $5.4 million aggregate principal amount of the Loan, (ii) grant a lien in favor of the Lender on all of our real and personal property, (iii) restrict the incurrence of additional debt and (iv) maintain certain deposit accounts with various restrictions with the Lender.

 

As a condition of the Fourth Amendment and pursuant to the Merger Agreement, Brushy also completed the divestiture of certain of its assets in South Texas to its subordinated lender, SOS Ventures (“SOS”), in exchange for the extinguishment of $20.5 million of subordinated debt, a cash payment of $500,000, the issuance of the SOS Note, and the issuance of the SOS Warrant.

 

On September 29, 2016, we repaid the Independent Bank debt in full, resulting in the extinguishment of Independent Bank’s security interest.

 

Convertible Notes

 

In a series of transactions from December 29, 2015 to May 6, 2016, we issued an aggregate of approximately $5.8 million Convertible Notes maturing on June 30, 2016 and April 1, 2017, at a conversion price of $5.00. In connection with the December 2015 and March 2016 financing transactions, we issued warrants to purchase an aggregate of approximately 1.7 million shares of common stock with an exercise price of $2.50 per share and in connection with the May 2016 transaction, we issued warrants to purchase an aggregate of approximately 625,000 shares of common stock with an exercise price of $0.10 per share. Subsequently, as an inducement to participate in the May Convertible Notes offering, warrants to purchase up to 620,000 shares of common stock issued between December 2015 and March 2016 were amended and restated to reduce the exercise price to $0.10. As such, we recorded in other expense an inducement expense of $1.72 million. The proceeds of $5.8 million from these financing transactions were used to pay a $2.0 million refundable deposit in connection with the Merger, to fund certain operating expenses of Brushy in an aggregate amount of $508,000, to fund approximately $1.3 million of interest payments to Heartland and to fund approximately $2.0 million in working capital and accounts payables.

 

 48 

 

 

In connection with the closing of the Merger, on June 23, 2016, we entered into a Conversion Agreement with certain holders of Convertible Notes in an aggregate principal amount of approximately $4.0 million (the “Note Conversion Agreement”). The terms of the Note Conversion Agreement provided that the Convertible Notes were automatically converted into common stock upon the closing of the Merger. Pursuant to the terms of the Note Conversion Agreement, in exchange for immediate conversion upon closing, the conversion price of the Convertible Notes was reduced to $1.10, which resulted in the issuance of 3,636,366 shares of common stock. The modification of such conversion rate resulted in a $3.4 million inducement charge recorded in other expense. Holders of these Convertible Notes waived and forfeited approximately $198,000 rights to receive accrued but unpaid interest.

 

On August 3, 2016, we entered into the first amendment to the Convertible Notes with the remaining holders of approximately $1.8 million of Convertible Notes. Pursuant to the first amendment: (i) the maturity date was changed to January 2, 2017, (ii) the conversion price was adjusted to $1.10 and (iii) the coupon rate was increased to 15% per annum. All accrued and unpaid interest on the Convertible Notes would have also been convertible in certain circumstances at the conversion price. Additionally, if the aggregate principal amount outstanding on the Convertible Notes was not either converted by the holder or repaid in full on or before the maturity date, we agreed to pay a 25% premium on the maturity date. We accounted for the reduction in the conversion price of remaining outstanding convertible notes as an inducement expense and recognized approximately $1.6 million in other income (expense). In exchange for the holders’ willingness to enter into the first amendment, we issued to the holders of additional warrants to purchase up to approximately 1.65 million shares of common stock. The warrants issued were valued using the following variables: (a) stock price of $1.15, (b) exercise price of $2.50, (c) contractual life of 3 years, (d) volatility of 203%, and (e) risk free rate of 0.76% for a total value of approximately $1.63 million. This amount was recorded as an inducement expense and an offset to additional paid-in capital.

 

On September 29, 2016, in connection with our entry into the Credit Agreement, the remaining holders of the Convertible Notes converted the outstanding principal amount of approximately $1.8 million and accrued and unpaid interest in an amount of approximately $138,000 into 1,772,456 shares of common stock.

 

Credit Agreement and Warrant Repricing

 

Credit Agreement

 

On September 29, 2016, we entered into the Credit Agreement which provides for a three-year senior secured term loan with initial commitments of $31 million in aggregate principal amount, of which $25 million was collected as of September 30, 2016 and the additional $6 million was collected as of November 11, 2016. The initial aggregate principal amount may be increased to a maximum principal amount of $50,000,000 at our request, but at the discretion of the Lenders, pursuant to an accordion advance provision in the Credit Agreement (the “Term Loan”).

 

As discussed above, in connection with our entry into the Credit Agreement, on September 29, 2016, we used part of the proceeds of the Term Loan to repay the balance of Brushy’s outstanding indebtedness with Independent Bank, resulting in the elimination of approximately $5.4 million in senior secured debt, including accrued interest, fees and expenses, and the extinguishment of Independent Bank’s security interest in the assets of the Initial Guarantors and of our guaranty to Independent Bank in full.

 

Funds borrowed under the Credit Agreement may be used by us to (i) fund drilling and development projects, (ii) purchase oil and gas assets and other acquisition targets, (iii) pay all costs and expenses arising in connection with the negotiation and execution of the Credit Agreement, and (iv) fund our general working capital needs.

 

In connection with our entry into the Credit Agreement, we paid advisory fees to KES 7 and TRW in an amount of $420,000 and $200,000, respectively and a commitment fee to each of the Lenders equal to 2.0% of their respective initial loan advances. As partial consideration given to the lenders, we also amended certain warrants issued in the Series B preferred stock offering held by the lenders during the third and fourth quarters of the year ended December 31, 2016, to purchase up to an aggregate amount of approximately 2,840,000 and 681,822 shares of common stock, respectively, such that the exercise price per share was lowered from $2.50 to $0.01 on such warrants. The portion repriced in the fourth quarter was due to certain delayed funding that occurred after the initial commitment. The number of warrants amended for each Lender was based on the amount of each Lender’s respective participation in the initial Term Loan relative to the amount invested in the June 2016 Series B Preferred Stock private placement. All of the amended warrants are immediately exercisable from the original issuance date, for a period of two years, subject to certain conditions. We accounted for the reduction in the conversion price as a deferred financing cost of $714,000 and will be amortized over the length of the loan.

 

 49 

 

 

The Term Loan bears interest at a rate of 6.0% per annum and matures on September 30, 2019. We have the right to prepay the Term Loan, in whole or in part, at any time at a prepayment premium equal to 6.0% of the amount repaid. Such prepayment premium must also be paid if the Term Loan is repaid prior to maturity as a result of a change in control. In certain situations, the Credit Agreement requires mandatory prepayments of the Term Loans at the request of the Lenders, including in the event of certain non-ordinary course asset sales, the incurrence of certain debt and our receipt of proceeds in connection with insurance claims.

 

The Credit Agreement contains certain customary representations and warranties and affirmative and negative covenants, including covenants relating to maintenance of books and records, financial reporting and notification, compliance with laws, maintenance of properties and insurance, and limitations on guaranties, investments, issuance of debt, lease obligations and capital expenditures. The Credit Agreement also provides for events of default, including failure to pay any principal or interest when due, failure to perform or observe covenants, cross-default on certain outstanding debt obligations, the failure of a Guarantor to comply with the provisions of its Guaranty, and bankruptcy or insolvency events. The amounts under the Credit Agreement could be accelerated and be due and payable upon an event of default.

 

Subsequent Events

 

Credit Agreement Drawdown

 

On February 7, 2017, pursuant to the terms of the Credit Agreement, we exercised the accordion advance feature, increasing the aggregate principal amount outstanding under the term loan from $31 million to $38.1 million. The total availability for borrowing remaining under the Credit Agreement is $11.9 million. We intend to use the proceeds to fund its drilling and development program, for working capital and for general corporate purposes.

 

As partial consideration, we also amended certain warrants issued in the June 2016 private placement held by the Lenders to purchase up to an aggregate amount of approximately 738,638 shares of common stock such that the exercise price per share was lowered from $2.50 to $0.01 on such warrants The number of warrants amended for each Lender was based on the amount of each Lender’s respective participation in the initial Term Loan relative to the amount invested in the June 2016 private placement. All of the amended warrants are immediately exercisable from the original issuance date, for a period of two years, subject to certain conditions.

 

March 2017 Private Placement

 

On February 28, 2017, we entered into a Securities Subscription Agreement (the “Subscription Agreement”) with certain institutional and accredited investors in connection with a private placement (the “March 2017 Private Placement”) to sell 5.2 million units, consisting of approximately 5.2 million shares of common stock and warrants to purchase approximately an additional 2.6 million shares of common stock for an aggregate purchase price of approximately $20] million. Each unit consists of one share of common stock and a warrant to purchase 0.50 shares of common stock (each, a “Unit”), at a price per unit of $3.85. Each warrant has an exercise price of $4.50 and may be subject to redemption by the Company, upon prior written notice, if the price of the Company’s common stock closes at or above $6.30 for twenty trading days during a consecutive thirty trading day period. The closing of the Offering is subject to the satisfaction of customary closing conditions.

 

We expect to use the net proceeds from the Offering to support our planned 2017 capital budget, and for general corporate purposes including working capital.

 

The securities to be sold in the private placement have not been registered under the Securities Act or any state securities laws and may not be offered or sold in the United States absent registration or an applicable exemption from registration. However, in conjunction with the closing of the March 2017 Private Placement, we have also entered into a registration rights agreement whereby we agreed to use our reasonable best efforts to register, on behalf of the investors, the shares of common stock underlying the Units and the shares of common stock underlying the warrants no later than April 1, 2017.

 

Our 2017 capital budget may require additional financing above the level of cash generated by our operations and proceeds from recent financing activities.  We can provide no assurance that additional financing would be available to us on acceptable terms, if at all. 

 

 50 

 

 

Off-Balance Sheet Arrangements

 

We do not have any off-balance sheet arrangements.

 

Critical Accounting Policies and Estimates

 

The preparation of our consolidated financial statements in conformity with generally accepted accounting principles in the United States (“US GAAP”) requires our management to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities at the date of our financial statements and the reported amounts of revenues and expenses during the reporting period. The following is a summary of the significant accounting policies and related estimates that affect our financial disclosures.

 

Critical accounting policies are defined as those significant accounting policies that are most critical to an understanding of a company’s financial condition and results of operation. We consider an accounting estimate or judgment to be critical if (i) it requires assumptions to be made that were uncertain at the time the estimate was made, and (ii) changes in the estimate or different estimates that could have been selected could have a material impact on our results of operations or financial condition.

 

Use of Estimates

 

The preparation of financial statements in conformity with US GAAP requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ significantly from those estimates. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment.

 

Our most significant financial estimates are associated with our estimated proved oil and gas reserves, assessments of impairment in the carrying value of undeveloped acreage and proven properties. There are also significant financial estimates associated with the valuation of our Common Stock, options and warrants, inducement transactions and estimated derivative liabilities.

 

Oil and Natural Gas Reserves

 

We follow the full cost method of accounting. All of our oil and gas properties are located within the United States, and therefore all costs related to the acquisition and development of oil and gas properties are capitalized into a single cost center referred to as a full cost pool. Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves. Under the full cost method of accounting, capitalized oil and gas property costs 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 gas reserves less the future cash outflows associated with the asset retirement obligations that have been accrued on the balance sheet plus the cost, or estimated fair value if lower, of unproved properties. Should capitalized costs exceed this ceiling, impairment would be recognized. Under the SEC rules, we prepared our oil and gas reserve estimates as of December 31, 2016, using the average, first-day-of-the-month price during the 12-month period ended December 31, 2016.

 

Estimating accumulations of gas and oil is complex and is not exact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of the quality and quantity of available data; the interpretation of that data, the accuracy of various mandated economic assumptions; and the judgment of the persons preparing the estimate.

 

We believe estimated reserve quantities and the related estimates of future net cash flows are among the most important estimates made by an exploration and production company such as ours because they affect the perceived value of our company, are used in comparative financial analysis ratios, and are used as the basis for the most significant accounting estimates in our financial statements, including the quarterly calculation of depletion, depreciation and impairment of our proved oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. We determine anticipated future cash inflows and future production and development costs by applying benchmark prices and costs, including transportation, quality and basis differentials, in effect at the end of each quarter to the estimated quantities of oil and natural gas remaining to be produced as of the end of that quarter. We reduce expected cash flows to present value using a discount rate that depends upon the purpose for which the reserve estimates will be used. For example, the standardized measure calculation requires us to apply a 10% discount rate. Although reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than those of established proved producing oil and natural gas properties, we make considerable effort to estimate our reserves, including through the use of independent reserves engineering consultants. We expect that quarterly reserve estimates will change in the future as additional information becomes available or as oil and natural gas prices and operating and capital costs change. We evaluate and estimate our oil and natural gas reserves as of December 31, and quarterly throughout the year. For purposes of depletion, depreciation, and impairment, we adjust reserve quantities at all quarterly periods for the estimated impact of acquisitions and dispositions. Changes in depletion, depreciation or impairment calculations caused by changes in reserve quantities or net cash flows are recorded in the period in which the reserves or net cash flow estimate changes.

 

 51 

 

 

Oil and Natural Gas Properties-Full Cost Method of Accounting

 

We use the full cost method of accounting whereby all costs related to the acquisition and development of oil and natural gas properties 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 and overhead charges directly related to acquisition and exploration activities.

 

Capitalized costs, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves as determined by independent petroleum engineers. For this purpose, we convert our petroleum products and reserves to a common unit of measurement.

 

Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. This undeveloped acreage is assessed quarterly to ascertain whether impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to the full cost pool and becomes subject to depletion calculations.

 

Proceeds from the sale of oil and natural gas properties are applied against capitalized costs, with no gain or loss recognized, unless the sale would alter the rate of depletion by more than 25%. Royalties paid, net of any tax credits received, are netted against oil and natural gas sales.

 

Under the full cost method of accounting, capitalized oil and natural gas property costs, less accumulated depletion and net of deferred 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, plus the cost, or estimated fair value if lower, of unproved properties. Should capitalized costs exceed this ceiling, we would recognize impairment.

 

Revenue Recognition

 

The Company recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller's price to the buyer is fixed or determinable and (iv) collectability is reasonably assured.

 

The Company uses the entitlements method of accounting for oil, NGLs and gas revenues. Sales proceeds in excess of the Company's entitlement are included in other liabilities and the Company's share of sales taken by others is included in other assets in the accompanying consolidated balance sheets. The Company had no material oil, NGL or gas entitlement assets or liabilities as of December 31, 2016 or 2015.

  

Recently Issued Accounting Pronouncements

 

For a discussion of recently adopted accounting standards and recent accounting standards not yet adopted, see “Note 1 – Summary of Significant Accounting Policies” to our consolidated financial statements in Item 8 of this Annual Report on Form 10-K.

 

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

 

Not applicable.

 

 52 

 

 

Item 8. Financial Statements and Supplementary Data

 

Our financial statements appear immediately after the signature page of this Annual Report on Form 10-K, which are incorporated herein by reference. See “Index to Financial Statements” included in this Annual Report on Form 10-K.

 

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

Not applicable

 

Item 9A. Controls and Procedures

 

Evaluation of Disclosure Controls and Procedures

 

As required by Rule 13a-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), at the end of the period we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2016 at the reasonable assurance level.

 

Changes in Internal Control over Financial Reporting

 

Management implemented internal audit activities to improve the Company’s governance and risk management based on assessment of systems and business processes. Management has conducted an assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2016. The assessment was based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 COSO Framework).

 

Management’s assessment sufficiently addresses the risks of misstatements in financial reporting including risk of fraud identified within key business processes. As a result, management has concluded that, as of December 31, 2016, the Company's internal control over financial reporting was effective and that the previously identified material weakness in the Company’s Form 10-K filed for the year ended December 31, 2015 has been fully remediated.

 

Remediation of Material Weakness in Internal Control

 

Continuing into the fourth quarter of 2016, a number of remedial actions were taken to address the previously existing material weaknesses. Management’s efforts included performing a top-down risk assessment to identify risk of financial misstatement and fraud risks related to key processes and activities, including identification of relevant assertions for each significant account and disclosure. Additional measures included:

 

1)Management identified the risk of fraud for significant accounts and disclosures.
2)Management identified key risks within each business process and implemented controls to address each risk.
3)Management conducted walkthroughs for key processes.
4)Management assessed operating effectiveness by performing test procedures on samples of transactions.

 

In addition, starting in 2016, management augmented and high-graded key staff with more experience and expertise, supplemented with outside consultants, to put into place an effective mechanism for monitoring our system of internal control.

 

Management’s Annual Report on Internal Control Over Financial Reporting

 

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed by or under the supervision of our Chief Executive Officer and Chief Financial Officer and effected by our Board of Directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external purposes in accordance with generally accepted accounting principles. Our management, with the participation of our Chief Executive Officer and Chief Financial Officer assessed the effectiveness of our internal control over financial reporting, as of December 31, 2016, based on the criteria for effective internal control over financial reporting established in “Internal Control - Integrated Framework (2013)” which is issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment and those criteria, our management determined that we maintained effective internal control over financial reporting as of December 31, 2016.

 

Item 9B. Other Information

 

None.

 

 53 

 

 

PART III

 

Item 10. Directors, Executive Officers and Corporate Governance

 

The following table sets forth the names, ages and positions of the persons who are our directors and executive officers as of March 1, 2016:

 

Name   Age   Position
Abraham “Avi” Mirman   47   Chief Executive Officer, Director
Ronald D. Ormand   58   Executive Chairman of the Board of Directors
Nuno Brandolini   63   Director
R. Glenn Dawson   60   Director
General Merrill McPeak   81   Director
Peter Benz   56   Director
Joseph C. Daches   50   Executive Vice President, Chief Financial Officer and Treasurer
Brennan Short   42   Chief Operating Officer
Ariella Fuchs   35   Executive Vice President, General Counsel and Secretary
Seth Blackwell   29   Executive Vice President of Land and Business Development  

 

Abraham Mirman: Chief Executive Officer, Director. Mr. Mirman joined our Board of Directors (the “Board” or the “Board of Directors”) on September 12, 2014. He currently serves as our Chief Executive Officer and has held that position since April 21, 2014. Prior to being appointed to his current position of Chief Executive Officer, Mr. Mirman served as our President beginning in September 2013. During that same time, from April 2013 until September 2014, Mr. Mirman served as the Managing Director, Investment Banking at T.R. Winston & Company, LLC (“TRW”). Between 2012 and February 2013, Mr. Mirman served as Head of Investment Banking at John Thomas Financial. From 2011 to 2012, Mr. Mirman served as Head of Investment Banking at BMA Securities. Lastly, from 2006 to 2011, Mr. Mirman served as Chairman of the Board of Cresta Capital Strategies LLC. During Mr. Mirman’s service as Chief Executive Officer, we have completed several significant capital raising transactions and negotiated a final settlement with its senior secured lender.

 

Director Qualifications:

 

·Leadership Experience - Chief Executive Officer of Lilis Energy, Inc.; Chairman of the Board of Cresta Capital Strategies LLC; Head of Investment Banking at BMA Securities; Head of Investment Banking at John Thomas Financial; Managing Director, Investment Banking at TRW.
·Industry Experience - Personal investment in oil and gas industry, and experience as executive officer of our company.

 

Ronald D. Ormand: Executive Chairman of the Board of Directors. Mr. Ormand joined Lilis’s Board of Directors in February, 2015, bringing with him more than 33 years of experience as a senior executive and investment banker in energy, including extensive financing and mergers and acquisitions expertise in the oil and gas industry. During his career, he has completed more than $25 billion of capital markets and financial advisory transactions, both as a principal and as a banker. Prior to joining Lilis, Mr. Ormand served as the Chairman and Head of the Investment Banking Group at MLV & Co. (“MLV”), which is now owned by FBR & Co., after it acquired MLV in September of 2015. After the acquisition, Mr. Ormand served as Senior Managing Director and Senior Advisor at FBR & Co. until May 2016, where he focused on investment banking and principal investments in the energy sector. Prior to joining MLV in November 2013, from 2009 to 2013, Mr. Ormand was a senior executive at Magnum Hunter Resources Corporation, or MHR (NYSE:MHR), an exploration and production company engaged in unconventional resource plays, as well as midstream and oilfield services operations. He was part of the management team that took over prior management and grew MHR from approximately $35 million enterprise value to over $2.5 billion enterprise value at the time he left in 2013. Mr. Ormand served on the Board of Directors and in several senior management positions for MHR, including Executive Vice President, Chief Financial Officer and Executive Vice President of Capital Markets. On March 10, 2016, in connection with his prior position as Chief Financial Officer of MHR, Mr. Ormand, without admitting or denying any of the allegations, settled with the SEC in connection with an investigation of MHR’s books and records and internal controls for financial reporting. Specifically, Mr. Ormand agreed to cease and desist from violating Sections 13(a) and 13(b)(2)(A) and (B) of the Exchange Act and Rules 13a-1, 13a-13 and 13-15(a) thereunder. He has also paid a penalty of $25,000. The SEC did not allege any anti-fraud violations, intentional misrepresentations or willful conduct on the part of Mr. Ormand. Mr. Ormand’s career includes serving as Managing Director and Group Head of U.S. Oil and Gas Investment Banking at CIBC World Markets and Oppenheimer (1988-2004); Head Of North American Oil and Gas Investment Banking at West LB A.G. (2005-2007), and President and CFO of Tremisis Energy Acquisition Corp. II, an energy special purpose acquisition company from 2007-2009. Mr. Ormand has previously served as a Director of Greenhunter Resources, Inc. (2011-2013), Tremisis (2007-2009), and Eureka Hunter Holdings, Inc., a private midstream company (2010-2013). Mr. Ormand holds a B.A. in Economics, an M.B.A. in Finance and Accounting from UCLA and studied Economics at Cambridge University, England.

 

 54 

 

 

Director Qualifications:

 

·Leadership Experience - Senior executive at Magnum Hunter Resources Corporation, Chairman and Head of Investment Banking at MLV and Head of US Oil and Gas for CIBC and investment banker.
·Industry Experience - Extensive experience in oil and gas development and services industries at the entities and in the capacities described above

 

Nuno Brandolini: Director. Mr. Brandolini joined our Board of Directors in February 2014, and became Chairman in April 2014. On January 13, 2016, Mr. Brandolini was replaced as Chairman of our Board of Directors by Ronald D. Ormand. Mr. Brandolini served as a member of the general partner of Scorpion Capital Partners, L.P., a private equity firm organized as a small business investment company until June 2014. Prior to forming Scorpion Capital and its predecessor firm, Scorpion Holding, Inc., in 1995, Mr. Brandolini served as managing director of Rosecliff, Inc., a leveraged buyout fund co-founded by Mr. Brandolini in 1993. Mr. Brandolini served previously as a vice president in the investment banking department of Salomon Brothers, Inc., and a principal with the Batheus Group and Logic Capital, two venture capital firms. Mr. Brandolini began his career as an investment banker with Lazard Freres & Co. Mr. Brandolini is a director of Cheniere Energy, Inc. (NYSE MKT: LNG), a Houston-based company primarily engaged in LNG related businesses. Mr. Brandolini received a law degree from the University of Paris and an M.B.A. from the Wharton School.

 

Director Qualifications:

 

·Leadership Experience - Executive positions with several private equity firms, and Board position with Cheniere Energy, Inc.
·Industry Experience - Service on the Board of Cheniere Energy, Inc., as well as personal investments in the oil and gas industry.

 

R. Glenn Dawson: Director. Mr. Dawson joined our Board of Directors on January 13, 2016. Mr. Dawson has over 30 years of experience in oil and gas exploration in North America and is currently President and Chief Executive Officer of Cuda Energy, Inc., a private Canadian-based exploration and production company. Mr. Dawson’s career includes serving as President of Bakken Hunter, a division of MHR, where he managed operations and development of Bakken assets in the United States and Canada, from 2011 to 2014. His principal responsibilities have involved the generation and evaluation of drilling prospects and production acquisition opportunities. In the early stages of his career, Mr. Dawson was employed as an exploration geologist by Sundance Oil and Gas, Inc., a public company located in Denver, Colorado, concentrating on their Canadian operations. From December 1985 to September 1998, Mr. Dawson held a variety of managerial and technical positions with Summit Resources, a then-public Canadian oil and gas exploration and production company, including Vice President of Exploration, Exploration Manager and Chief Geologist. He served as Vice President of Exploration with PanAtlas Energy Inc., a then-public Canadian oil and gas exploration and production company, from 1999 until its acquisition by Velvet Exploration Ltd. in July 2000. Mr. Dawson was a co-founder and Vice President of Exploration of TriLoch Resources Inc., a then-public Canadian oil and gas exploration company, from 2001 to 2005, until it was acquired by Enerplus Resources Fund. As a result of the sale of TriLoch Resources Inc. to Enerplus Resources Fund, Mr. Dawson founded NuLoch Resources, Inc. in 2005. Mr. Dawson graduated in 1980 from Weber State University of Utah with a Bachelor’s degree in Geology and attended the University of Calgary from 1980 to 1982 in the Masters Program for Geology. As a result of these professional experiences, Mr. Dawson possesses particular knowledge and experience in the operations of oil and gas companies that strengthen the Board’s collective qualifications, skills, and experience.

 

 55 

 

 

Director Qualifications:

 

·Leadership Experience - President and Chief Executive Officer of Cuda Energy, Inc.; former President of Bakken Hunter.
·Industry Experience - Extensive experience in oil and gas exploration industry; co-founded numerous oil and gas exploration companies.

 

General Merrill McPeak: Director. General McPeak joined our Board of Directors in January 2015. He served as the fourteenth chief of staff of the U.S. Air Force and flew 269 combat missions in Vietnam during his distinguished 37-year military career. Following retirement from active service in 1994, General McPeak launched a second career in business. He was a founding investor and chairman of Ethics Point, an ethics and compliance software and services company, which was subsequently restyled as industry leader Navex Global, and acquired in 2011 by a private equity firm. General McPeak co-invested and remained a board member of Nava Global, which was sold again in 2014. From 2012 to 2014, General McPeak was Chairman of Coast Plating, Inc., a Los Angeles-based, privately held provider of metal processing and finishing services, primarily to the aerospace industry, which was also acquired in a private equity buyout. He remains a director of that company, now called Valence Surface Technologies. He also currently serves as a director of Aerojet Rocketdyne, Lion Biotechnologies and Research Solutions, Inc. Formerly, he was a director of Tektronix, TWA and ECC International, a defense subcontractor, where he served for many years as chairman of the Board. Since 2010, General McPeak has been Chairman of the American Battle Monuments Commission, an agency of the executive branch of the federal government, responsible for operating and maintaining American cemeteries in foreign countries holding the remains of 125,000 US servicemen. General McPeak has a B.A. degree in Economics from San Diego State College and an M.S. in International Relations from George Washington University. He is a graduate of the National War College and of the Executive Development Program of the University of Michigan Graduate School of Business. He spent an academic year as Military Fellow at the Council on Foreign Relations

 

Director Qualifications:

 

·Leadership Experience - Chief of Staff of the U.S. Air Force; Founding investor and chairman of Ethicspoint (subsequently Navex Global).
·Industry Experience - Personal investments in the oil and gas industry.

 

Peter Benz: Director. Mr. Benz joined our Board of Directors on June 23, 2016 in connection with the completion of the merger with Brushy. Prior to that, Mr. Benz had served on Brushy’s Board of Directors since January 20, 2012. Mr. Benz serves as the Chairman and Chief Executive Officer of Viking Asset Management, LLC and is a member of its Investment Committee. He has been affiliated with Viking Asset Management, LLC since 2001. His responsibilities include assuring a steady flow of candidate deals, making asset allocation and risk management decisions and overseeing all business and investment operations. He has more than 25 years of experience specializing in investment banking and corporate advisory services for small growth companies in the areas of financing, merger/acquisition, funding strategy and general corporate development. Prior to founding Viking in 2001, Mr. Benz founded Bi Coastal Consulting Company where he advised hundreds of companies regarding private placements, initial public offerings, secondary public offerings and acquisitions. He has founded three public companies and served as a director for four other public companies. Prior to founding Bi Coastal Consulting, Mr. Benz was responsible for private placements and investment banking activities at Gilford Securities in New York, NY. Mr. Benz became a director of usell.com, Inc. on May 15, 2014. Mr. Benz is a graduate of Notre Dame University. As a result of these professional experiences, Mr. Benz possesses particular knowledge and experience in developing companies and capital markets that strengthen the board of director’s collective qualifications, skills, and experience.

 

Director Qualifications:

 

·Leadership Experience –Chairman and CEO of Viking Asset Management; founded three public companies.

 

 56 

 

 

·Industry Experience –Extensive experience in the investment banking and corporate advisory services industries; founded Bi Coastal Consulting, a consulting company advising companies regarding private placements, initial public offerings, secondary public offerings and acquisitions.

 

Joseph C. Daches: Executive Vice President, Chief Financial Officer and Treasurer. On January 23, 2017, our Board appointed Joseph Daches to the position of Executive Vice President, Chief Financial Officer and Treasurer, effective immediately. Prior to joining our company, Mr. Daches most recently held the position of Chief Financial Officer and Senior Vice President of Magnum Hunter Resources Corp. (“MHR”) from July 2013 to June 2016, where he finished his tenure by successfully guiding MHR through a restructuring, and upon emergence was appointed Co-CEO by MHR’s new board of directors until his departure. Mr. Daches has over 20 years of experience and expertise in directing strategy, accounting and finance in primarily small and mid-size oil and gas companies and has helped guide several of those companies through financial strategy, capital raises and private and public offerings. Prior to joining MHR, Mr. Daches served as Executive Vice President, Chief Accounting Officer and Treasurer of Energy & Exploration Partners, Inc. from September 2012 until June 2013 and as a director of that company from April 2013 through June 2013. He previously served as a partner and Managing Director of the Willis Consulting Group, LLC, from January 2012 to September 2012. From October 2003 to December 2011, Mr. Daches served as the Director of E&P Advisory Services at Sirius Solutions, LLC, where he was primarily responsible for financial reporting, technical and oil and gas accounting and the overall management of the E&P Advisory Services practice. Mr. Daches earned a Bachelor of Science in Accounting from Wilkes University in Pennsylvania, and he is a certified public accountant in good standing with the Texas State Board of Public Accountancy.

 

Brennan Short: Chief Operating Officer. On January 27, 2017, our Board appointed Brennan Short to the position of Chief Operating Officer, effective immediately. Mr. Short most recently held the position of President at MMZ Consulting Inc. from May 2012 to January 2017, where he provided full cycle drilling & completions engineering and operational support to multiple clients. Mr. Short has over 20 years of proven expertise in domestic oil & gas exploration and production operations, field supervision, management and petroleum engineering consulting. Prior to forming MMZ Consulting Inc., Mr. Short held the position of Drilling Engineering Specialist at EOG Resources, Inc. from March 2010 to May 2012, where he was a drilling engineer in the infancy of the Eagleford Shale Play in South Texas. Previous to his role EOG Resources, Inc., Mr. Short was a Drilling Engineer at SM Energy from November 2007 to March 2010 and a Drilling Engineer at Samson Investment Company from March 2005 to November 2007. Mr. Short earned his Bachelor’s degree in Petroleum Engineering from Texas A&M University.

 

Ariella Fuchs: Executive Vice President, General Counsel and Secretary. Ariella Fuchs joined our company in March 2015. Prior to that, Ms. Fuchs was an associate with Baker Botts L.L.P. from April 2013 to February 2015, specializing in securities transactions and corporate governance. Prior to joining Baker Botts L.L.P, she served as an associate at White & Case LLP and Dewey and LeBoeuf LLP from January 2010 to March 2013 in their mergers and acquisitions groups. Ms. Fuchs received a J.D. from New York Law School and a B.A. in Political Science from Tufts University.

 

Seth Blackwell: Executive Vice President of Land and Business Development. Seth Blackwell joined our company in December 2016. Mr. Blackwell is a Professional Landman with extensive knowledge and experience in all facets of land management. Prior to joining our company, Mr. Blackwell held the position of Vice President of Land for XOG Resources where he managed all land and business development efforts for the company. Mr. Blackwell also gained extensive experience in a wide variety of major US oil and gas plays while working for Occidental Petroleum. Mr. Blackwell started his career blocking together large acreage positions in excess of 30,000 acres throughout Central and East Texas. Mr. Blackwell is an active member of the American Association of Professional Landman, North Houston Association of Professional Landman and the Houston Association of Professional Landman. Mr. Blackwell holds a bachelor’s degree in Business Management from Fort Hays State University and is currently pursuing his MBA in Energy from the University of Tulsa.

 

Directors hold office for a period of one year from their election at the annual meeting of stockholders and until a particular director’s successor is duly elected and qualified. Officers are elected by, and serve at the discretion of, our Board of Directors. None of the above individuals has any family relationship with any other. It is expected that our Board of Directors will elect officers annually following each annual meeting of stockholders.

 

 57 

 

 

Section 16(a) Beneficial Ownership Reporting Compliance

 

Our executive officers and directors and persons who own more than 10% of our common stock are required to file reports with the SEC, disclosing the amount and nature of their beneficial ownership in our common stock, as well as changes in that ownership. Based solely on our review of reports and written representations that we have received, we believe that all required reports were timely filed during 2016 and through the date of this report, except as follows:

 

·Kevin Nanke filed one Form 4, reporting one transaction late.
·R. Glenn Dawson filed one Form 4 reporting one transaction late. After the reporting period, Mr. Dawson filed one Form 4 reporting one transaction late.
·Sean O-Sullivan Revocable Living Trust (the “SOS Trust”) filed one Form 3 late, as well as an amendment to such Form 3 reporting his initial beneficial ownership late. The SOS Trust filed three Form 4s reporting eight transactions late, as well as an amendment to one of the late Form 4s, reporting an additional two transactions late.
·SOSVentures LLC filed one Form 3 late.
·Ronald D. Ormand filed one Form 4 amendment reporting two transactions late.
·Peter Benz filed one Form 4 amendment reporting one transaction late.
·Joseph C. Daches filed one Form 3 reporting his initial beneficial ownership late.

 

The Board of Directors and Committees Thereof

 

Our Board of Directors conducts its business through meetings and through its committees. Our Board of Directors held ten meetings in 2016 and took action by unanimous written consent on nine occasions. Each director attended at least 75% of (i) the meetings of the Board held after such director’s appointment and (ii) the meetings of the committees on which such director served, after being appointed to such committee. Our policy regarding directors’ attendance at the annual meetings of stockholders is that all directors are expected to attend, absent extenuating circumstances.

 

Affirmative Determinations Regarding Director Independence and Other Matters

 

Our Board of Directors follows the standards of independence established under the rules of the Nasdaq Stock Market, or the Nasdaq, as well as our Corporate Governance Guidelines on Director Independence, which was amended on December 10, 2015, a copy of which is available on our website at www.lilisenergy.com under “Investors-Corporate Governance-Highlights” in determining if directors are independent. The Board has determined that four of our current directors, Mr. Brandolini, General McPeak, Mr. Benz and Mr. Dawson are “independent directors” under the Nasdaq rules referenced above.

 

No independent director receives, or has received, any fees or compensation directly as an individual from us other than compensation received in his or her capacity as a director or indirectly through their respective companies, except as described below. See “Certain Relationships and Related Transactions, and Director Independence”. There were no transactions, relationships or arrangements not otherwise disclosed that were considered by the Board of Directors in determining whether any of the directors were independent.

 

Committees of the Board of Directors

 

Pursuant to our amended and restated bylaws, our Board of Directors is permitted to establish committees from time to time as it deems appropriate. To facilitate independent director review and to make the most effective use of our directors’ time and capabilities, our Board of Directors has established an audit committee, a compensation committee and a nominating and corporate governance committee. The membership and function of these committees are described below.

 

 58 

 

 

Audit Committee

 

During the year ended December 31, 2016, each of Mr. Brandolini, General McPeak, Mr. Dawson and Mr. Benz served on the audit committee. Currently, the audit committee consists of Mr. Benz, Mr. Brandolini and General McPeak. Mr. Benz is the acting as chairman of the audit committee and meets the definition of an audit committee financial expert. Our Board of Directors determined that each of Mr. Brandolini, General McPeak, Mr. Dawson and Mr. Benz were independent as required by Nasdaq for audit committee members.

 

The audit committee met four times during the year ended December 31, 2016, but met separately on several occasions in connection with a meeting of the full Board of Directors. The audit committee is governed by a written charter that is reviewed, and amended if necessary, on an annual basis. A copy of the charter is available on our website at www.lilisenergy.com under “Investors-Corporate Governance-Highlights.”

 

Compensation Committee

 

Our compensation committee currently consists of Mr. Brandolini, General McPeak and Mr. Dawson. Mr. Ormand had also served on the compensation committee, but resigned following a determination that he should not be considered independent and eligible for compensation committee service based on the above-described compensation paid to his investment bank. General McPeak is the chairman of the compensation committee.

 

The compensation committee met six times during the year ended December 31, 2016, and acted by written consent twice. The compensation committee has also met separately on several occasions in connection with a meeting of the full Board. The Board determined that each of Mr. Brandolini, General McPeak and Mr. Dawson were independent as required by Nasdaq for compensation committee members.

 

The compensation committee reviews, approves and modifies our executive compensation programs, plans and awards provided to our directors, executive officers and key associates. The compensation committee also reviews and approves short-term and long-term incentive plans and other stock or stock-based incentive plans. In addition, the committee reviews our compensation and benefit philosophy, plans and programs on an as-needed basis. In reviewing our compensation and benefits policies, the compensation committee may consider the recruitment, development, promotion, retention, compensation of our executive and senior officers, trends in management compensation and any other factors that it deems appropriate. Under its charter, the compensation committee may create and delegate such tasks to such standing or ad hoc subcommittees as it may determine to be necessary or appropriate for the discharge of its responsibilities, as long as the subcommittee has at least the minimum number of directors necessary to meet any regulatory requirements. The compensation committee may engage consultants in determining or recommending the amount of compensation paid to our directors and executive officers. The compensation committee is governed by a written charter that is reviewed, and amended if necessary, on an annual basis. A copy of the charter is available on our website at www.lilisenergy.com under “Investors-Corporate Governance-Highlights.”

 

Nominating and Corporate Governance Committee

 

Our nominating and corporate governance committee currently consists of Mr. Benz, General McPeak and Mr. Brandolini, who is the chairman of the nominating and corporate governance committee. The nominating and corporate governance committee met once during the year ended December 31, 2016, but met separately on several occasions in connection with a meeting of the full Board.

 

The primary responsibilities of the nominating and corporate governance committee include identifying, evaluating and recommending, for the approval of the entire Board of Directors, potential candidates to become members of the Board of Directors, recommending membership on standing committees of the Board of Directors, developing and recommending to the entire Board of Directors corporate governance principles and practices for our company and assisting in the implementation of such policies, and assisting in the identification, evaluation and recommendation of potential candidates to become officers of our company. The nominating and corporate governance committee will review our code of business conduct and ethics and its enforcement, and reviews and recommends to our Board of Directors whether waivers should be made with respect to such code. A copy of the nominating and corporate governance committee charter may be found on our website at www.lilisenergy.com under “Investor Relations-Corporate Governance-Highlights.” During fiscal year 2016, there have been no material changes to the procedures by which security holders may recommend nominees to our Board of Directors.

 

 59 

 

 

Communications with the Board of Directors

 

Stockholders may communicate with our Board of Directors or any of the directors by sending written communications addressed to the Board of Directors or any of the directors, Lilis Energy, Inc., 300 E. Sonterra Blvd., Suite No. 1220, San Antonio, Texas 78258, Attention: General Counsel. All communications are compiled by the general counsel and forwarded to the Board of Directors or the individual director(s) accordingly.

 

Code of Ethics

 

Our Board of Directors has adopted a code of business conduct and ethics, which we refer to as the Code, that applies to all of our officers and employees, including our chief executive officer, chief financial officer or controller, and persons performing similar functions. Our code of business conduct and ethics codifies the business and ethical principles that govern all aspects of our business. A copy of our code of business conduct and ethics is available on our website at www.lilisenergy.com under “Investors-Corporate Governance-Highlights.” We undertake to provide a copy of our code of business conduct and ethics to any person, at no charge, upon a written request. All written requests should be directed to: Lilis Energy, Inc., 300 E. Sonterra Blvd., Suite No. 1220, San Antonio, Texas 78258, Attention: General Counsel. If any substantive amendments are made to our code of business conduct and ethics, or if any waiver (including any implicit waiver) is granted from any provision of the code of business conduct and ethics to our chief executive officer, chief financial officer or controller, we will disclose the nature of such amendment or waiver on our website at www.lilisenergy.com under “Investors-Corporate Governance-Highlights.” or, if required, in a Current Report on Form 8-K.

 

Item 11. Executive Compensation

 

Executive Compensation for Fiscal Year 2016

 

The compensation earned by our executive officers for the year ending December 31, 2016 consisted of base salary, short-term incentive compensation consisting of cash payments and long-term incentive compensation consisting of awards of stock grants. All share and per share amounts, fair values per share and exercise prices that appear in this section have been adjusted to reflect the 1-for-10 reverse stock split of our outstanding common stock effected on June 23, 2016.

 

Summary Compensation Table

 

The table below sets forth compensation paid to our named executive officers (NEOs) for the years ending December 31, 2016 and 2015.

 

Name and Principal
Position
  Year  Salary
($)
   Bonus
($)
   Stock
Awards
($)(1)
   Option
Awards
($)(2)
   All Other
Compensation
($)(3)
   Total
($)
 
Abraham “Avi” Mirman  2016   350,000    175,000(4)       4,295,894    22,484    4,843,378 
(Chief Executive Officer)  2015   325,466    100,000(5)   90,000    1,397,721    31,504    1,944,691 
                                  
Ronald D. Ormand(6)  2016   150,000        1,875,000    533,092    69,502    2,627,594 
(Chairman of the Board of Directors)                                 
                                  
Ariella Fuchs  2016   240,000    112,500(4)       1,288,768    8,417    1,649,685 
(General Counsel and Secretary)  2015   182,083        48,000    234,887    10,538    475,508 

 

 60 

 

 

(1)Represents restricted stock awards. The grant date fair values for restricted stock awards were computed in accordance with FASB ASC Topic 718. The amounts reported in this column reflect the accounting cost for the stock awards and do not necessarily correspond to the actual economic value that may be received for the stock awards.
(2)Awards in this column are reported at grant date fair value, if awarded in the period, and any incremental fair value, if modified in the period, in each case in accordance with FASB ASC Topic 718. Mr. Mirman was granted 1,250,000 options on each of June 24, 2016 and December 15, 2016; Mr. Ormand was granted 250,000 options on December 15, 2016; and Ms. Fuchs was granted 375,000 options on each of June 24, 2016 and December 15, 2016. The grant date fair values for options granted on June 24, 2016 and December 15, 2016 were $1.30 (rounded) and $2.13 (rounded), respectively. For both Mr. Mirman and Ms. Fuchs, their options granted June 24, 2016 were modified December 15, 2016 to provide for accelerated exercisability upon an involuntary employment termination and upon a change in control, and for extension of the post-termination exercise period upon an employment termination other than for cause. However, there was no incremental fair value for those modified options. The amounts reported in this column reflect the accounting cost for the options and do not correspond to the actual economic value that may be received for the options. The assumptions used to calculate the fair value of options are set forth in the notes to our consolidated financial statements included in this Annual Report on Form 10-K.
(3)For 2016, reflects reimbursement of health insurance premiums for all of the NEOs. For Mr. Ormand, the amount also reflects $55,000 in director fees paid to him for his Board service in 2016 prior to the time he became an officer.
(4)Reflects a bonus payable under the officer’s employment agreement for the successful completion of the Brushy merger.
(5)Reflects a sign-on bonus.
(6)Effective July 11, 2016, Mr. Ormand began to serve as Executive Chairman of the Board, which is an officer position. Prior to July 11, 2016, Mr. Ormand was a nonemployee director of the Board and his compensation from January 1 to July 10, 2016 is reflected under All Other Compensation.

 

Outstanding Equity Awards at Fiscal Year-End

 

   Option Awards  Stock Awards 
Name  Number of
Securities
Underlying
Unexercised
Options
(#)
Exercisable
   Number of
Securities
Underlying
Unexercised
Options
(#)
Unexercisable
  

Option
Exercise
Price

($)

   Option
Expiration
Date
  Number of
Shares or
Units of
Stock That
Have Not
Vested
(#)
   Market
Value of
Shares or
Units of
Stock That
Have Not
Vested
($)
 
                        
Abraham “Avi” Mirman   170,000    330,000(1)   2.98   12/15/2026        
    425,000    825,000(2)   1.34   6/24/2026        
    60,000        21.10   9/16/2023        
Ronald D. Ormand   85,000    165,000(1)   2.98   12/15/2026   833,333(3)   2,583,332 
    31,666    13,334(4)   16.50   4/20/2025        
Ariella Fuchs   127,500    247,500(1)   2.98   12/15/2026        
    127,500    247,500(2)   1.34   6/24/2026        

 

(1)Options vest in equal installments on each of December 15, 2017 and 2018, subject to acceleration provisions and continued service
(2)Options vest in equal installments on each of June 24, 2017 and 2018, subject to acceleration provisions and continued service.
(3)Restricted shares vest in equal installments on each of July 7, 2017 and July 7, 2018, subject to acceleration provisions and continued service.
(4)Options vest in equal installments on each of April 20, 2017 and 2018, subject to acceleration provisions and continued service.

 

 61 

 

 

Employment Agreements and Other Compensation Arrangements

 

2012 Equity Incentive Plan (“2012 EIP”) (formerly the Recovery Energy, Inc. 2012 Equity Incentive Plan)

 

Our Board and stockholders approved our 2012 EIP in August 2012. The 2012 EIP provided for grants of equity incentives to: attract, motivate and retain the best available personnel for positions of substantial responsibility; provide additional incentives to our employees, directors and consultants; and promote the success and growth of our business. Equity incentives that were available for grant under our 2012 EIP included stock options, stock appreciation rights (SARs), restricted stock awards, restricted stock units (RSUs), and unrestricted stock awards.

 

Our 2012 EIP is administered by our compensation committee, subject to the ultimate authority of our Board, which has full power and authority to take all actions and to make all determinations required or provided for under the 2012 EIP.

 

Under our 2012 EIP, 1,000,000 shares of our common stock were available for issuance. As a result of the adoption of our 2016 Plan, awards are no longer made under the 2012 EIP, as discussed below.

 

2016 Omnibus Incentive Plan (“2016 Plan”)

 

Background

 

Our 2016 Plan was approved by our Board effective April 20, 2016 and approved by our stockholders at their 2016 annual meeting on May 23, 2016. Our 2016 Plan replaced our 2012 EIP.

 

The purposes of our 2016 Plan are to create incentives that are designed to motivate eligible directors, officers, employees and consultants to put forth maximum effort toward our success and growth, and to enable us to attract and retain experienced individuals who by their position, ability and diligence are able to make important contributions to our success.

 

Eligibility

 

Awards may be granted under our 2016 Plan to officers, employees, directors, consultants and advisors of the Company and its affiliates. Tax-qualified incentive stock options may be granted only to employees of the Company or its subsidiaries.

 

Administration

 

Our 2016 Plan may be administered by our Board or its compensation committee. Our compensation committee, in its discretion, generally selects the individuals to whom awards may be granted, the time or times at which awards are granted and the terms and conditions of awards.

 

Number of Authorized Shares

 

When initially approved by our stockholders, 50,000,000 shares of our common stock were made available for issuance under our 2016 Plan. As a result of our 1-for-10 reverse stock split, which took effect on June 23, 2016, the number of shares available for issuance under our 2016 Plan was automatically reduced to 5,000,000. On August 25, 2016, our Board approved an amendment to our 2016 Plan to increase the maximum number of shares that may be issued from 5,000,000 to 10,000,000, and our stockholders approved that amendment at a special meeting on November 3, 2016.

 

 62 

 

 

In addition, as of May 23, 2016, any awards then outstanding under our 2012 EIP remain subject to and will be paid under the 2012 EIP and any shares then subject to outstanding awards under the 2012 EIP that subsequently expire, terminate or are surrendered or forfeited for any reason without issuance of shares will automatically become available for issuance under our 2016 Plan. Up to 5,000,000 shares may be granted as tax-qualified incentive stock options under our 2016 Plan. The shares issuable under our 2016 Plan will consist of authorized and unissued shares, treasury shares or shares purchased on the open market or otherwise.

 

If any award is canceled, terminates, expires or lapses for any reason prior to the issuance of shares or if shares are issued under our 2016 Plan and thereafter are forfeited to the Company, the shares subject to those awards and the forfeited shares will not count against the aggregate number of shares available for grant under the plan. In addition, the following items will not count against the aggregate number of shares available for grant under our 2016 Plan: (1) the payment in cash of dividends or dividend equivalents under any outstanding award, (2) any award that is settled in cash rather than by issuance of shares, (3) shares surrendered or tendered in payment of the option price or purchase price of an award or any taxes required to be withheld in respect of an award or (4) awards granted in assumption of or in substitution for awards previously granted by an acquired company.

 

Limits on Awards to Nonemployee Directors

 

The maximum number of shares subject to awards under our 2016 Plan granted during any calendar year to any nonemployee member of our Board, taken together with any cash fees paid to the director during the fiscal year, may not exceed $500,000 in total value (calculating the value of any such awards based on the grant date fair value of such awards for financial reporting purposes).

 

Types of Awards

 

Our 2016 Plan permits the granting of any or all of the following types of awards: stock options, which entitle the holder to purchase a specified number of shares at a specified price; SARs, which, upon exercise, entitle the holder to receive payment per share in stock or cash equal to the excess of the share’s fair market value on the date of exercise over the grant price of the SAR; restricted stock, which are shares of common stock subject to specified restrictions; RSUs, which represent the right to receive shares of our common stock in the future; other types of equity or equity-based awards; and performance awards, which entitle participants to receive a payment from the Company, the amount of which is based on the attainment of performance goals established by the compensation committee over a specified award period.

 

No Repricing

 

Without shareholder approval, our compensation committee is not authorized to (1) lower the exercise or grant price of a stock option or SAR after it is granted, except in connection with certain adjustments to our corporate or capital structure permitted by our 2016 Plan, such as stock splits, (2) take any other action that is treated as a repricing under generally accepted accounting principles or (3) cancel a stock option or SAR at a time when its exercise or grant price exceeds the fair market value of the underlying stock, in exchange for cash, another stock option or SAR, restricted stock, RSUs or other equity award, unless the cancellation and exchange occur in connection with a change in capitalization or other similar change.

 

Clawback

 

All awards granted under our 2016 Plan will be subject to all applicable laws regarding the recovery of erroneously awarded compensation, any implementing rules and regulations under such laws, any policies we adopt to implement such requirements and any other compensation recovery policies as we may adopt from time to time.

 

Transferability

 

2016 Plan awards are not transferable other than by will or the laws of descent and distribution, except that in certain instances transfers may be made to or for the benefit of designated family members of the participant for no value.

 

 63 

 

 

Effect of Change in Control

 

Under our 2016 Plan, in the event of a change in control, outstanding awards will be treated in accordance with the applicable transaction agreement. If no treatment is provided for in the transaction agreement, each award holder will be entitled to receive the same consideration that stockholders receive in the change in control for each share of stock subject to the award holder’s awards, upon the exercise, payment or transfer of the awards, but the awards will remain subject to the same terms, conditions and performance criteria applicable to the awards before the change in control, unless otherwise determined by our compensation committee. In connection with a change in control, outstanding stock options and SARs can be cancelled in exchange for the excess of the per share consideration paid to stockholders in the transaction, minus the applicable exercise price.

 

Subject to the terms and conditions of the applicable award agreement, awards granted to nonemployee directors will fully vest upon a change in control.

 

Subject to the terms and conditions of the applicable award agreement, for awards granted to all other service providers, vesting of awards will depend on whether the awards are assumed, converted or replaced by the resulting entity.

 

·For awards that are not assumed, converted or replaced, the awards will vest upon the change in control. For performance awards, the amount vesting will be based on the greater of (1) achievement of all performance goals at the “target” level or (2) the actual level of achievement of performance goals as of our fiscal quarter end preceding the change in control, and will be prorated based on the portion of the performance period that had been completed through the date of the change in control.

 

·For awards that are assumed, converted or replaced by the resulting entity, no automatic vesting will occur upon the change in control. Instead, the awards, as adjusted in connection with the transaction, will continue to vest in accordance with their terms and conditions. In addition, the awards will vest if the award recipient has a separation from service within two years after a change in control other than for cause or by the award recipient for good reason. For performance awards, the amount vesting will be based on the greater of (1) achievement of all performance goals at the “target” level or (2) the actual level of achievement of performance goals as of fiscal quarter end preceding the change in control, and will be prorated based on the portion of the performance period that had been completed through the date of the separation from service.

 

Term, Termination and Amendment of 2016 Plan

 

Unless earlier terminated by our Board, our 2016 Plan will terminate, and no further awards may be granted, 10 years after the date on which it is approved by stockholders. Our Board may amend, suspend or terminate our 2016 Plan at any time, except that, if required by applicable law, regulation or stock exchange rule, stockholder approval will be required for any amendment. The amendment, suspension or termination of our 2016 Plan or the amendment of an outstanding award generally may not, without a participant’s consent, materially impair the participant’s rights under an outstanding award.

 

Equity Grants for Fiscal Year 2016

 

During our year ended December 31, 2016, we granted 1,780,052 shares of restricted common stock and 5,683,500 options to purchase shares of common stock to employees and directors. Also during the year ended December 31, 2016, our employees forfeited and we cancelled 335,000 stock options previously issued in connection with the termination of certain employees and directors. As a result, as of December 31, 2016, the Company had 1,068,305 restricted shares of common stock and 5,956,833 options to purchase shares of common stock outstanding to employees and directors. Options issued to employees and directors generally vest in equal installments over specified time periods during the service period or upon achievement of certain performance based operating thresholds.

 

 64 

 

 

Employment Agreements

 

Mr. Mirman

 

Effective as of March 30, 2015, we entered into an amended and restated employment agreement with Mr. Mirman, which replaced his prior employment agreement. The agreement had a three-year term and provided for a $100,000 cash bonus due upon signing, base compensation of $350,000 per year, and 200,000 stock options, where one-third of the options vested immediately and two-thirds were scheduled to vest in two annual installments on each of the next two anniversaries of the grant date. The agreement also provided for additional bonuses due based on our achievement of certain performance measures.

 

On July 5, 2016, we entered into a new employment agreement with Mr. Mirman under which he will serve as our CEO. This agreement became effective June 24, 2016 upon the closing of our merger with Brushy. The initial term of the agreement is scheduled to end on December 31, 2017, and the agreement will renew automatically for additional one-year periods beginning on December 31, 2017, unless either party gives notice of non-renewal at least 180 days before the end of the then-current term. The agreement replaces in its entirety Mr. Mirman’s prior employment agreement with the Company.

 

Mr. Mirman’s base salary (which will be reviewed by the Board for adjustments) is $350,000 for the first year of the agreement, $375,000 for the second year of the agreement, and $425,000 for the third year of the agreement. Mr. Mirman was entitled to a bonus under the agreement equal to $175,000, payable in cash on the first regular payroll date of the Company following June 24, 2016 (the closing date of the merger with Brushy). Mr. Mirman will also be eligible to receive a cash bonus equal to a percentage of his base salary (ranging from 0% to 400%) depending on the level of achievement of certain BOE per day, EBITDAX and cash on hand performance measures. Mr. Mirman will also be eligible to receive awards of equity and non-equity compensation and to participate in our annual and long-term incentive plans, in each case as determined by our Board in its discretion. On June 24, 2016, Mr. Mirman received a grant of 1,250,000 stock options under our 2016 Plan, with an exercise price of $1.34. This grant is scheduled to vest over two years, with 34% vesting on the grant date, 33% vesting on the first anniversary of the grant date and 33% vesting on the second anniversary of the grant date, subject to continued service through each vesting date.

 

Under his employment agreement, Mr. Mirman will be entitled to a lump sum severance payment equal to 12 months of base salary and 12 months of COBRA premiums upon a termination by us without cause or a termination by him for good reason. Upon a termination by us without cause or a termination by Mr. Mirman for good reason within 12 months following a change in control, he will be entitled to a lump sum severance payment equal to 24 months of base salary and 24 months of COBRA premiums. Upon a termination due to disability, Mr. Mirman will be entitled to a lump sum severance payment equal to six months of COBRA premiums. All severance payments under Mr. Mirman’s employment agreement are subject to his execution and non-revocation of a release of claims against us. The severance payments are also subject to reduction in order to avoid an excise tax associated with Section 280G of the Internal Revenue Code, but only if that reduction would result in Mr. Mirman receiving a greater net after tax benefit as a result of the reduction.

 

All payments to Mr. Mirman under his employment agreement will be subject to clawback in the event required by applicable law. Further, Mr. Mirman is subject to non-competition, non-solicitation, anti-raiding and confidentiality provisions under his employment agreement.

 

Mr. Ormand

 

On July 5, 2016, we entered into an employment agreement with Ronald D. Ormand, effective as of July 11, 2016, under which he will serve as our Executive Chairman. The initial term of the agreement is scheduled to end on December 31, 2017, and the agreement will renew automatically for additional one-year periods beginning on December 31, 2017, unless either party gives notice of non-renewal at least 180 days before the end of the then-current term.

 

 65 

 

 

Mr. Ormand’s base salary (which will be reviewed by the Board for adjustments) is $300,000 for the first year of the agreement, $350,000 for the second year of the agreement, and $400,000 for the third year of the agreement. Mr. Ormand will be eligible to receive a cash bonus equal to a percentage of his base salary (ranging from 0% to 400%) depending on the level of achievement of certain BOE per day, EBITDAX and cash on hand performance measures. Mr. Ormand will also be eligible to receive awards of equity and non-equity compensation and to participate in our annual and long-term incentive plans, in each case as determined by our Board in its discretion. On July 7, 2016, Mr. Ormand received a grant of restricted stock under our 2016 Plan for 1.25 million shares of common stock. The restricted stock vests over two years, with 34% vesting on the date of the grant, 33% vesting on the first anniversary of the date of the grant and 33% vesting on the second anniversary of the date of the grant, subject to continued service through each vesting date.

 

Under his employment agreement, Mr. Ormand will be entitled to a lump sum severance payment equal to 12 months of base salary and 12 months of COBRA premiums upon a termination by us without cause or a termination by him for good reason. Upon a termination by us without cause or a termination by Mr. Ormand for good reason within 12 months following a change in control, he will be entitled to a lump sum severance payment equal to 24 months of base salary and 24 months of COBRA premiums. Upon a termination due to disability, Mr. Ormand will be entitled to a lump sum severance payment equal to six months of COBRA premiums. All severance payments under Mr. Ormand’s employment agreement are subject to his execution and non-revocation of a release of claims against us. The severance payments are also subject to reduction in order to avoid an excise tax associated with Section 280G of the Internal Revenue Code, but only if that reduction would result in Mr. Ormand receiving a greater net after tax benefit as a result of the reduction.

 

All payments to Mr. Ormand under his employment agreement will be subject to clawback in the event required by applicable law. Further, Mr. Ormand is subject to non-competition, non-solicitation, anti-raiding, and confidentiality provisions under his employment agreement.

 

Ms. Fuchs

 

In connection with the appointment of Ms. Fuchs as our General Counsel, we entered into an employment agreement with her dated March 16, 2015. The agreement provided, among other things, that Ms. Fuchs would receive an annual salary of $230,000. Additionally, as of the effective date of the agreement, Ms. Fuchs was granted (i) 5,000 shares of restricted stock and (ii) 30,000 stock options, which were scheduled to vest in equal installments on the first three anniversaries of the effective date of the agreement. Ms. Fuchs was also eligible receive a cash incentive bonus if we achieved certain production thresholds.

 

On July 5, 2016, we entered into a new employment agreement with Ms. Fuchs under which she will continue to serve as our General Counsel. This agreement became effective June 24, 2016 upon the closing of our merger with Brushy. The initial term of the agreement is scheduled to end on December 31, 2017, and the agreement will renew automatically for additional one-year periods beginning on December 31, 2017, unless either party gives notice of non-renewal at least 180 days before the end of the then-current term. The agreement replaces in its entirety Ms. Fuchs’ prior employment agreement with us.

 

Ms. Fuchs’ initial base salary under the agreement (which will be reviewed for adjustments) is $250,000. Ms. Fuchs was entitled to a bonus under the agreement equal to $112,500, payable in cash on the first regular payroll date of the Company following June 24, 2016 (the closing date of the merger with Brushy). Ms. Fuchs is also eligible to receive a cash bonus equal to a percentage of her base salary (ranging from 0% to 400%) depending on the level of achievement of certain BOE per day, EBITDAX and cash on hand performance measures. Ms. Fuchs is also eligible to receive awards of equity and non-equity compensation and to participate in our annual and long-term incentive plans, in each case as determined by our Board in its discretion. On June 24, 2016, Ms. Fuchs received a grant of 375,000 stock options under our 2016 Plan, with an exercise price of $1.34. This grant is scheduled to vest over two years, with 34% vesting on the grant date, 33% vesting on the first anniversary of the grant date and 33% vesting on the second anniversary of the grant date, subject to continued service through each vesting date.

 

 66 

 

 

Under her employment agreement, Ms. Fuchs’ will be entitled to a lump sum severance payment equal to six months of base salary and six months of COBRA premiums upon a termination by the Company without cause or a termination by her for good reason. Upon a termination by the Company without cause or a termination by Ms. Fuchs for good reason within 12 months following a change in control, she will be entitled to a lump sum severance payment equal to 24 months of base salary and 24 months of COBRA premiums. Upon a termination due to disability, Ms. Fuchs will be entitled to a lump sum severance payment equal to six months of COBRA premiums. All severance payments under Ms. Fuchs employment agreement are subject to her execution and non-revocation of a release of claims against the Company. The severance payments are also subject to reduction in order to avoid an excise tax associated with Section 280G of the Internal Revenue Code, but only if that reduction would result in Ms. Fuchs receiving a greater net after tax benefit as a result of the reduction.

 

All payments to Ms. Fuchs under her employment agreement will be subject to clawback in the event required by applicable law. Further, Ms. Fuchs is subject to non-competition, non-solicitation, anti-raiding and confidentiality provisions under her employment agreement.

 

Potential Payments Upon Termination or Change-In-Control

 

Mr. Mirman

 

Under his employment agreement, Mr. Mirman will be entitled to a lump sum severance payment equal to 12 months of base salary and 12 months of COBRA premiums upon a termination by us without cause or a termination by him for good reason. Upon a termination by the Company without cause or a termination by Mr. Mirman for good reason within 12 months following a change in control, he will be entitled to a lump sum severance payment equal to 24 months of base salary and 24 months of COBRA premiums. Upon a termination due to disability, Mr. Mirman will be entitled to a lump sum severance payment equal to six months of COBRA premiums. All severance payments under Mr. Mirman’s employment agreement are subject to his execution and non-revocation of a release of claims against us. The severance payments are also subject to reduction in order to avoid an excise tax associated with Section 280G of the Internal Revenue Code, but only if that reduction would result in Mr. Mirman receiving a greater net after tax benefit as a result of the reduction. All payments to Mr. Mirman under his employment agreement will be subject to clawback in the event required by applicable law. Further, Mr. Mirman is subject to non-competition, non-solicitation, anti-raiding and confidentiality provisions under his employment agreement.

 

Mr. Ormand

 

Under his employment agreement, Mr. Ormand will be entitled to a lump sum severance payment equal to 12 months of base salary and 12 months of COBRA premiums upon a termination by us without cause or a termination by him for good reason. Upon a termination by us without cause or a termination by Mr. Ormand for good reason within 12 months following a change in control, he will be entitled to a lump sum severance payment equal to 24 months of base salary and 24 months of COBRA premiums. Upon a termination due to disability, Mr. Ormand will be entitled to a lump sum severance payment equal to six months of COBRA premiums. All severance payments under Mr. Ormand’s employment agreement are subject to his execution and non-revocation of a release of claims against the Company. The severance payments are also subject to reduction in order to avoid an excise tax associated with Section 280G of the Internal Revenue Code, but only if that reduction would result in Mr. Ormand receiving a greater net after tax benefit as a result of the reduction. All payments to Mr. Ormand under his employment agreement will be subject to clawback in the event required by applicable law. Further, Mr. Ormand is subject to non-competition, non-solicitation, anti-raiding and confidentiality provisions under his employment agreement.

 

Ms. Fuchs

 

Under her employment agreement, Ms. Fuchs’ will be entitled to a lump sum severance payment equal to six months of base salary and six months of COBRA premiums upon a termination by us without cause or a termination by her for good reason. Upon a termination by us without cause or a termination by Ms. Fuchs for good reason within 12 months following a change in control, she will be entitled to a lump sum severance payment equal to 24 months of base salary and 24 months of COBRA premiums. Upon a termination due to disability, Ms. Fuchs will be entitled to a lump sum severance payment equal to six months of COBRA premiums. All severance payments under Ms. Fuchs employment agreement are subject to her execution and non-revocation of a release of claims against us. The severance payments are also subject to reduction in order to avoid an excise tax associated with Section 280G of the Internal Revenue Code, but only if that reduction would result in Ms. Fuchs receiving a greater net after tax benefit as a result of the reduction. All payments to Ms. Fuchs under her employment agreement will be subject to clawback in the event required by applicable law. Further, Ms. Fuchs is subject to non-competition, non-solicitation, anti-raiding and confidentiality provisions under her employment agreement.

 

 67 

 

 

Stock Options

 

Each of Mr. Mirman, Mr. Ormand and Ms. Fuchs hold unvested options under our 2016 Plan, all of which become fully exercisable (1) immediately upon the officer’s separation from service other than for cause or for good reason, and (2) immediately prior to, and contingent upon, a change in control prior to the officer’s separation from service.

 

Retirement and Other Benefits

 

All employees, including our NEOs, may participate in our 401(k) retirement savings plan (“401(k) Plan”). Each employee may make before tax contributions in accordance with Internal Revenue Service limits. We provide this 401(k) Plan to help our employees save a portion of their cash compensation for retirement in a tax efficient manner. In prior years, we have made a matching contribution in an amount equal to 100% of the employee’s elective deferral contribution below 3% of the employee’s compensation and 50% of the employee’s elective deferral that exceeds 3% of the employee’s compensation but does not exceed 5% of the employee’s compensation.

 

Compensation of Nonemployee Directors

 

Name  Fees Earned
or Paid in
Cash
Compensation
($)
   Stock Awards
($)(1)
   Option
Awards
($)(2)
  

All Other
Compensation

($)

  

Total

($)

 
                     
G. Tyler Runnels(3)                    
Nuno Brandolini(4)   72,500    135,000            207,500 
General Merrill McPeak(5)   85,000    135,000            220,000 
R. Glenn Dawson(6)   70,522    255,750    81,000        407,272 
Peter Benz(7)   43,901    135,000    67,500        246,401 

 

(1)Represents restricted stock awards. The grant date fair values for restricted stock awards were determined in accordance with FASB ASC Topic 718. The amounts reported reflect the accounting cost for the awards and do not correspond to the actual economic value that may be received for the awards.
(2)Awards in this column are reported at grant date fair value in accordance with FASB ASC Topic 718. The amounts reported reflect the accounting cost for the options and do not correspond to the actual economic value that may be received for the options. The assumptions used to calculate the fair value of options are set forth in the notes to our consolidated financial statements included in this Annual Report on Form 10-K. As of December 31, 2016, our nonemployee directors held the following equity awards: Mr. Brandolini - 45,000 options, 50,000 restricted shares and 41,666 restricted stock units; General McPeak - 45,000 options, 33,333 restricted shares and 66,666 restricted stock units; Mr. Dawson - 45,000 options and 113,667 restricted shares; and Mr. Benz - 45,000 options and 33,333 restricted shares.
(3)Mr. Runnels served as a director from November 21, 2014, through January 13, 2016.
(4)Mr. Brandolini has served as a director since February 13, 2014.
(5)General McPeak was appointed to the board on January 29, 2015.
(6)Mr. Dawson was appointed to the Board on January 13, 2016.
(7)Mr. Benz was appointed to the Board on June 23, 2016.

 

 68 

 

 

On April 16, 2015, our Board adopted an amended nonemployee director compensation program (the “Prior Program”). The Prior Program was comprised of the following components:

 

·Initial Grant: Each nonemployee director would receive 100,000 restricted shares of common stock on the first anniversary of the date of the director’s appointment, which would vest in three equal installments over a three-year period, (subject to the continued service of the director and certain accelerated vesting provisions);
·Annual Stock Award: Each nonemployee director would receive an annual stock award equal to $60,000 divided by the most recent per share closing price of the common stock prior to the date of each annual grant, payable on each anniversary of the date an independent director was initially appointed to our Board, and subject to certain accelerated vesting provisions;
·Option Award: Each nonemployee director would receive a one-time initial grant of 25,000 stock options, which would vest immediately, and 20,000 options that would vest in equal installments over a three-year period beginning on the first anniversary of the grant date; and
·Committee Fees: On a quarterly basis, beginning at the end of the first full quarter following the appointment of the nonemployee director to Chairman of the Board, Chairman of the Audit Committee or Chairman of the Compensation Committee, the director would receive $12,500, $6,250 and $6,250, respectively, in cash compensation, which at the election of the director would be payable in cash or stock (calculated by dividing the value of cash compensation (or a portion thereof), by the most recent per share closing price of the common stock prior to the date of the grant).

 

Beginning January 1, 2017, our Board adopted an amended nonemployee director compensation program (the “New Program”). The New Program is substantially similar to the Prior Program. However, the New Program sets forth an annual equity date (which will be the first business day on or after January 31 of each year) pursuant to which each nonemployee director will receive an Annual Stock Award, subject to substantially the same terms and conditions set forth above. In addition, the New Program establishes annual limits on the number of shares subject to our equity compensation plan awards that may be granted during any calendar year to any director, which, taken together with any cash fees paid to the director during the year, cannot exceed $500,000 in total value.

 

Indemnification of Directors and Officers

 

Pursuant to our certificate of incorporation we provide indemnification of our directors and officers to the fullest extent permitted under Nevada law. We believe that this indemnification is necessary to attract and retain qualified directors and officers.

 

 69 

 

 

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

 

Securities Authorized for Issuance under Equity Compensation Plans

 

The following table represents the securities authorized for issuance under our equity compensation plans at December 31, 2016.

 

Plan category  Number of
securities to
be issued
upon exercise
of outstanding
options,
warrants and
rights (1)
   Weighted-average
exercise price of
outstanding
options, warrants
and rights (2)
   Number of
securities
remaining
available for
future issuance
under equity
compensation
plans
 
             
Equity compensation plans approved by security holders   5,354,794    1.74    3,574,742 
Equity compensation plans not approved by security holders   -    -      
Total   5,354,794    1.74    3,574,742 

 

(1)Includes stock options and restricted stock units outstanding under our 2016 Plan and our 2012 EIP as of December 31, 2016. Does not include shares of restricted stock issued pursuant to our 2016 Plan or our 2012 EIP.
(2)Represents the weighted average exercise price of outstanding options issued pursuant to our 2016 Plan and our 2012 EIP as of December 31, 2016.

 

Other Equity Compensation

 

We have entered into various services agreements for which compensation has been paid with equity securities, including (i) a consulting agreement with Bristol Capital LLC pursuant to which we issued to Bristol a five year warrant to purchase up to 641,026 shares of common stock at an exercise price of $3.12 per share (or, in the alternative, 641,026 options, but in no case both), (ii) consulting agreements with Market Development Consulting Group, Inc. pursuant to which we issued five year warrants to purchase up to an aggregate of 500,000 shares of common stock ,with an exercise price of $2.33 for the warrant to purchase 250,000 shares of common stock and an exercise price of $2.00 for the warrant to purchase 250,000 shares of common stock; (iii) an investment banking agreement with TRW pursuant to which we issued 900,000 warrants at an exercise price of $4.25 per share; and (iv) various agreements pursuant to which issued an aggregate amount of 150,000 and 300,000 five year warrants to purchase shares of common stock at an exercise price of $2.50 and $2.00, respectively. With respect to the warrants awarded to Bristol Capital, we recorded the warrants as a derivative due to the price reset provision encompassed in the warrants.

 

 70 

 

 

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

 

The following table sets forth certain information with respect to beneficial ownership of our common stock as of March 1, 2017, by each of our executive officers and directors and each person known to be the beneficial owner of 5% or more of the outstanding common stock.

 

This table is based upon the total number of shares outstanding as of March 1, 2017 of 24,387,793. Unless otherwise indicated, the persons and entities named in the table have sole voting and sole investment power with respect to the shares set forth opposite the stockholder’s name. Beneficial ownership is determined in accordance with Rule 13d-3 under the Securities Exchange Act of 1934, as amended. In computing the number of shares beneficially owned by a person or a group and the percentage ownership of that person or group, shares of our common stock subject to options or warrants currently exercisable or exercisable within 60 days after March 1, 2017 are deemed outstanding by such person or group, but are not deemed outstanding for the purpose of computing the percentage ownership of any other person. All share amounts that appear in this report have been adjusted to reflect a 1-for-10 reverse stock split of our outstanding common stock effected on June 23, 2016. Unless otherwise indicated, the address of each stockholder listed in the table is c/o Lilis Energy, Inc., 300 E. Sonterra Blvd. Ste. 1220, San Antonio, Texas 78258

 

   Series B Preferred Stock   Common Stock 
Name and Address of Beneficial
Owner
  Shared
Beneficially
Owned (1)
   % of
Class
   Lilis
common
stock
Held
Directly
   Lilis
common
stock
Acquirable
Within 60
Days(2)
   Total
Beneficially
Owned(2)
   Percent of
Class
Beneficially
Owned(2)
 
                         
Directors and Named Executive Officers                              
Abraham Mirman, Chief Executive Officer and Director   1,650    10.59%   762,906(3)   643,334(4)   1,406,240    5.6%(5)
Ronald D. Ormand, Executive Chairman of the Board   1,000    6.42%   2,495,752(6)   115,001(7)   2,610,753    10.7%(8)
Joseph Daches, Chief Financial Officer           45,000    250,000(9)   295,000    1.2%
Ariella Fuchs, Executive Vice President, General Counsel and Secretary               250,000(10)   250,000    1.0%
Peter Benz, Director           75,000    25,000(11)   100,000    * 
Nuno Brandolini, Director           402,060    159,574(12)   561,634    2.3%
R. Glenn Dawson, Director           440,861    108,486(13)   549,347    2.2%
General Merrill McPeak, Director           406,207    143,521(14)   549,728    2.2%
Directors and Officers as a Group (10 persons)   2,650    17.0%   4,627,786    1,694,916(15)   6,322,702    24.2%(16)
                               
5% Stockholders                              
Bryan Ezralow, 23622 Calabasas Road, Suite 200, Calabasas, CA 913012   900    5.8%   1,564,969(17)   (18)   1,564,969    6.42%
Marc Ezralow, 23622 Calabasas Road, Suite 200, Calabasas, CA 913012   750    4.8%   1,221,566(19)   (20)   1,221,566    5.01%

 

* Represents beneficial ownership of less than 1% of the outstanding shares of common stock.
   
(1)

Applicable percentages are based on 15,588 shares of Series B Preferred Stock outstanding as of the date March 1, 2017. Series B Preferred Stock is non-voting, and currently, no holder of shares of Series B Preferred Stock may convert such shares if, upon conversion, such holder would beneficially own more than 4.99% of the Company’s then-outstanding stock. Accordingly, holders of 5% or more of shares of Series B Preferred Stock have been excluded from this beneficial ownership table.

 

 

 71 

 

 

(2)

 

 

The terms of the Series B Preferred Stock, and each of the Company’s outstanding warrants, the “Blocker Securities”) contain a provision prohibiting the conversion of such Series B Preferred Stock, and the exercise of warrants into common stock of the Company if, upon such conversion or exercise, as applicable, the holder thereof would beneficially own more than a certain percentage of the Company’s then outstanding common stock (the “Blocker Limitation”). This percentage limitation is 4.99%, except that upon 61 days prior notice to the Company, a holder of Series B Preferred Stock may increase the percentage limitation with respect to the Series B Preferred up to a maximum of 9.99%. However, the foregoing restrictions do not prevent such holder from converting or exercising, as applicable, some of its holdings, selling those shares, and then converting or exercising, as applicable, more of its holdings, while still staying below the respective percentage limitation. As a result, the holder could sell more than any applicable ownership limitation while never actually holding more shares than the applicable limitations allow. Accordingly, the share numbers in the above table represent ownership without regard to the beneficial ownership limitations described in this footnote. While the ownership percentages are also given without regard to this beneficial ownership limitation, specific footnotes indicate what the effect of each ownership limitation would be as of March 1, 2017.
   
(3) Consists of: (i) 11,087 shares of common stock held by The Bralina Group, LLC; and (ii) 751,819 shares of common stock held directly by Mr. Mirman. Mr. Mirman has shared voting and dispositive power over the securities held by The Bralina Group, LLC with Susan Mirman.
   
(4)

Represents shares of common stock subject to options exercisable within 60 days.

 

In addition, Mr. Mirman beneficially owns an aggregate of 2,566,274 additional shares of common stock acquirable within 60 days, each of which is subject to a Blocker Limitation. However, Mr. Mirman’s percentage ownership is currently in excess of such Blocker Limitations, and as a result, such Blocker Securities have been excluded from the table. These Blocker Securities consist of the following: (i) 1,500,000 shares of common stock issuable upon conversion of shares of Series B Preferred held by the Bralina Group; (ii) 305,187 shares of common stock issuable upon exercise of warrants held by the Bralina Group and (iii) 761,087 shares of common stock issuable upon exercise of warrants held directly by Mr. Mirman.

   
(5) Including the Blocker Securities, and ignoring the Blocker Limitation, Mr. Mirman beneficially owns a total 3,972,514 shares of common stock, which represents 14.4% of our currently issued and outstanding common stock.

 

(6)

 

Consists of: (i) 1,259,388 shares of common stock held directly by Mr. Ormand; (ii) 100,000 shares of common stock held by Perugia Investments L.P. (“Perugia”); and (iii) 1,136,364 shares of common stock held by The Bruin Trust, an irrevocable trust managed by Jerry Ormand, Mr. Ormand’s brother, as trustee and whose beneficiaries include the adult children of Mr. Ormand. Mr. Ormand is the manager of Perugia and has sole voting and dispositive power over the securities held by Perugia.

   
(7)

Represents shares of common stock subject to options exercisable within 60 days.

 

In addition, Mr. Ormand beneficially owns an aggregate of 1,874,011 additional shares of common stock acquirable within 60 days, each of which is subject to a Blocker Limitation. However, Mr. Ormand’s percentage ownership is currently in excess of such Blocker Limitations, and as a result, such Blocker Securities have been excluded from the table. These Blocker Securities consist of the following: (i) 464,920 shares of common stock issuable upon exercise of warrants held by Perugia; (ii) 500,000 shares of common stock issuable upon exercise of warrants held by The Bruin Trust; and (iii) 909,091 shares of common stock issuable upon conversion of shares of Series B Preferred Stock held by Perugia.

   
(8) Including the Blocker Securities, and ignoring the Blocker Limitation, Mr. Ormand beneficially owns a total 4,484,764 shares of common stock, which represents 17% of our currently issued and outstanding common stock.
   
(9) Represents shares of common stock subject to options exercisable within 60 days.

 

 72 

 

 

(10)  Represents shares of common stock subject to options exercisable within 60 days.
   
(11) Represents shares of common stock subject to options exercisable within 60 days.
   
(12) Consists of: (i) 45,000 shares of common stock subject to options exercisable within 60 days; and (ii) 114,574 shares of common stock issuable upon exercise of warrants. The effect of any Blocker Limitation with respect to the securities described here has been excluded, as Mr. Brandolini is below the threshold of any such limitation.
   
(13) Consists of: (i) 31,667 shares of common stock subject to options exercisable within 60 days; and (ii) 76,819 shares of common stock issuable upon exercise of warrants. The effect of any Blocker Limitation with respect to the securities described here has been excluded, as Mr. Dawson is below the threshold of any such limitation.
   
(14) Consists of: (i) 38,333 shares of common stock subject to options exercisable within 60 days; (ii) 105,188 shares of common stock issuable upon exercise of warrants. The effect of any Blocker Limitation with respect to the securities described here has been excluded, as General McPeak is below the threshold of any such limitation.
   
(15) As indicated in the above footnotes, this amount excludes an aggregate of 4,440,285 additional shares of common stock acquirable within 60 days, which are subject to Blocker Limitations.
   
(16) Including the Blocker Securities, and ignoring the Blocker Limitation, the directors and officers as a group beneficially own a total of 10,762,987 shares of common stock, which represents 37.34% of our currently issued and outstanding common stock.
   
(17)

Based solely on a Schedule 13G filed by Bryan Ezralow on February 14, 2017. Collectively, the shares of Common Stock reported herein in which Bryan Ezralow has shared voting and dispositive power over such shares is an aggregate of 1,011,451 shares. Such shares are held directly by (a) the Ezralow Family Trust u/t/d 12/9/1980 (the “Family Trust”) in the amount of 36,723 shares, where Bryan Ezralow as a co-trustee of the Family Trust shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; (b) the Ezralow Marital Trust u/t/d 1/12/2002 (the “Marital Trust”) in the amount of 42,583 shares, where Bryan Ezralow as a co-trustee of the Marital Trust shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; (c) Elevado Investment Company, LLC, a Delaware limited liability company (“Elevado Investment”), in the amount of 140,821 shares, where Bryan Ezralow as a co-trustee and manager, respectively, of the two trusts and limited liability company that comprise the managing members of Elevado Investment, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; (d) EMSE LLC (“EMSE”), a Delaware limited liability company, in the amount of 81,949 shares, where Bryan Ezralow, as a manager of EMSE, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; (e) EZ Colony Partners, LLC, a Delaware limited liability company (“EZ Colony”), in the amount of 709,372 shares, where Bryan Ezralow as the sole trustee of one of the trusts that is a manager of EZ Colony, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; and (f) EZ MM&B Holdings, LLC, a Delaware limited liability company (“EZ MM&B”), in the amount of 3 shares, where Bryan Ezralow as the sole trustee of one of the trusts that is a manager of EZ MM&B, and as a co-trustee and manager, respectively, of the two trusts and limited liability company that comprise the managing members of one of the other managers of EZ MM&B, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares.

 

Collectively, the shares of Common Stock reported herein in which Bryan Ezralow has sole voting and dispositive power over such shares are 553,518 shares. Such shares are held directly by (a) the Bryan Ezralow 1994 Trust u/t/d/ 12/22/1994, Bryan Ezralow, Trustee (the “Bryan Trust”) in the amount of 518,669 shares, where Bryan Ezralow as sole trustee of the Bryan Trust has sole voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; and (b) the Marc Ezralow Irrevocable Trust u/t/d 6/1/2004 (the “Irrevocable Trust”) in the amount of 34,849 shares, where Bryan Ezralow as sole trustee of the Irrevocable Trust has sole voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares.

 

 

 73 

 

 

(18) In addition, Bryan Ezralow beneficially owns an aggregate of 2,137,598 additional shares of common stock acquirable within 60 days, each of which is subject to a Blocker Limitation. However, the percentage ownership by Bryan Ezralow is currently in excess of such Blocker Limitations, and as a result, such Blocker Securities have been excluded from the table. These Blocker Securities consist of the following: (A) (i) 272,728 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 529,091 shares of common stock issuable upon the exercise of warrants, each held by the Bryan Trust; (B) (i) 45,455 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 68,546 shares of common stock issuable upon the exercise of warrants, each held by the Irrevocable Trust; (C) (i) 136,364 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 200,371 shares of common stock issuable upon the exercise of warrants, each held by Elevado; (D) (i) 90,910 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 75,550 shares of common stock issuable upon the exercise of warrants, each held by EMSE; (E) (i) 181,819 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 343,168 shares of common stock issuable upon the exercise of warrants, each held by EZ Colony; (F) (i) 45,455 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 53,234 shares of common stock issuable upon the exercise of warrants, each held by the Marital Trust; and (H) (i) 45,455 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 49,452 shares of common stock issuable upon the exercise of warrants, held by the Family Trust.
   
(19)

Based solely on a Schedule 13G filed by Marc Ezralow on February 14, 2017. Collectively, the shares of Common Stock reported herein in which Marc Ezralow has shared voting and dispositive power over such shares are an aggregate of 1,011,451 shares. Such shares are held directly by (a) the Ezralow Family Trust u/t/d 12/9/1980 (the “Family Trust”) in the amount of 36,723 shares, where Marc Ezralow, as a co-trustee of the Family Trust, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; (b) the Ezralow Marital Trust u/t/d 1/12/2002 (the “Marital Trust”) in the amount of 42,583 shares, where Marc Ezralow, as a co-trustee of the Marital Trust, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; (c) Elevado Investment Company, LLC, a Delaware limited liability company (“Elevado Investment”), in the amount of 140,821 shares, where Marc Ezralow as a co-trustee and manager, respectively, of the two trusts and limited liability company that comprise the managing members of Elevado Investment, shares voting and dispositive power over such shares, and thus, be deemed to beneficially own such shares; (d) EMSE LLC (“EMSE”), a Delaware limited liability company, in the amount of 81,949 shares, where Marc Ezralow, as a manager of EMSE shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; (e) EZ Colony Partners, LLC, a Delaware limited liability company (“EZ Colony”), in the amount of 709,372 shares, where Marc Ezralow as the sole trustee of one of the trusts that is a manager of EZ Colony, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; and (f) EZ MM&B Holdings, LLC, a Delaware limited liability company (“EZ MM&B”) in the amount of 3 shares, where Marc Ezralow as the sole trustee of one of the trusts that is a manager of EZ MM&B, and as a co-trustee and manager, respectively, of the two trusts and limited liability company that comprise the managing members of one of the other managers of EZ MM&B, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares.

 

Collectively, the shares of Common Stock reported herein in which Marc Ezralow has sole voting and dispositive power over said Common Stock are 210,115 shares. Such shares are held directly by (a) the Marc Ezralow 1997 Trust u/t/d/ 11/26/1997, Marc Ezralow, Trustee (the “Marc Trust”) in the amount of 175,266 shares, where Marc Ezralow as sole trustee of the Marc Trust has sole voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; and (b) the SPA Trust u/t/d 9/13/2004 (the “SPA Trust”), in the amount of 34,849 shares, where Marc Ezralow as sole trustee of the SPA Trust has sole voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares.

 

(20)

In addition, Marc Ezralow beneficially owns an aggregate of 1,769,416 additional shares of common stock acquirable within 60 days, each of which is subject to a Blocker Limitation. However, the percentage ownership by Marc Ezralow is currently in excess of such Blocker Limitations, and as a result, such Blocker Securities have been excluded from the table. These Blocker Securities consist of the following: (A) (i) 45,455 shares of common stock issuable upon conversion of shares of Series B Preferred Stock and (ii) 68,546 shares of common stock issuable upon exercise of warrants, each held the SPA Trust; (B) (i) 136,364 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 297,273 shares of common stock issuable upon exercise of warrants, each held by the 1997 Trust; (C) (i) 136,364 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 200,371 shares of common stock issuable upon the exercise of warrants, each held by Elevado; (D) (i) 90,910 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 75,550 shares of common stock issuable upon the exercise of warrants, each held by EMSE; (E) (i) 181,819 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 343,168 shares of common stock issuable upon the exercise of warrants, each held by EZ Colony; (F) (i) 45,455 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 53,234 shares of common stock issuable upon the exercise of warrants, each held by the Marital Trust; and (H) (i) 45,455 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 49,452 shares of common stock issuable upon the exercise of warrants, held by the Family Trust.

 

 

To Lilis’s knowledge, except as noted above, no person or entity is the beneficial owner of 5% or more of Lilis’s common stock.

 

 74 

 

 

Item 13. Certain Relationships and Related Transactions, and Director Independence

 

Related Party Transactions

 

We describe below transactions and series of similar transactions, since January 1, 2016, to which we were a party, in which:

 

·The amounts involved exceeded or will exceed the lesser of $120,000 or one percent (1%) of our average total assets at year-end for the last two completed fiscal years; and
·Any of our directors, executive officers, or holders of more than 5% of our capital stock, or any member of the immediate family of, or person sharing the household with, any of the foregoing persons, who had or will have a direct or indirect material interest.

 

All share and per share amounts applicable to our common stock from transactions that occurred prior to the June 23, 2016 reverse split in the following summaries of related party transactions have not been adjusted to reflect the 1-for-10 reverse split of our issued and outstanding common stock, unless specifically described below.

 

Series B Preferred Stock Private Placement

 

On June 15, 2016, we entered into the Series B Purchase Agreement with certain institutional and accredited investors (the “Purchasers”) in connection with the Series B preferred stock offering. For more information on the Series B preferred stock offering see Note 13-Shareholders Equity.

 

On June 6, 2016, as subsequently amended, we entered into a Transaction Fee Agreement with TRW, a more than 5% shareholder of our company during the year ended December 31, 2016, in connection with the Series B preferred stock offering to act as co-broker dealers along with KES7, and as administrative agent. TRW received a cash fee of $500,000 and broker warrants to purchase up to 452,724 shares of common stock, at an exercise price of $1.30, exercisable on or after September 17, 2016, for a period of two years. Of the cash fee paid to TRW, $150,000 was reinvested into the Series B preferred stock offering in exchange for 150 shares of Series B preferred stock and the related warrants to purchase 68,182 shares of common stock at an exercise price of $2.50. These fees were recorded as a reduction to equity.

 

Certain other Purchasers in the Series B preferred stock offering include certain of our related parties, such as Abraham Mirman, our Chief Executive Officer and a director, through the Bralina Group, LLC for which Mr. Mirman holds shared voting and dispositive power ($1.65 million); Ronald D. Ormand, the Chairman of our Board of Directors through Perugia Investments LP for which Mr. Ormand holds sole voting and dispositive power ($1.0 million), Kevin Nanke, the Company’s former Executive Vice President and Chief Financial Officer during the year ended December 31, 2016, through KKN Holdings LLC, for which Mr. Nanke holds sole voting and dispositive power ($200,000), R. Glenn Dawson, a director of our company ($125,000), Pierre Caland through Wallington Investment Holdings, Ltd. a more than 5% shareholder of our company ($250,000) during the year ended December 31, 2016 and Bryan Ezralow and Marc Ezralow through various entities beneficially owned by them ($1.3 million).

 

Credit and Guarantee Agreement and Warrant Reprice

 

On September 29, 2016, we entered into the Credit Agreement. For more information about the Credit Agreement see Management’s Discussion and Analysis—Credit Agreement and Warrant Reprice.

 

Certain parties to the Credit Agreement included certain of our related parties such as TRW, acting as collateral agent, and Bryan Ezralow, Marc Ezralow and Marshall Ezralow through certain of their investment entities ($2.8 million).

 

Debenture Conversion Agreement

 

On December 29, 2015, we entered into the Debenture Conversion Agreement with all of the remaining holders of the Debentures. For more information about the Debentures see Management’s Discussion and Analysis—Debentures.

 

Certain parties to the Debenture Conversion Agreement included certain of our related parties at that time, such as the Steven B. Dunn and Laura Dunn Revocable Trust dated 10/28/10, of which its respective Debenture amount converted was approximately $1.02 million, Bryan Ezralow through EZ Colony Partners, LLC of which his respective Debenture amount converted was approximately $1.54 million and Pierre Caland through Wallington Investment Holdings, Ltd., of which its respective Debenture amount converted was approximately $2.09 million. Steven B. Dunn and Laura Dunn Revocable Trust dated October 28, 2010 who held more than 5% of our Common Stock during the year ended December 31, 2016.

 

 75 

 

 

Series A Preferred Stock

 

On May 30, 2014, we entered into a securities purchase agreement with accredited investors, pursuant to which it issued an aggregate of $7.5 million in Series A preferred stock with a conversion price of $24.10 and warrants to purchase up to 155,602 shares of common stock.

 

On June 23, 2016, after the receipt of requisite stockholder approval and in connection with the consummation of the Merger, all outstanding shares of Series A preferred stock were converted into common stock at a reduced conversion price of $5.00 a share, resulting in the issuance of 1,500,000 shares of common stock. In exchange for the reduction in conversion price from $24.10 per share to $5.00 per share, all accrued but unpaid dividends were forfeited.

 

Several of our officers, directors and affiliates were investors in the Series A preferred stock and converted their shares at $5.00 including Abraham Mirman ($250,000), Ronald D. Ormand (through Perugia Investments ($500,000), Nuno Brandolini ($100,000), General Merrill McPeak ($250,000), TRW ($779,000) and Pierre Caland through Wallington Investment Holdings, Ltd. ($125,000).

 

Convertible Notes

 

In a series of transactions from December 29, 2015 to May 6, 2016, we issued an aggregate of approximately $5.8 million in Convertible Notes maturing on June 30, 2016 and April 1, 2017 at a conversion price of $5.00 and warrants to purchase an aggregate of approximately 2.3 million shares of common stock with an exercise price of $2.50 for warrants issued between December 2015 and March 2016 and $0.10 for the warrants issued in May 2016. The purchasers include certain of our related parties, including Abraham Mirman, our Chief Executive Officer and director of our company ($750,000), the Bruin Trust (the “Bruin Trust”), an irrevocable trust managed by an independent trustee and whose beneficiaries include the adult children of Ronald D. Ormand, Chairman of our Board of Directors ($1.15 million), General Merrill McPeak, a director of our company ($250,000), Nuno Brandolini, a director of our company ($250,000), Glenn Dawson, a director of our company ($50,000), Kevin Nanke, the Company’s former Executive Vice President and Chief Financial Officer during the year ended December 31, 2016 ($100,000, which was reinvested instead of a cash bonus payment due to Mr. Nanke pursuant to his prior executive employment agreement), Pierre Caland through Wallington Investment Holdings, Ltd. ($300,000), who held more than 5% of our common stock during the year ended December 31, 2016, Bryan and Marc Ezralow, through various entities who held more than 5% of our common stock during the year ended December 31, 2016 ($905,381) and TRW ($400,000).

 

Subsequently, warrants to purchase up to 620,000 shares of common stock issued in connection with the Convertible Notes between December 2015 and March 2016 were amended and restated to reduce the exercise price to $0.10 in exchange for additional consideration given to us in the form of participation in the May Convertible Notes offering. Of those warrants, a total of 80,000 warrants were exercised. Additionally, during the three months ended June 30, 2016, in exchange for several offers to immediately exercise a portion of each investor’s outstanding warrants issued between 2013 and 2014, we reduced the exercise price on warrants to purchase a total of 416,454 shares of common stock ranging from $42.50 to $25.00 per share to $0.10 per share, of which a total of 315,990 were subsequently exercised, resulting in the issuance of an aggregate amount of 300,706 shares of common stock due to certain cashless exercises. TRW net exercised warrants to purchase 80,000 shares of common stock at a reset exercise price of $0.10, resulting in the issuance of 75,820 shares.

 

TRW also received an advisory fee on the Convertible Notes in the amount of $350,000, which was subsequently reinvested in full into the Series B Preferred Offering for 350 shares of Series B Preferred Stock and related warrants to purchase up to 159,091 shares of common stock.

 

On June 23, 2016, we entered into the Note Conversion Agreement. Certain parties to the Note Conversion Agreement include certain of our related parties, such as each officer and director who invested in the Notes, each of whom converted their outstanding amounts in full. In addition, Pierre Caland, through Wallington Investments, Ltd., was signatory to the Note Conversion Agreement and converted its outstanding amounts in full.

 

On August 3, 2016, we entered into the first amendment to the Notes with the remaining holders of approximately $1.8 million of our Notes. Each of Bryan Ezralow and Marc Ezralow through various entities and TRW was a party to the first amendment. For a detailed description of the first amendment to the Convertible Notes see—Note 8—Long Term Debt.

 

 76 

 

 

SOS

 

In connection with the Merger, SOS, Brushy’s former subordinated lender, and a more than 5% shareholder of our Company during the year ended December 31, 2016, agreed to extinguish approximately $20.5 million of its outstanding debt in exchange for Brushy’s divestiture of its properties to SOS in the Giddings Field, the SOS Note and the SOS Warrant, which was completed on June 23, 2016.

 

March 2017 Private Placement

 

On February 28, 2017, we entered into a Securities Purchase Agreement in connection with the March 2017 Private Placement. For more information on the March 2017 Private Placement see Management’s Discussion and Analysis—Liquidity and Capital Resources—Subsequent Events—March 2017 Private Placement.

 

The subscribers include certain of our related parties, including Bryan and Marc Ezralow through various entities ($2.6 million) and TRW, described further below.

 

G. Tyler Runnels and T.R. Winston

 

We have participated in several transactions with TRW, of which G. Tyler Runnels, a former member of our Board of Directors, is chairman and majority owner. During the year ended December 31, 2016, Mr. Runnels beneficially held more than 5% of our common stock, including the holdings of TRW and his personal holdings, and has personally participated in certain transactions with us.

 

On January 31, 2014, we entered into the Debenture Conversion Agreement with all of the holders of the Debentures, including TRW and Mr. Runnels’ personal trust. On June 23, 2016, all of the outstanding Debentures were converted at $5.00. See “—Debenture Conversion Agreement.”

 

On May 3, 2016 through May 5, 2016, in exchange for several offers to immediately exercise outstanding warrants issued between 2013 and 2014, we reduced the exercise price on warrants to purchase a total of 265,803 shares of common stock from a range of $42.50 to $25.00 per share to $0.10 per share which resulted in the issuance of a total of 250,520 shares of common stock. TRW received a total of 758,203 shares of common stock in this transaction.

 

On June 6, 2016, as subsequently amended, we entered into a Transaction Fee Agreement with TRW in connection with the Series B preferred stock offering. See “—Series B Private Placement.”

 

On November 1, 2016, we entered into a sublease agreement with TRW to sublease office space in New York, for which we pay $10,000 per month on a month-to-month basis.

 

On February 28, 2017, we entered into a Subscription Agreement in connection with the March 2017 Private Placement, for which TRW acted as placement agent and received a fee of $459,060. Additionally, TRW was a participant in the offering for an aggregate amount of $750,000.

 

Ronald D. Ormand

 

On March 20, 2014, we entered into an Engagement Agreement (the “Engagement Agreement”) with MLV & Co. LLC (“MLV”), which is now owned by FBR & Co., after it acquired MLV in September of 2015, pursuant to which MLV acted as our exclusive financial advisor. Ronald D. Ormand, a member of our Board of Directors since February 2015 and the current Executive Chairman of our Board of Directors, was previously the Managing Director and Head of the Energy Investment Banking Group at MLV. The Engagement Agreement provided for a fee of $25,000 to be paid monthly to MLV, subject to certain adjustments and other specific fee arrangements in connection with the nature of financial services being provided. We expensed $75,000 and $175,000 for the three and six months ended June 30, 2015, respectively. On May 27, 2015, MLV agreed to take $150,000 of its accrued fees in our common stock and was issued 75,000 shares in lieu of payment. The closing share price on May 27, 2015 was $1.56. The term of Engagement Agreement expired on October 31, 2015. On November 8, 2016, we paid FBR $100,000 as final settlement of outstanding fees owed under the Engagement Agreement.

 

Additionally, MLV had been involved in certain initial discussions relating to the Merger for which it did not receive a fee.

 

 77 

 

 

Agreements with Former Executive Officers

 

Kevin Nanke, Former Executive Vice President and Chief Financial Officer

 

On February 13, 2017, we entered into a Separation and Release of Claims Agreement (the “Separation Agreement”) with Mr. Nanke, providing for his separation as an officer of our company, effective January 23, 2017. Pursuant to the Separation Agreement and the terms of his employment agreement, Mr. Nanke will receive (1) a lump sum severance payment in an amount equal to 24 months of base salary in effect immediately prior to the date of termination, (2) a lump sum payment equal to 24 months of COBRA premiums based on the terms of our group health plan and Mr. Nanke’s coverage under such plan as of the date of termination, and (3) a lump sum bonus payment of $175,000. For consideration of the separation benefits listed above, Mr. Nanke (1) provided a general release of claims against us, our affiliates, and related parties, (2) to the extent reasonable, shall continue to provide full and continued cooperation in good faith with our company, our subsidiaries, and affiliates for 24 months following the date of termination in connection with certain matters relating to our company, and (3) agreed to be bound by confidentiality commitments to our company.

 

Additionally, pursuant to Mr. Nanke’s former employment agreement with us, dated as of March 18, 2016, he was entitled to receive a performance bonus of $100,000 if we were to achieve certain compliance goals set forth therein. In May 2016, our Board of Directors approved the reinvestment by Mr. Nanke of his performance bonus in the amount of $100,000 into the May Offering, pursuant to the same terms as the May Offering.

 

Edward Shaw, Former Executive Vice President and Chief Operating Officer of the Company

 

On February 13, 2017, we entered into a Separation and Release of Claims Agreement (the “Settlement Agreement”) with Mr. Shaw, providing for his separation as an officer of our company, effective January 24, 2017 (the “Separation Date”). Pursuant to the Settlement Agreement, Mr. Shaw received (1) a lump sum severance payment in an amount equal to 3 months of base salary in effect immediately prior to the date of termination, (2) a lump sum payment equal to 3 months of COBRA premiums based on the terms of our group health plan and Mr. Shaw’s coverage under such plan as of the date of termination, and (3) a period of three months from the separation date to exercise all vested options. For consideration of the separation benefits listed above, Mr. Shaw (1) provided a general release of claims against us, our affiliates, and related parties, (2) to the extent reasonable, shall continue to provide full and continued cooperation in good faith with our company, our subsidiaries, and affiliates for 24 months following the date of termination in connection with certain matters relating to our company, and (3) agreed to be bound by confidentiality commitments to our company.

 

For additional information on the above-mentioned agreements, see “Employment Agreements and Other Arrangements” above.

 

Compensation of Directors

 

See “Executive CompensationCompensation of Nonemployee Directors” above.

 

Conflict of Interest Policy

 

Our Board of Directors has recognized that transactions between us and certain related persons present a heightened risk of conflicts of interest. We have a corporate conflict of interest policy that prohibits conflicts of interests unless approved by our Board of Directors. Our Board of Directors has established a course of conduct whereby it considers in each case, whether the proposed transaction is on terms as favorable or more favorable to us than would be available from a non-related party. Our Board of Directors also looks at whether the transaction is fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us. Each of the related party transactions described above was presented to our Board of Directors for consideration and each of these transactions was unanimously approved by our Board of Directors after reviewing the criteria set forth in the preceding two sentences.

 

Director Independence

 

See “Directors, Executive Officers and Corporate Governance—Affirmative Determinations Regarding Director Independence and Other Matters” above.

 

Item 14. Principal Accounting Fees and Services

 

The following table sets forth fees billed by our principal accounting firm Marcum LLP for the years ended December 31, 2016 and 2015:

 

 78 

 

 

   Year Ended December 31, 
Fee Category  2016   2015 
   (In thousands) 
Audit Fees  $358   $264 
Audit-Related Fees   341    5 
Tax Fees   -    - 
All Other Fees   -    - 
Total Fees  $699   $269 

 

Audit Fees consist of the aggregate fees for professional services rendered for the audit of our annual financial statements and the reviews of the financial statements included in our Quarterly Reports on Forms 10-Q and for any other services that were normally provided by our auditors in connection with our statutory and regulatory filings or engagements.

 

Audit-Related Fees consist of the aggregate fees billed or reasonably expected to be billed for professional services rendered for assurance and related services that were reasonably related to the performance of the audit or review of our financial statements and were not otherwise included in Audit Fees. Majority of these services were related to the Brushy merger.

 

Tax Fees consist of the aggregate fees billed for professional services rendered for tax consulting. Included in such Tax Fees were fees for consultancy, review, and advice related to our income tax provision and the appropriate presentation on our financial statements of the income tax related accounts.

 

All Other Fees consist of the aggregate fees billed for products and services provided by our auditors and not otherwise included in Audit Fees, Audit-Related Fees or Tax Fees.

 

Audit Committee Pre-Approval Policy

 

Our independent registered public accounting firm may not be engaged to provide non-audit services that are prohibited by law or regulation to be provided by it, nor may our independent registered public accounting firm be engaged to provide any other non-audit service unless it is determined that the engagement of the principal accountant provides a business benefit resulting from its inherent knowledge of our company while not impairing its independence. Our audit committee must pre-approve permissible non-audit services. During the year ended December 31, 2016, we had no non-audit services provided by our independent registered public accounting firm.

 

 79 

 

 

PART IV

 

Item 15. Exhibits, Financial Statement Schedules

 

a)Index to Financial Statements

 

Report of Independent Registered Public Accounting Firm F-1
Consolidated Balance Sheets as of December 31, 2016 and 2015 F-2
Consolidated Statements of Operations for the years ended December 31, 2016 and 2015 F-4
Consolidated Statements of Stockholders’ Equity (Deficit) for the years ended December 31, 2016 and 2015. F-5
Consolidated Statements of Cash Flows for the years ended December 31, 2016 and 2015 F-6
Notes to Consolidated Financial Statements F-7

 

b)Exhibits

 

The information required by this Item is set forth on the exhibit index that follows the signature page to this Annual Report on Form 10-K and is incorporated herein by reference.

 

c)Financial Statement Schedules

 

Not applicable.

 

 80 

 

 

SIGNATURES

 

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

  LILIS ENERGY, INC.
     
Date: March 3, 2017 By: /s/ Abraham Mirman
    Abraham Mirman
   

Chief Executive Officer

(Authorized Signatory)

 

Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated.

 

Signature   Title   Date
         
/s/ Abraham Mirman   Chief Executive Officer, Director   March 3, 2017
Abraham Mirman   (Principal Executive Officer)    
         
/s/ Joseph C. Daches   Executive Vice President and Chief Financial Officer   March 3, 2017
Joseph C. Daches   (Principal Financial and Accounting Officer)    
         
/s/ Ronald D. Ormand   Executive Chairman of the Board   March 3, 2017
Ronald D. Ormand        
         
/s/ Peter Benz   Director   March 3, 2017
Peter Benz        
         
/s/ Nuno Brandolini   Director   March 3, 2017
Nuno Brandolini        
         
/s/ R. Glenn Dawson   Director   March 3, 2017
R. Glenn Dawson        
         
/s/ General Merrill McPeak   Director   March 3, 2017
General Merrill McPeak        

 

 81 

 

 

Exhibit Index

 

The following exhibits are either filed herewith or incorporated herein by reference

 

2.1 Agreement and Plan of Merger, dated as of December 29, 2015, among Lilis Energy, Inc., Lilis Merger Sub, Inc. and Brushy Resources, Inc. (incorporated herein by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on January 5, 2016).
2.2 First Amendment to Agreement and Plan of Merger, dated as of January 20, 2016, among Lilis Energy, Inc., Lilis Merger Sub, Inc. and Brushy Resources, Inc. (incorporated herein by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on January 20, 2016).
2.3 Second Amendment to Agreement and Plan of Merger, dated as of March 24, 2016, among Lilis Energy, Inc., Lilis Merger Sub, Inc. and Brushy Resources, Inc. (incorporated herein by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on March 24, 2016).
2.4 Third Amendment to Agreement and Plan of Merger, dated as of June 22, 2016, among Lilis Energy, Inc., Lilis Merger Sub, Inc. and Brushy Resources, Inc. (incorporated herein by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on June 28, 2016).
3.1 Amended and Restated Articles of Incorporation of Recovery Energy, Inc., dated as of October 10, 2011 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on October 20, 2011).
3.2 Certificate of Amendment to the Amended and Restated Articles of Incorporation of Recovery Energy, Inc., dated as of November 18, 2013 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on November 19, 2013).
3.3 Certificate of Designation of Preferences, Rights, and Limitations of Series A 8% Convertible Preferred Stock, dated as of May 30, 2014 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 4, 2014).
3.4 Amendment to Certificate of Designation of Preferences, Rights, and Limitations of Series A 8% Convertible Preferred Stock, dated as of June 12, 2014 (incorporated herein by reference to Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, filed on June 17, 2014).
3.5 Certificate of Designation of Preferences, Rights and Limitations of 6% Redeemable Preferred Stock, dated as of August 29, 2014 (incorporated herein by reference to Exhibit 3.3 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2014, filed on November 26, 2014).
3.6 Certificate of Designation of Preferences, Rights and Limitations of Series B 6% Convertible Preferred Stock, dated as of June 15, 2016 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 16, 2016).
3.7 Certificate of Change of Lilis Energy, Inc., dated as of June 21, 2016 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 28, 2016).
3.8 Amended and Restated Bylaws (incorporated herein by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed on October 31, 2014).
4.1 Form of Warrant (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on January 28, 2014).
4.2 Form of Warrant (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on February 6, 2014).
4.3 Five Year Warrant to David Castaneda dated January 17, 2014 (incorporated herein by reference to Exhibit 4.1 to the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2014, filed on June 17, 2014).
4.4 Five Year Warrant (Anniversary Warrant) to David Castaneda dated January 17, 2014 (incorporated herein by reference to Exhibit 4.2 to the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2014, filed on June 17, 2014).
4.5 Form of Warrant dated May 30, 2014 (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on June 4, 2014).
4.6 Warrant to Purchase Common Stock issued to Bristol Capital (incorporated herein by reference to Exhibit 4.3 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2014, filed on November 26, 2014).
4.7 Warrant to Purchase Common Stock issued to Heartland Bank (incorporated herein by reference to Exhibit 4.3 to the Company’s Quarterly Report on Form 10-Q, filed on February 26, 2015).
4.8 Form of Convertible Note (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on January 5, 2016).
4.9 Form of Warrant (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on January 5, 2016).
4.10 Form of Common Stock Purchase Warrant (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on June 16, 2016).
4.11 Common Stock Purchase Warrant issued to SOSV Investments, LLC on June 23, 2016. (incorporated herein by reference to Exhibit 4.3 to the Company’s Quarterly Report on Form 10-Q filed on August 25, 2016).
4.12 Form of Warrant (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on February 28, 2017).
4.13 Form of Common Stock Certificate (incorporated herein by reference to Exhibit 4.1 to the Company’s Registration Statement on Form S-1 filed on September 16, 2016).
4.14† Lilis Energy, Inc. 2016 Omnibus Incentive Plan and forms of agreement thereunder (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on June 28, 2016).
4.15† First Amendment to the Lilis Energy, Inc. 2016 Omnibus Incentive Plan, approved on November 3, 2016 (incorporated herein by reference to Annex C to the Company’s Definitive Proxy filed on September 30, 2016).
10.1† Employment Agreement with Kevin Nanke, dated as of March 6, 2015 (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on March 12, 2015).
10.2† Employment Agreement with Ariella Fuchs, dated as of March 16, 2015 (incorporated herein by reference to Exhibit 10.84 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2014, filed on April 15, 2015).
10.3† Amended and Restated Employment Agreement between the Company and Abraham Mirman, dated as of March 30, 2015 (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 2, 2015).
10.4 Recovery Energy, Inc. 2012 Equity Incentive Plan dated August 31, 2012, as amended (incorporated herein by reference to Annex A to the Company’s definitive proxy filed on December 15, 2015).
10.5 Voting Agreement, dated as of December 29, 2015, among Lilis Energy, Inc., Lilis Merger Sub, Inc., Brushy Resources, Inc. and SOSventures, LLC (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 5, 2016).
10.6 Voting Agreement, dated as of December 29, 2015, among Lilis Energy, Inc., Lilis Merger Sub, Inc., Brushy Resources, Inc. and Longview Marquis Fund LP, LMIF Investments LLC and SMF investments, LLC (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on January 5, 2016).
10.7 Debenture Conversion Agreement, dated as of December 29, 2015, among Lilis Energy, Inc., T.R. Winston & Company, acting as placement agent, and each Debenture holder (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on January 5, 2016).

 

 

 

 

10.8 Form of Convertible Note Purchase Agreement (incorporated herein by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K filed on January 5, 2016).
10.9 Form of Note Exchange Agreement (incorporated herein by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K filed on January 5, 2016).
10.10 Form of Securities Purchase Agreement (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on June 16, 2016).
10.11 Form of Registration Rights Agreement (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on June 16, 2016).
10.12 Convertible Subordinated Promissory Note Conversion Agreement, dated as of June 23, 2016, among Lilis Energy, Inc. and the parties signatory thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on June 28, 2016).
10.13 First Amendment to the Convertible Subordinated Promissory Notes, dated as of August 3, 2016, among Lilis Energy, Inc. and the parties signatory thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on August 5, 2016).
10.14† Employment Agreement with Michael Pawelek, dated as of July 5, 2016 (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on July 8, 2016).
10.15† Employment Agreement with Edward Shaw, dated as of July 5, 2016 (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on July 8, 2016).
10.16† Employment Agreement with Abraham Mirman, dated as of July 5, 2016 (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on July 8, 2016).
10.17† Employment Agreement with Kevin Nanke, dated as of July 5, 2016 (incorporated herein by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on July 8, 2016).
10.18† Employment Agreement with Ariella Fuchs, dated as of July 5, 2016 (incorporated herein by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K filed on July 8, 2016).
10.19† Employment Agreement with Ronald Ormand, dated as of July 5, 2016 (incorporated herein by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K filed on July 8, 2016).
10.20 Transaction Fee Agreement, dated as of June 6, 2016, between Lilis Energy, Inc. and T.R. Winston & Company, LLC (incorporated herein by reference to Exhibit 10.12 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2016 filed on August 25, 2016).
10.21 First Amendment to Transaction Fee Agreement, dated as of June 8, 2016, between Lilis Energy, Inc. and T.R. Winston & Company, LLC (incorporated herein by reference to Exhibit 10.13 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2016 filed on August 25, 2016).
10.22 Escrow Deposit Agreement, dated as of May 26, 2016, by and among Lilis Energy, Inc., T.R. Winston & Company, LLC and Signature Bank (incorporated herein by reference to Exhibit 10.15 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2016 filed on August 25, 2016).
10.23 Texican Crude & Hydrocarbon LLC Purchase Contract, dated as of February 3, 2016, between Texican Crude & Hydrocarbon, LLC and Impetro Operating LLC (incorporated herein by reference to Exhibit 10.65 to Brushy Resources, Inc.’s Registration Statement on Form S-1 filed on September 16, 2016).
10.24 DCP Midstream, LP Gas Purchase Agreement (incorporated herein by reference to Exhibit 10.8 to Brushy Resources, Inc.’s Form 10/A filed on July 26, 2013, which became effective August 6, 2013).
10.25 Credit and Guarantee Agreement, dated as of September 29, 2016 by and among Lilis Energy, Inc., Brushy Resources, Inc., ImPetro Operating, LLC, ImPetro Resources, LLC, the Lenders party thereto and T.R. Winston & Company, LLC acting as collateral agent (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K/A filed on October 26, 2016).
10.26† Employment Agreement with Joseph C. Daches, dated as of January 23, 2017 (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 25, 2017).

10.27†

 

Employment Agreement with Brennan Short, dated as of January 27, 2017 (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 31, 2017).
10.28†* Employment Agreement with Seth Blackwell, dated as of December 1, 2016.
10.29† Separation and Release Agreement, dated February 13, 2017, between Kevin Nanke and Lilis Energy, Inc. (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 17, 2017).
10.30 Securities Subscription Agreement, dated February 28, 2017, by and among the Company and the Purchasers thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on March 2, 2017).
10.31 Registration Rights Agreement, dated February 28, 2017, by and among the Company and the Purchasers thereto (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on March 2, 2017).
21.1* List of Subsidiaries of the Company.
23.1* Consent of Marcum LLP, for the Company.
23.2* Consent of Cawley, Gillespie & Associates, Inc., independent petroleum engineers for the Company.
31.1* Certifications Pursuant to Section 302 of Sarbanes Oxley Act of 2002.
31.2* Certifications Pursuant to Section 302 of Sarbanes Oxley Act of 2002.
32.1* Certifications Pursuant to Section 906 of Sarbanes Oxley Act of 2002
32.2* Certifications Pursuant to Section 906 of Sarbanes Oxley Act of 2002
99.1* Report of Cawley, Gillespie & Associates, Inc., dated January 12, 2016, for the Company
101.INS*

XBRL Instance Document

101.SCH* XBRL Taxonomy Extension Schema Document
101.CAL* XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF* XBRL Taxonomy Extension Definition Linkbase Document
101.LAB* XBRL Taxonomy Extension Label Linkbase Document
101.PRE* XBRL Taxonomy Extension Presentation Linkbase Document

 

*Filed herewith.
Indicates management contract or compensatory plan.
+To be filed by amendment.

 

 

 

 

Report of Independent Registered Public Accounting Firm

 

To the Audit Committee of the

Board of Directors and Shareholders

of Lilis Energy, Inc. and Subsidiaries

 

We have audited the accompanying consolidated balance sheets of Lilis Energy, Inc. and Subsidiaries (the “Company”) as of December 31, 2016 and 2015, and the related consolidated statements of operations, changes in stockholders’ equity (deficit) and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

 

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Lilis Energy, Inc. and Subsidiaries, as of December 31, 2016 and 2015, and the consolidated results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

 

/s/ Marcum LLP

Marcum LLP

New York, NY

March 3, 2017

 

 F-1 

 

 

Lilis Energy, Inc. and Subsidiaries

Consolidated Balance Sheets

(In thousands, except share and per share data)

 

   December 31, 
   2016   2015 
ASSETS          
Current assets:          
Cash and cash equivalents  $11,738   $110 
Accounts receivables, net of allowance of $106 and $80, respectively   2,247    952 
Prepaid expenses and other current assets   767    79 
Total current assets   14,752    1,141 
Oil and gas properties, full cost method of accounting          
Unproved   24,461    - 
Proved   69,809    50,096 
Less: accumulated depreciation, depletion, amortization and impairment   (55,771)   (49,573)
Total oil and gas properties, net   38,499    523 
           
Other property and equipment, net   52    44 
Other assets   216    2,000 
Total other assets   268    2,044 
           
Total assets  $53,519   $3,708 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 F-2 

 

 

Lilis Energy, Inc. and Subsidiaries

Consolidated Balance Sheet

(In thousands, except share and per share data)

 

   December 31, 
   2016   2015 
         
LIABILITIES, REDEEMABLE PREFERRED STOCK AND STOCKHOLDERS' EQUITY          
Current liabilities:          
Accounts payable  $5,166   $1,331 
Accrued liabilities   2,706    3,496 
Dividends payable   808    719 
Asset retirement obligations   338    - 
Current portion of long-term debt   17    11,067 
Total current liabilities   9,035    16,613 
Asset retirement obligations   919    209 
Long-term debt   30,226    - 
Long-term derivative liabilities   1,400    56 
Total liabilities   41,580    16,878 
           
Commitments and contingencies (Note 9)          
Conditionally redeemable 6% preferred stock, $0.0001 par value, 7,000 shares authorized, 2,000 shares issued and outstanding with a liquidation preference of $2,240 at December 31, 2016.   1,874    1,173 
           
Stockholders’ Equity (Deficit):          
Series A Preferred stock, $0.0001 par value; stated rate $1,000:10,000 shares authorized, 0 and 7,500 shares issued and outstanding as of December 31, 2016 and 2015, respectively.   -    6,794 
Series B Preferred stock, $0.0001 par value; stated rate $1,000: 20,000 shares authorized; 17,000 and 0 shares issued and outstanding at December 31, 2016 and 2015, respectively, with a liquidation preference of $20,627 at December 31, 2016.   13,432    - 
Common stock, $0.0001 par value per share; 100,000,000 shares authorized, 20,918,901 and 2,786,275 shares issued and outstanding as of December 31, 2016 and 2015, respectively.   2    - 
Additional paid-in capital   219,837    159,773 
Accumulated deficit   (223,206)   (180,910)
Total stockholders’ equity (deficit)   10,065    (14,343)
           
Total liabilities, redeemable preferred stock and stockholders’ equity  $53,519   $3,708 

 

The accompanying notes are an integral part of these consolidated financial statements

 

 F-3 

 

 

Lilis Energy, Inc. and Subsidiaries

Consolidated Statements of Operations

(In thousands, except share and per share data)

 

   Years Ended December 31, 
   2016   2015 
         
Oil, natural gas and natural gas liquid sales  $3,435   $396 
           
Costs and expenses:          
Production costs   1,247    195 
Production taxes   (167)   28 
General and administrative   14,570    7,930 
Depreciation, depletion and amortization   1,566    574 
Accretion of asset retirement obligations   132    10 
Impairment of evaluated oil and gas properties   4,718    24,478 
Total operating expenses   22,066    33,215 
           
Loss from operations   (18,631)   (32,819)
           
Other income (expenses):          
Other income   90    3 
Debt conversion inducement expense   (8,307)   - 
Gain on extinguishment of debt   250    - 
Gain (loss) in fair value of derivative instruments   (1,222)   1,638 
Gain (loss) in fair value of conditionally redeemable 6% preferred stock   (701)   514 
Gain on modification of convertible debts   602    - 
Interest expense   (4,924)   (1,697)
Total other income (expenses)   (14,212)   458 
           
Net loss   (32,843)   (32,361)
Dividends on redeemable preferred stock   (407)   (120)
Loss on extinguishment of Series A Convertible Preferred Stock   (540)   - 
Dividend and deemed dividend Series B Convertible Preferred stock   (8,506)   (600)
Net loss attributable to common stockholders  $(42,296)  $(33,081)
           
Net loss per common share basic and diluted  $(3.73)  $(12.13)
Weighted average common shares outstanding:          
Basic and diluted   11,328,252    2,726,775 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 F-4 

 

 

Lilis Energy, Inc. and Subsidiaries

Consolidated Statements of Changes in Stockholders’ Equity (Deficit)

(In thousands, except share and per share data)

 

   Series A Preferred   Series B Preferred           Additional         
   Shares   Shares   Common Shares   Paid In   Accumulated     
   Shares   Amount   Shares   Amount   Shares   Amount   Capital   Deficit   Total 
                                     
Balance, January 1, 2015   7,500   $6,794    -   $-    2,699,273   $-   $155,101   $(147,829)  $14,066 
Issuances of common stock   -    -    -    -    87,002    -    365    -    365 
Fair value of warrants issued for professional services   -    -    -    -    -    -    425    -    425 
Fair value of warrants issued for bridge term loan   -    -    -    -    -    -    1,222    -    1,222 
Stock based compensation   -    -    -    -    -    -    2,660    -    2,660 
Dividend Preferred stockholders   -    -    -    -    -    -    -    (120)   (120)
Deemed dividend Series A Convertible Preferred Stock   -    -    -    -    -    -    -    (600)   (600)
Net loss   -    -    -    -    -    -    -    (32,361)   (32,361)
Balance, December 31, 2015   7,500    6,794    -    -    2,786,275    -    159,773    (180,910)   (14,343)
Stock based compensation   -    -    -    -    711,667    -    7,078    -    7,078 
Exercise of warrants   -    -    -    -    420,707    -    187    -    187 
Fair value of warrants issued for financing costs   -    -    -    -    -    -    713    -    713 
Issuance and repricing of warrants to induce conversion   -    -    -    -    -    -    8,307    -    8,307 
Gain on modification of convertible debentures   -    -    -    -    -    -    (602)   -    (602)
Fair value of warrants issued for debt discount   -    -    -    -    -    -    1,479    -    1,479 
Common stock issued for conversion of convertible notes and                                             
accrued interest   -    -    -    -    6,778,115    1    14,871    -    14,872 
Common stock and warrants issued in connection with the                                             
Brushy merger   -    -    -    -    5,785,119    -    7,111    -    7,111 
Series B Preferred stock issued for cash, net of fees   -    -    20,000    18,195    -    -    -    -    18,195 
Warrants issued for Series B Preferred Stock offering fees   -    -    -    (1,590)   -    -    1,590    -    - 
Common stock issued for conversion of Series A Preferred                                             
Stock and accrued dividends   (7,500)   (6,794)   -    -    1,500,000    1    7,681    -    888 
Loss on extinguishment of Series A Preferred Stock   -    -    -    -    -    -    540    (540)   - 
Common stock issued for conversion of Series B Preferred                                             
Stock and accrued dividends   -    -    (3,000)   (3,173)   2,937,018    -    3,230    -    57 
Dividends and deemed dividends for Preferred Stock   -    -    -    -    -    -    7,879    (8,913)   (1,034)
Net Loss   -    -    -    -    -    -    -    (32,843)   (32,843)
Balance, December 31, 2016   -   $-    17,000   $13,432    20,918,901   $2   $219,837   $(223,206)  $10,065 

   

The accompanying notes are an integral part of these consolidated financial statements.

 

 F-5 

 

 

Lilis Energy, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(In thousands)

 

   Years Ended December 31, 
   2016   2015 
Cash flows from operating activities:          
Net loss  $(32,843)  $(32,361)
Adjustments to reconcile net loss to net cash used in operating activities:          
Equity instruments issued for services and compensation   7,078    3,450 
Bad debt expense   494    - 
Inducement Expense   8,307    - 
Amortization of deferred financing cost   328    52 
Accretion of debt discount   2,857    - 
Gain on extinguishment of debt   (250)   - 
Gain (loss) in fair value of derivative instruments   1,222    (1,604)
Gain (loss) in fair value of conditionally redeemable 6% preferred stock   701    (514)
Gain on modification of convertible debt   (602)   - 
Depreciation, depletion, amortization and accretion of asset retirement obligation   1,698    584 
Impairment of evaluated oil and gas properties   4,718    24,478 
Changes in operating assets and liabilities:          
Accounts receivable   (1,264)   (120)
Other assets   1,554    57 
Accounts payable, accrued expenses and other liabilities   (307)   2,027 
Net cash used in operating activities   (6,309)   (3,951)
           
Cash flows from investing activities:          
Cash advance to Brushy Resources, Inc.   -    (1,750)
Cash consideration for Brushy merger, net of cash acquired   (2,302)   - 
Restricted cash   -    145 
Capital expenditures   (16,828)   (98)
Net cash used in investing activities   (19,130)   (1,703)
           
Cash flows from financing activities:          
Net proceeds from issuance of Series B Preferred Stock   18,195    - 
Proceeds from bridge notes, net   2,863    5,950 
Proceeds from warrant exercise   187    - 
Dividend payments on preferred stock   -    (180)
Debt issuance costs   (1,299)   (266)
Proceeds from issuance of term loan   31,000    - 
Repayment of debt   (13,879)   (250)
Net cash provided by financing activities   37,067    5,254 
Increase (decrease) in cash   11,628    (400)
Cash at beginning of period   110    510 
Cash at end of period  $11,738   $110 
Supplemental disclosure:          
Cash paid for interest  $762   $365 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 F-6 

 

 

Lilis Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

 

NOTE 1 – ORGANIZATION

 

On September 21, 2007, Universal Holdings, Inc. (“Universal”), a Nevada corporation, completed the acquisition of Coronado Acquisitions, LLC (“Coronado”). Under the terms of the acquisition, Coronado was merged into Universal. On October 12, 2009, Universal changed its name to Recovery Energy, Inc. On December 1, 2013, Recovery Energy, Inc. changed its name to Lilis Energy, Inc. (“Lilis”, “Lilis Energy” and the “Company”).

 

The Company is an independent oil and gas exploration and production company focused on the Delaware Basin in Winkler and Loving Counties, Texas and Lea County, New Mexico and the Denver-Julesburg Basin (“DJ Basin”) in Wyoming, Colorado, and Nebraska.

 

On June 23, 2016, the Company effected a 1-for-10 reverse stock split of its Common Stock (the “Reverse Split”). The accompanying consolidated financial statements and these notes to the consolidated financial statements give retroactive effect to the Reverse Split for all periods presented.

 

All references to production, sales volumes and reserves quantities are net to the Company’s interest unless otherwise indicated.

 

NOTE 2 – MANAGEMENT PLANS AND LIQUIDITY

 

The Company has reported net operating losses during the year ended December 31, 2016 and for the past five years. As a result, the Company funded its operations in 2016 and the merger with Brushy Resources, Inc. through additional debt and equity financing. On September 29, 2016, the Company entered into a new Credit and Guaranty Agreement (the “Credit Agreement”) that provides for a three-year, senior, secured term loan with initial aggregate principal commitments of $31 million and a maximum facility size of $50 million. The term loan was funded in two draws, with $25 million collected as of September 30, 2016 and the additional $6 million collected as of November 11, 2016.

 

As of December 31, 2016, the Company had a working capital balance and a cash balance of approximately $5.7 million and $11.7 million, respectively. As of March 1, 2017, the Company’s cash balance was approximately $9.0 million, which included a drawdown of additional principal under its Credit Agreement on February 7, 2017 of $7.1 million and excluded net proceeds of the equity offering completed on March 1, 2017, or approximately $18.6 million. The Company believes that it will have sufficient capital to operate over the next 12 months from the date of the filing of this annual report. However, it is possible that the Company will seek to raise additional debt, equity capital, or both depending on the pace of its drilling and leasing activity.

 

NOTE 3 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND ESTIMATES

 

Principles of Consolidation

 

The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. The Company’s wholly owned subsidiaries include Brushy Resources, Inc (“Brushy”), ImPetro Operating, LLC (“ImPetro Operating”) and ImPetro Resources, LLC (“ImPetro”), and Lilis Operating Company, LLC (“Lilis Operating”). All significant intercompany accounts and transactions have been eliminated in consolidation.

 

Use of Estimates

 

The preparation of consolidated financial statements in conformity with generally accepted accounting principles in the United States (“U.S. GAAP”) requires the Company to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities; disclosure of contingent assets and liabilities at the date of the financial statements; the reported amounts of revenues and expenses during the reporting period; and the quantities and values of proved oil, natural gas and NGL reserves used in calculating depletion and assessing impairment of its oil and gas properties.

 

 F-7 

 

 

The most significant financial estimates are associated with the Company’s estimated volumes of proved oil and natural gas reserves, asset retirement obligations, assessments of impairment imbedded in the carrying value of undeveloped acreage and undeveloped properties, fair value of financial instruments, including derivative liabilities, depreciation and accretion, income taxes and contingencies. Although management believes that these estimates are reasonable, actual results could differ significantly from those estimates.

 

Reclassifications

 

Certain prior-period amounts have been reclassified for comparative purposes to conform with the fiscal 2016 presentation. These reclassifications have no effect on the Company’s previously reported results of operations.

 

Cash and Cash Equivalent

 

Cash and cash equivalents include highly liquid instruments with an original maturity of three months or less when purchased to be cash equivalents as these instruments are readily convertible to known amounts of cash and do not bear significant risk of changes in value due to their short maturity period.

 

Accounts Receivable

 

The Company records actual and estimated oil and gas revenue receivable from third parties at its net revenue interest. The Company also reflects costs incurred on behalf of joint interest partners. The Company typically has the right to withhold future revenue disbursements to recover outstanding joint interest billings on outstanding receivables from joint interest owners. Management periodically reviews accounts receivable amounts for collectability and records its allowance for uncollectible receivables using the allowance method based on past experience. Allowance for doubtful accounts are based primarily on joint interest billings for expenses related to oil and natural gas wells. Receivables which derive from sales of certain oil and gas production are collateral under the Company’s Credit Agreement.

 

Concentration of Credit Risk

 

The Company’s cash is invested at major financial institutions primarily within the United States. At December 31, 2016 and 2015, the Company’s cash was maintained in accounts that are insured up to the limit determined by the federal governmental agency. The Company may at times have balances in excess of the federally insured limits. Periodically, the Company evaluates the creditworthiness of the financial institutions, and has not experienced any losses in such accounts.

 

Significant Customers

 

The Company’s major customers include, Noble Energy, Texican and Energy Transfer, Inc. These customers accounted for approximately 41%, 38% and 16% of the Company’s revenue for the year ended December 31, 2016. The Company’s major customers include, Shell Trading (US), PDC Energy and Noble Energy, which accounted for approximately 43%, 26% and 21% of its revenue for the year ended December 31, 2015.

 

However, the Company believe that the loss of a single purchaser could not materially affect the Company’s business because alternative purchasers are available.

 

Reserves

 

All of the reserves data included herein are estimates. Estimates of the Company’s crude oil and natural gas reserves are prepared in accordance with guidelines established by the Securities Exchange Commission (“SEC”), including rule revisions designed to modernize the oil and gas company reserves reporting requirements, which the Company implemented effective December 31, 2010. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Uncertainties include the projection of future production rates and the expected timing of development expenditures. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserves estimates may be different from the quantities of crude oil and natural gas that are ultimately recovered. In addition, the ability to produce economic reserves is dependent on the oil and gas prices used in the reserves estimate. The Company’s reserves estimates are based on 12-month average commodity prices, unless contractual arrangements otherwise designate the price to be used, in accordance with the SEC rules. However, oil and gas prices are volatile and, as a result, the Company’s reserves estimates may change in the future.

 

 F-8 

 

  

Estimates of proved crude oil and natural gas reserves significantly affect the Company’s depreciation, depletion, and amortization (“DD&A”) expense. For example, if estimates of proved reserves decline, the DD&A rate will increase, resulting in a decrease in net income. A decline in estimates of proved reserves could also result in an impairment charge, which would reduce earnings.

 

Oil and Gas Properties

 

The Company uses the full cost method of accounting for oil and gas operations. Under this method, costs related to the exploration, non-production related development and acquisition of oil and natural gas reserves are capitalized. Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling, developing and completing productive wells and/or plugging and abandoning non-productive wells, and any other costs directly related to acquisition and exploration activities. Proceeds from property sales are generally applied as a credit against capitalized exploration and development costs, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of proved reserves.

 

The Company accounts for its unproven long-lived assets in accordance with Accounting Standards Codification (“ASC”) Topic 360-10-05, Accounting for the Impairment or Disposal of Long-Lived Assets. ASC Topic 360-10-05 requires that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the historical cost carrying value of an asset may no longer be appropriate.

 

Depletion of exploration and development costs and depreciation of wells and tangible production assets is computed using the units-of-production method based upon estimated proved oil and gas reserves. Costs included in the depletion base to be amortized include (a) all proved capitalized costs including capitalized asset retirement costs net of estimated salvage values, less accumulated depletion, (b) estimated future development cost to be incurred in developing proved reserves; and (c) estimated decommissioning and abandonment/restoration costs, net of estimated salvage values, that are not otherwise included in capitalized costs.

 

Costs associated with undeveloped acreage are excluded from the depletion base until it is determined whether proved reserves can be assigned to the properties. When proved reserves are assigned to such properties or one or more specific properties are deemed to be impaired, the cost of such properties is added to full cost pool which is subject to depletion calculations.

 

Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the sum of the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves and the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are not subject to amortization. Should capitalized costs exceed this ceiling, an impairment expense is recognized. During 2016, commodity prices continued to trade in a low range. With low commodity prices sustained for the majority of 2016 in the DJ Basin, some of the Company’s properties became uneconomic triggering an impairment charge of $4.7 million at December 31, 2016. Due to the decline in commodity prices and lack of liquidity the Company recorded an impairment charge during the year ended December 31, 2015. During the years ended December 31, 2016 and 2015, the Company recorded $4.7 million and $24.5 million impairment charges, respectively.

 

The present value of estimated future net cash flows was computed by applying: a flat oil price to forecast revenues from estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves (assuming the continuation of existing economic conditions), less any applicable future taxes.

 

Wells in Progress

 

Wells in progress connotes wells that are currently in the process of being drilled or completed or otherwise under evaluation as to their potential to produce oil and gas reserves in commercial quantities. Such wells continue to be classified as wells in progress and withheld from the depletion calculation and the ceiling test until such time as either proved reserves can be assigned, or the wells are otherwise abandoned. Upon either the assignment of proved reserves or abandonment, the costs for these wells are then transferred to the full cost pool and become subject to both depletion and the ceiling test calculations in accordance with full cost accounting under Rule 4-10 of Regulation S-X of the Securities Exchange Act of 1934, as amended.

 

 F-9 

 

  

Other Property and Equipment

 

Property and equipment include office equipment and furniture which are stated at cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets. The estimated useful lives of property and equipment range from three to seven years. The Company recorded approximately $0.04 million and $0.03 million of depreciation for the years ended December 31, 2016 and 2015, respectively.

 

Impairment of Long-lived Assets

 

The Company accounts for long-lived assets (other than oil and gas properties) at cost. The Company may impair these assets whenever events or changes in circumstances indicate that the carrying amount of such assets may not be fully recoverable. Recoverability is measured by comparing the carrying amount of an asset to the expected undiscounted future net cash flows generated by the asset. If it is determined that the asset may not be recoverable, and if the carrying amount of an asset exceeds its estimated fair value, an impairment charge is recognized to the extent of the difference.

 

Asset Retirement Obligation

 

The Company incurs retirement obligations for certain assets at the time they are placed in service. The fair values of these obligations are recorded as liabilities on a discounted basis. The costs associated with these liabilities are capitalized as part of the related assets and depreciated. Over time, the liabilities are accreted for the change in their present value. For purposes of depletion calculations, the Company includes estimated dismantlement and abandonment cost, net of salvage values, associated with future development activities that have not yet been capitalized as asset retirement obligations. Asset retirement obligations incurred are classified as Level 3 (unobservable inputs) fair value measurements. The asset retirement liability is allocated to operating expense using a systematic and rational method.

 

Fair Value of Financial Instruments

 

As of December 31, 2016 and 2015, the carrying value of cash and cash equivalents, accounts receivable, accounts payable, accrued expenses, interest and dividends payable and advance from joint interest partners approximates fair value due to the short-term nature of such items. The carrying value of the Company’s secured debt is carried at cost which is approximately the fair value of the debt as the related interest rate are at the terms approximates rates currently available to the Company.

 

Revenue Recognition

 

The Company recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller's price to the buyer is fixed or determinable and (iv) collectability is reasonably assured.

 

The Company uses the entitlements method of accounting for oil, NGLs and gas revenues. Sales proceeds in excess of the Company's entitlement are included in other liabilities and the Company's share of sales taken by others is included in other assets in the accompanying consolidated balance sheets. The Company had no material oil, NGL or gas entitlement assets or liabilities as of December 31, 2016 or 2015.

Stock Based Compensation

 

The Company measures the fair value of stock-based compensation expense awards made to employees and directors, including stock options, restricted stock units, and restricted stock, on the date of grant using a Black-Scholes model. For equity awards, compensation expense is based on the fair value on the grant or modification date and is recognized in the Company’s financial statements over the vesting period. The measurement of share-based compensation expense is based on several criteria, including but not limited to, the valuation model used and associated input factors, such as expected term of the award, stock price volatility, risk free interest rate, dividend rate and award cancellation rate. These inputs are subjective and are determined using management’s judgment. If differences arise between the assumptions used in determining share-based compensation expense and the actual factors, which become known over time, the Company may change the input factors used in determining future share-based compensation expense.

 

The Company accounts for warrant grants to nonemployees whereby the fair values of such warrants are determined using the option pricing model at the earlier of the date at which the nonemployee’s performance is complete or a performance commitment is reached.

 

 F-10 

 

  

Warrant Modification Expense

 

The Company accounts for the modification of warrants as an exchange of the old award for a new award. The incremental value is measured as the excess, if any, of the fair value of the modified award over the fair value of the original award immediately before modification, and is either expensed as a period expense or amortized over the performance or vesting date. The Company estimates the incremental value of each warrant using the Black-Scholes option pricing model. The Black-Scholes model is highly complex and dependent on key estimates by management. The estimate with the greatest degree of subjective judgment is the estimated volatility of the Company’s stock price.

 

Earnings (Loss) Per Share

 

Basic income (loss) per share was calculated by dividing net income or loss applicable to common shares by the weighted average number of common shares outstanding during the periods presented. The calculation of diluted income (loss) per share should include the potential dilutive impact of shares issuable upon the conversion of debt or preferred stock, vested restricted stock and exercise of warrants and options during the period, unless their effect is anti-dilutive. At December 31, 2016 and 2015, shares underlying restricted stock units, restricted stock, options, warrants, preferred stock and debentures have been excluded from the diluted share calculations as they were anti-dilutive as a result of net losses incurred. The Company has included 3,522,735 warrants, with an exercise price of $.01, in its earnings per share calculation for the year ended December 31, 2016.

 

The Company had the following shares of Common Stock equivalents at December 31, 2016 and 2015:

 

   December 31, 
   2016   2015