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, 2017

 

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:

 

Common Stock, $0.0001 par value   NYSE American
Title of class   Name of exchange on which registered

 

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

 

None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes   ¨   No  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 x
Non-accelerated filer    ¨ Smaller reporting company x
Emerging growth company ¨    

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

 

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, 2017, 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 $186,032,195 based on the closing sales price of $4.90 per share of the registrant’s common stock on June 30, 2017 on the NYSE American.

 

As of March 5, 2018, 53,496,205 shares of the registrant’s common stock were issued and outstanding.

 

 

 

 

  

FORM 10-K ANNUAL REPORT

YEAR ENDED DECEMBER 31, 2017

LILIS ENERGY, INC.

 

    Page
PART I
 
Special Note regarding Forward Looking Statements
Items 1 and 2. Business and Properties 4
Item 1A. Risk Factors 19
Item 1B. Unresolved Staff Comments 33
Item 3. Legal Proceedings 33
Item 4. Mine Safety Disclosures 33
     
PART II
 
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 34
Item 6. Selected Financial Data 35
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 35
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 50
Item 8. Financial Statements and Supplementary Data 50
Item 9. Changes in and disagreements with Accountants on Accounting and Financial Disclosure 50
Item 9A. Controls and Procedures 50
Item 9B. Other Information 51
     
PART III
 
Item 10. Directors, Executive Officers and Corporate Governance 51
Item 11. Executive Compensation 57
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 78
Item 13. Certain Relationships and Related Transactions, and Director Independence 83
Item 14. Principal Accounting Fees and Services 86
     
PART IV
 
Item 15. Exhibits, Financial Statement Schedules 90
Item 16.  Form 10-K Summary 90

 

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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

 

This Annual Report on Form 10-K (this “Annual Report”) contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. Forward-looking statements may include the words “may,” “should,” “could,” “estimate,” “intend,” “plan,” “project,” “continue,” “believe,” “predict,” “expect,” “anticipate,” “goal,” “forecast,” “target” or other similar words.

 

All statements, other than statements of historical fact, that are included in this Annual Report that address activities, events or developments that we expect or anticipate will or may occur in the future are forward-looking statements,” 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; commodity price risk management activities and the impact on our average realized price; and any statements of assumptions underlying any of the foregoing.

 

Although we believe that the expectations, plans, and intentions reflected in or suggested by any of our forward-looking statements are reasonable, we can give no assurance that these plans, intentions, or expectations will be achieved, and the actual results could differ materially from those projected or assumed in any of our forward-looking statements.

 

Our future financial condition and results of operations, as well as any forward-looking statements, are subject to inherent risks and uncertainties, many of which are beyond our control. Some of the factors, which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include but are not limited to, the Risk Factors set forth in this Annual Report in Part I, “Item 1A. Risk Factors.”

 

Should one or more of the risks or uncertainties described in this Annual Report Form occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those in any forward-looking statements.

 

These forward-looking statements present our estimates and assumptions only as of the date of this Annual Report. Except as required by law, we specifically disclaim all responsibility to publicly update any information contained in any forward-looking statement and, therefore, disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by this cautionary statement.

 

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 website of the Securities Exchange Commission (the “SEC”) - www.sec.gov.

 

 3 

 

  

PART I

 

Items 1. Business and Properties

 

Overview

 

Lilis is an independent oil and gas company focused on the exploration, acquisition, development, and production of oil and natural gas reserves from properties in the Permian Basin. Our operations are focused in the Delaware Basin of the Permian in Winkler, Loving, and Reeves Counties, Texas and Lea County, New Mexico.

 

Our Business

 

Lilis was incorporated in the State of Nevada in 2007 as “Universal Holdings, Inc.” The name of the corporation was changed to “Recovery Energy, Inc.” in October 2009 and changed to “Lilis Energy, Inc.” in December 2013.

 

On June 23, 2016, we completed a merger transaction with Brushy Resources, Inc. (“Brushy Resources” or “Brushy”). The merger resulted in the acquisition of our initial properties in the Delaware Basin. In connection with the merger with Brushy Resources, 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. Subsequently, on March 31, 2017, we completed the divestiture of all our oil and gas properties located in the Denver-Julesburg Basin (the “DJ Basin”), completing our transformation to a pure play Permian Basin oil and natural gas company.

 

We intend to grow our company through generating cash flow from new production of oil, natural gas and natural gas liquids (“NGL”), as well as through de-risking the development profile of our portfolio of properties in order to add overall value. We believe that horizontal development of our properties will provide attractive returns on a majority of our acreage positions. We believe our significant inventory of oil and liquids-rich drilling opportunities in the Delaware Basin provides us with a platform for continued growth. As of December 31, 2017, we had accumulated approximately 35,200 gross (15,700 net) acres that we believe to be in the core of the Delaware Basin, with approximately 33,080 gross (14,430 net) acres in Winkler, Loving, and Reeves Counties, Texas and approximately 2,120 gross (1,270 net) acres in Lea County, New Mexico. Our leasehold position is largely contiguous, which we believe gives us significant control over the pace of our development and the ability to design an efficient and profitable drilling program that maximizes recovery of hydrocarbons.

 

Shortly after our merger with Brushy Resources, we commenced a development program to delineate and de-risk our properties by drilling of new horizontal wells across multiple potentially productive formations. Our drilling program utilizes the development of new horizontal wells across several potentially productive formations in the Delaware Basin. We commenced our drilling program in 2016, when we drilled two wells, which were completed in 2017. In 2017, we drilled eight wells on our leases and completed five of these wellbores, which targeted the Wolfcamp formation for initial development.

 

As a result of our development activity, our proved reserves increased to approximately 11,453 MBOE (million barrels of oil equivalent) as of December 31, 2017. Our proved reserves as of that date consisted of 63% oil, 23% natural gas and 14% NGL. Of those reserves, 37% of our proved reserves are classified as proved developed and approximately 63% are classified as proved undeveloped.

 

In addition, 34% of our net acreage position was held by production, and we operated approximately 90% of our acreage, which we believe gives us significant control over the pace of our development and the ability to design a more efficient and profitable drilling program to maximize recovery of oil and natural gas.

 

In 2017, we also entered into a long-term gas gathering, processing and purchase agreement with an affiliate of Lucid Energy Group (“Lucid”) to support our active drilling program in the Delaware Basin. Lucid will receive, gather and process our gas production from certain production areas located in Lea County, New Mexico and Winkler and Loving Counties, Texas. The agreement secures sufficient term and capacity for Lilis during our development and exploitation life cycle of the production areas committed to the new agreement.

  

We expect that substantially all of our estimated 2018 capital expenditure budget will be focused on the development and expansion of our Delaware Basin acreage and operations in order to further delineate the prospectivity of Wolfcamp and Bone Spring development on our properties. We also plan to continue selectively and opportunistically pursuing strategic acreage acquisitions and organic leasing prospects in the Delaware Basin.

 

 4 

 

  

Our Business Strategy

 

Our business objective is to increase stockholder value by growing our leasehold position, reserves, production and cash flows at attractive rates of return on invested capital. We continue to focus on developing our existing acreage position, gaining additional operational control and expanding our core assets in the Delaware Basin. We plan to achieve our business objective by implementing a business strategy focused on the following:

 

  · Execute our Operated, Horizontal Drilling Program to Grow Production from our Delaware Basin Leasehold. We plan to drill and develop our existing acreage base of approximately 35,800 gross (16,200 net) acres in the Delaware Basin, which we believe will maximize our resource potential and value to our stockholders. Through the development of our properties, we seek to de-risk our acreage position 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, which we believe includes at least seven productive zones. We estimate that all productive zones within our properties may support approximately 900 future drilling locations, including over 400 longer lateral locations, and we expect that inventory to increase with the closing of our pending acquisition from OneEnergy Partners Operating, LLC. We focused our horizontal development in 2017 on the Wolfcamp B formation but intend to expand our target zones to the Wolfcamp A, Wolfcamp XY and 2nd Bone Spring during 2018. Our long-term gas gathering, processing and purchase agreement with Lucid will support our active drilling program and alleviate production constraints we have experienced.

 

  · Focus on Delineation of our Existing Acreage. We plan to focus on the delineation and de-risking of our existing acreage. We expect that our drilling activity will also grow our drilling inventory and the identified resource potential of our Delaware Basin properties. We believe that our current reserves represent only a small portion of the resource potential within our acreage. Our development plan for 2018 contemplates the continued delineation of our acreage both geographically and geologically by testing our eastern acreage and by drilling and completing wells within additional prospective benches, including the Wolfcamp A, Wolfcamp XY and the 2nd Bone Spring.

 

  · Leverage our Extensive Operational Expertise to Reduce Costs and Enhance Returns. As of December 31, 2017, we operated approximately 90% of our acreage position, giving us significant control over the pace of our development and allowing us to increase value through operational and cost efficiencies. We intend to obtain the highest possible returns on the capital we expend on our development projects using results from the wells we have completed and the operational expertise of our management team. We also plan to focus on operational efficiencies, including salt water disposal and midstream costs, and capital costs of our development wells in order to maximize returns to our stockholders.

 

  · Pursue Selective Acquisitions and Organic Leasing to Grow Our Leasehold Position. Since entering the Delaware Basin in June 2016, we have grown our net acreage position approximately 376% from 3,400 net (7,200 gross) acres to approximately 16,200 net (35,800 gross) acres at March 1, 2018. On January 30, 2018, we announced our entry into a pending Purchase and Sale Agreement with OneEnergy Partners Operating, LLC to acquire 2,798 net acres in New Mexico, which are largely overlapping or contiguous with our existing properties, for approximately $70 million (the “OEP Acquisition”).  Pro forma for the closing of the OEP Acquisition, we expect our acreage position to approximate 19,000 net acres.  Our most significant acquisition in 2017 included approximately 4,400 net acres, approximately 92% of which overlapped our existing acreage position. Our acquisitions to date have added approximately 600 drilling locations with multiple stacked pay zones. In addition to our continued evaluation of strategic acquisition opportunities in the Delaware Basin, we will continue to expand our leasehold position through our organic leasing program.

 

  · Maintain Fiscal Discipline and Financial Liquidity. We actively manage the level of our development, leasing and acquisition activity in response to commodity prices, access to capital, and to the performance of our wells. We hold significant control over the pace of our drilling activity as a result of our operatorship on approximately 90% of our properties. During 2017, we commenced an active hedging program to provide certainty regarding our cash flow and protect returns from our development activity in the event of decreases in the prices received for our production. In addition, we have structured our balance sheet with the intent to reduce our leverage profile over time. The Second Lien Term Loan (as defined below) that we primarily relied upon to finance our capital spending and operations in 2017 is convertible, and we announced the issuance of $100 million in convertible, perpetual Series C preferred stock on January 31, 2018.  In addition, the closing of our recently announced OEP Acquisition, which carries a purchase price of approximately $70 million, will be funded in part with $30 million of common stock to be issued to the seller.

 

Our Strengths

 

  · Pure Play Permian Focus with Established Acreage Position in the Core of the Delaware Basin. We believe we have assembled a substantial portfolio of Delaware Basin properties that offers significant exploration and low-risk development opportunities, including one of the highest rates of return among formations in North America. As of March 1, 2018, we hold over 35,800 gross (16,200 net) acres in the core of the Delaware Basin, with an average working interest per well of approximately 66%. In addition, 35% of our acreage position is held by production, and we operate approximately 90% of our acreage, which we believe gives us significant control over the pace of development and the ability to design a more efficient and profitable drilling program to maximize recovery of oil and natural gas. Based on our drilling and production results to date and well-established offset operator activity in and around our project areas, we believe there are relatively low geologic risks and ample repeatable drilling opportunities across our core acreage.

 

  · Multi-year Portfolio of Drilling and Development Opportunities. We have a significant inventory of drilling and development locations in Winkler, Loving and Reeves Counties, Texas and Lea County, New Mexico. We believe our properties form part of the core of the Delaware Basin. Based on our drilling to date and results from nearby wells, we have identified more than 900 horizontal well locations on our acreage, including approximately 400 longer lateral locations, exclusive of the acreage to be acquired pursuant to the pending OEP Acquisition. We believe that inventory of drilling locations will allow us to grow our reserves and production at attractive rates of return based on current expectations for commodity prices.

 5 

 

 

  · Contiguous Acreage Position Provides Operating Leverage and Consolidation Opportunities. Our geographically-concentrated acreage position allows us to capitalize on economies of scale with respect to drilling and production costs. Our leasehold position is highly contiguous, and we held operatorship on approximately 90% of our properties at December 31, 2017, enabling us to maximize our development efficiency and manage our costs. In addition, we believe those efficiencies provide us with an advantage in competing for acquisitions and organic leasing opportunities on and around our acreage. On January 31, 2018, we announced our pending OEP Acquisition, pursuant to which we expect  to acquire 2,798 net acres comprised of working interests that overlap or are contiguous to our existing properties in Lea County, New Mexico. We expect that we will continue to see opportunities for accretive acquisitions where we may benefit from current and potential economies of scale going forward.

  

·Strong Financial Position and Liquidity. We believe our financial position is strong and provides the financial flexibility to fund our currently planned 2018 capital expenditures. On January 31, 2018, we announced our entry into a new $50 million, three-year term loan with Riverstone Credit Partners, LLC, that refinanced our existing first-lien bridge loan and provided approximately $18 million in net proceeds, and the concurrent issuance of $100 million in convertible, perpetual Series C preferred stock to Varde Partners, Inc. We expect to use $40 million in proceeds from the preferred stock issuance to fund the closing of the OEP Acquisition and to use remaining net proceeds from both financings to fund our planned 2018 capital expenditures. The remainder of the $70 million purchase price for the OEP Acquisition will be funded from the issuance of common stock to the sellers. We believe this financial liquidity and flexibility will result in continued growth in our oil and natural gas production, proved reserves, and cash flows.

 

  · Experienced Management Team. We have an experienced and skilled management team with a long track record of driving growth through asset development and strategic acquisitions. Our management team holds 105 years of collective experience in the oil and gas industry, with a significant amount of such experience being in the Permian Basin. We believe that our team’s experience through various commodity price cycles and operational expertise position us to operate effectively and efficiently and will help us to increase our returns and value to our stockholders.

 

Business Segments

 

Our operations are all oil and natural gas exploration and production related activities in the United States.

 

Summary of Oil and Natural Gas Properties and Projects

 

We are engaged in oil and natural gas acquisition, exploration, development and production, with all of our oil and natural gas properties being located in the Delaware Basin in Winkler, Loving, and Reeves Counties, Texas and Lea County, New Mexico.

 

As of December 31, 2017, we owned leasehold in approximately 35,200 gross (15,700 net) acres in the Delaware Basin, comprised of approximately 14,430 net acres in Winkler, Loving, and Reeves Counties, Texas and approximately 1,270 net acres in Lea County, New Mexico.

 

Of these properties, approximately 8,300 gross (5,300 net) acres were classified as developed and held by production and the remaining approximately 26,900 gross (10,400 net) acres we classified as undeveloped. We currently estimate our properties include at least seven productive zones and hold approximately 900 future drilling locations across all of the productive zones within this position. Our reserve estimates include 20 horizontal PUD wells, as well as the capital costs required to develop these wells.

 

Reserve Data

 

Reserve Estimates

 

Our reserve data and estimates were compiled and prepared internally and audited by third party independent consultants, Cawley, Gillespie & Associates, Inc. (“CG&A”), as described in more detail herein, in compliance with SEC definitions and guidance and in accordance with generally accepted petroleum engineering principles.

 

Internal Controls over Reserves Estimate

 

Our policy regarding internal controls over the recording of reserves is structured to objectively and accurately estimate our oil and gas reserve quantities and values in compliance with the regulations of the SEC. Responsibility for compliance in reserve bookings is delegated to our Chief Financial Officer with assistance from our senior geologist and a senior reservoir engineer. We have a Reserves Committee to provide additional oversight of our reserves estimation and certification process. The members of the Reserves Committee currently consist of Ron Ormand, our Executive Chairman, and Glenn Dawson, a member of our Board of Directors. Mr. Dawson serves as the Chairman of the Reserves Committee.

 

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Technical reviews are performed throughout the year by our senior reservoir engineer and our senior geologist and other consultants who evaluate all available geological and engineering data, under the guidance of our appropriate executive officer(s). This data, in conjunction with economic data and ownership information, is used in making a determination of estimated proved reserve quantities. The 2017 and 2016 reserve processes were overseen by Chris Cantrell, our senior reservoir engineer. 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

 

Our independent third-party consultant, CG&A, performed reserve studies as of December 31, 2017 and 2016, using its own engineering assumptions and other economic data provided by us. All of our total calculated proved reserve 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, 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 State of Texas. He is also a member of the Society of Petroleum Engineers. Mr. Brooker and the other technical persons employed by CG&A engaged in the reserve study met the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Natural Gas Reserves Information promulgated by the Society of Petroleum Engineer.

 

Oil and natural 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 natural 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, 2017 and 2016, we based the estimated discounted future net cash flows from proved reserves on the 12-month average oil and natural gas index prices, calculated as the un-weighted arithmetic average for the first-day-of-the-month price for each month and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties.

 

In addition to a third-party reserve study, our reserves and the corresponding report, along with the process for developing such estimates, are reviewed by our geologist and the Audit Committee of our Board of Directors to ensure compliance with SEC disclosure and internal control requirements and to verify the independence of the third-party consultants. The Audit Committee of our Board of Directors reviews the final reserves estimate in conjunction with CG&A’s audit letter.

 

Actual quantities of reserves recovered will most likely vary from the estimates set forth below. Reserves and cash flow estimates rely on interpretations of data and require assumptions that may be inaccurate. For a discussion of these interpretations and assumptions, see " Any significant inaccuracies in these reserves estimates or underlying assumptions will materially affect the quantities and present value of our reserves” under Item 1A, "Risk Factors," of this Annual Report. See "Supplementary Information on Oil and Natural Gas Exploration, Development and Production Activities" to our consolidated financial statements in Item 15 of this Annual Report for additional reserves disclosures.

 

Estimates of Proved Reserves

 

The table below summarizes our estimates of proved reserves at December 31, 2017.

 

  

Oil

(MBbl)

   Natural Gas
(MMcf)
   NGLs  
(MBbl)
   Total
(MBOE)
 
                 
Proved Developed Reserves   2,531    6,594    645    4,275 
Proved Undeveloped Reserves   4,640    9,466    960    7,178 
Total Proved Reserves   7,171    16,060    1,605    11,453 

 

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Total Proved Reserves

 

Our estimates of proved reserves and related standardized measure of future net cash flows and PV-10 as of December 31, 2017 are calculated based upon SEC pricing, which uses a twelve-month unweighted average of first-day-of-the-month oil and natural gas benchmark prices, adjusted for marketing and other differentials and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. SEC pricing for crude oil, natural gas and NGLs has been volatile since December 2014, and any future changes in oil and natural gas pricing will impact future estimated proved reserve volumes.

 

Our year-end 2017 proved reserves of 11,453 MBOE consisted of 4,275 MBOE proved developed, and 7,178 MBOE proved undeveloped reserves. For 2017, crude oil reserves increased to 6,620 MBbls to 7,131 MBbls from 551 MBbls at December 31, 2016, while NGL reserves increased to 1,605 MBbls from 3 MBbls at December 31, 2016. At December 31, 2017, our proved natural gas reserves increased 12,188 MMcf to 16,060 Mcf from 3,872 MMcf at December 31, 2016. At year-end 2017, all our proved reserves were located in the Delaware Basin.

 

At December 31, 2017, the SEC pricing for oil was $51.34 per barrel, a 20% increase compared to the prior year end price of $42.75 per barrel, and pricing for natural gas was $2.98 per MMBtu, a 21% increase compared to the prior year end price of $2.46 per MMBtu. Our total proved reserves increased by 10,253 MBOE; 10,654 MBOE in extensions, discoveries and other additions and 331 MBOE in revisions offset by a 732 MBOE reduction in proved reserves from production and the sale of reserves in 2017.

  

Proved Undeveloped Reserves

 

During 2017, we added 7,178 MBOE of proved undeveloped (“PUD”) reserves through the extension of proved acreage, primarily as a result of successful drilling on properties in the core of the Delaware Basin in Winkler, Loving, and Reeves Counties, Texas and Lea County, New Mexico.

 

Estimates of proved undeveloped reserve quantities are limited by development drilling activity that we intend to undertake during the 2018 to 2022 timeframe. For additional information regarding the changes in our proved reserves, see our "Supplementary Information on Oil and Natural Gas Exploration, Development and Production Activities" to our consolidated financial statements in Item 15 of this Annual Report.

 

Production History

 

The following table summarizes the average volumes and realized prices of oil and natural gas produced from properties during the periods indicated, and production cost per BOE:

 

   For the Years Ended December 31,
   2017  2016
Product      
Oil (Bbls)-net production   371,993    61,088 
Oil (Bbls)-average realized price  $47.92   $39.59 
           
Natural Gas (MCF)-production   776,164    332,643 
Natural Gas (MCF)-average realized price  $2.74   $2.54 
           
Natural gas liquids (Bbls)-net production   73,875    11,355 
Natural gas liquids (Bbls)-average realized price  $22.49   $15.22 
           
Barrels of oil equivalent (BOE)   575,229    127,863 
Average daily net production (BOE)   1,576    350 
Average Price per BOE  $37.57   $26.87 

 

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

 

   For the Years Ended December 31,
   2017  2016
Production costs per BOE  $12.21   $12.43 
Production taxes per BOE   2.06    (1.30)
Depreciation, depletion, and amortization per BOE   12.21    12.25 
Total operating costs per BOE  $26.48   $23.38 

 

The average oil and NGL sales prices above are calculated by dividing revenue from oil sales by volume of oil sold, in barrels “Bbl.” The average natural gas sales prices above are calculated by dividing revenue from natural gas sales by the volume of natural gas sold, in thousand cubic feet “Mcf.” The total average sales price amounts are calculated by dividing total revenues by total volume sold, in BOE. The average production costs above are calculated by dividing production costs by total production in BOE.

 

Acreage

 

The following table sets forth our approximate gross and net developed and undeveloped acreage as of December 31, 2017:

 

    Undeveloped Acreage     Developed Acreage     Total  
    Gross     Net     Gross     Net     Gross     Net  
Delaware Basin     26,900       10,400       8,300       5,300       35,200       15,700  

  

Productive Wells

 

As of December 31, 2017, we have had 13 gross (10.4 net) oil wells and 10 gross (6.6 net) natural gas wells. A net well is our percentage ownership interest of a gross well.

 

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 natural gas well based on the ratio of natural gas to oil produced when it first commenced production, and such designation may not be indicative of current production.

 

Drilling Activity

 

Exploratory Wells

 

During 2017, we drilled 8 gross (6.7 net) horizontal exploratory wells in the Delaware Basin. We completed and placed on production 5 gross (4.1 net) horizontal exploratory wells, leaving 3 gross (2.6 net) horizontal exploratory wells drilled but not yet completed as of December 31, 2017. All of these wells were successful and none were a dry hole.

 

During 2016, we drilled 2 gross (1.6 net) horizontal exploratory wells in Texas. These wells were drilled but not yet completed. These wells were successful and placed on production during the first quarter of 2017.

   

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Year Ended December 31,
   2017   2016 
   Gross   Net   Gross   Net 
Exploratory:                
Productive   5.00    4.10         
Dry                
Total:                    
Productive   5.00    4.10         
Dry                 

 

As of December 31, 2017, we had 3 gross (2.6 net) wells in the process of drilling, completing or dewatering or shut in awaiting infrastructure that are not reflected in the above table. At December 31, 2016, we had 2 gross (1.6 net) wells in the process of drilling, completing or dewatering or shut in awaiting infrastructure that are not reflected in the above table that were placed on production during the first quarter of 2017.

 

Present Activities

 

Subsequent to December 31, 2017 and through March 1, 2018, we drilled or were in the process of drilling 6 gross (5.1 net) horizontal wells and completed or were in the process of completing 4 gross (3.6 net) horizontal wells and had 5 gross (4.1 net) horizontal wells awaiting completion.

 

Title to Properties

 

We generally conduct a preliminary title examination prior to the acquisition of properties or leasehold interests. Prior to commencement of operations on such acreage, a thorough title examination will usually be conducted and any significant defects will be remedied before proceeding with operations. We believe the title to our leasehold properties is good, defensible and customary with practices in the oil and natural gas industry, subject to such exceptions that we believe do not materially detract from the use of such properties. Our properties are potentially subject to one or more of the following:

 

·royalties and other burdens and obligations under oil and natural gas leases, purchase agreements and leasehold assignments;
·overriding royalties and other burdens created by us or our predecessors in title;
·contractual obligations arising under operating agreements, farm-out agreements, production sales contracts and other agreements that may affect the properties or their titles;
·liens that arise in the normal course of operations, including those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors and contractual liens under operating agreements; and
·easements, restrictions, rights-of-way and other matters that commonly affect property.

 

Additionally, the majority of our Delaware Basin leasehold position is subject to mortgages securing indebtedness under our credit and guarantee agreement.

 

With respect to our properties of which we are not the record owner, we rely instead on contracts with the owner or operator of the property or assignment of leases, pursuant to which, among other things, we generally have the right to have our interest placed on record.

 

Competitive Business Conditions

 

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 depend 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.

 

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.

 

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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.

 

Marketing and Pricing

 

We derive revenue and cash flow principally from the sale of oil, natural gas and NGLs. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil, natural gas and NGLs. 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, natural gas and NGLs 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, natural gas and NGLs. 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, natural gas and NGLs have fluctuated widely.

 

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. In addition, hedging arrangements may limit the benefit we would receive from increases in the prices for oil and natural gas.

 

Major Customers

 

Our major customers for the year ended December 31, 2017 include Texican Crude & Hydrocarbons, LLC and ETC Field Services LLC, who accounted for approximately 85% and 14% of our revenue for the year ended December 31, 2017, respectively. Our major customers for the year ended December 31, 2016 included Noble Energy, Inc., Texican Crude & Hydrocarbons, LLC 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.

 

Delivery Commitments

 

As of December 31, 2017, we were not committed to providing a fixed quantity of oil or natural gas under any existing contracts.

 

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, Federal Energy Regulatory Commission (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.

 

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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 natural 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, 2017 and 2016, we incurred approximately $32,000 and approximately $182,000, respectively, related to compliance with environmental laws for our oil and natural gas properties.

 

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.

 

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Water Discharges

 

The Federal Water Pollution Control Act, also known as the Clean Water Act (the “Clean Water Act”) imposes restrictions and controls on the discharge of produced waters and other oil and natural gas wastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters and to discharge fill and pollutants into regulated waters and wetlands. Uncertainty regarding regulatory jurisdiction over wetlands and other regulated waters of the United States has complicated, and will continue to complicate and increase the cost of, obtaining such permits or other approvals. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the crude oil and natural gas industry into certain coastal and offshore waters. Further, the EPA has adopted regulations requiring certain crude oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. Spill Prevention, Control, and Countermeasure requirements of the Clean Water Act require appropriate secondary containment loadout controls, piping controls, berms and other measures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon spill, rupture or leak. The EPA and U.S. Army Corps of Engineers released a Connectivity Report in September 2013, which determined that virtually all tributary streams, wetlands, open water in floodplains and riparian areas are connected. This report supported the drafting of proposed rules providing updated standards for what will be considered jurisdictional waters of the United States. Those rules were finalized on May 27, 2015. Then, on October 9, 2015, in presiding over a challenge to the rules, the U.S. Court of Appeals for the Sixth Circuit stayed them, nationwide. It later determined (in February of 2016) that it has jurisdiction to adjudicate the challenge. In January of 2017, the U.S. Supreme Court accepted an appeal of that determination. In the meantime, the Sixth Circuit’s stay of the rules remains in place. On February 28, 2017, moreover, President Trump directed the EPA to review the rules and “publish for notice and comment a proposed rule rescinding or revising the rules, as appropriate and consistent with law.” The Clean Water Act and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges of crude oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution.

 

The Oil Pollution Act of 1990 (“OPA”) and regulations thereunder impose a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. The OPA assigns strict liability to each responsible party for oil removal costs and a variety of public and private damages, including natural resource damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of federal safety, construction or operating regulations. Few defenses exist to the liability imposed by the OPA. In addition, to the extent we acquire offshore leases and those operations affect state waters, we may be subject to additional state and local clean-up requirements or incur liability under state and local laws. The OPA also imposes ongoing requirements on responsible parties, including proof of financial responsibility to cover at least some costs in a potential spill. We cannot predict whether the financial responsibility requirements under the OPA amendments will adversely restrict our proposed operations or impose substantial additional annual costs to us or otherwise materially adversely affect us. The impact, however, should not be any more adverse to us than it will be to other similarly situated owners or operators.

 

Safe Drinking Water Act

 

The Safe Drinking Water Act of 1974, as amended, establishes a regulatory framework for the underground injection of a variety of wastes, including brine produced and separated from crude oil and natural gas production, with the main goal being the protection of usable aquifers. The primary objective of injection well operating permits and requirements is to ensure the mechanical integrity of the wellbore and to prevent migration of fluids from the injection zone into underground sources of drinking water. Class II underground injection wells, a predominant storage method for crude oil and natural gas wastewater, are strictly controlled, and certain wastes, absent an exemption, cannot be injected into such wells. Failure to abide by our permits could subject us to civil or criminal enforcement. We believe that we are in compliance in all material respects with the requirements of applicable state underground injection control programs and our permits. In Texas, the Texas Railroad Commission (“RRC”) regulates the disposal of produced water by injection well. The RRC requires operators to obtain a permit from the agency for the operation of saltwater disposal wells and establishes minimum standards for injection well operations. In response to recent seismic events near underground injection wells used for the disposal of oil and gas-related wastewaters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or imposed moratoria on the use of such injection wells. In response to these concerns, regulators in some states are considering additional requirements related to seismic safety. For example, the RRC has adopted new permit rules for injection wells to address these seismic activity concerns within the state. Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells, and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. These new rules could impact the availability of injection wells for disposal of wastewater from our operations. Increased costs associated with the transportation and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may reduce our profitability; however, these costs are commonly incurred by all oil and gas producers and we do not believe that the costs associated with the disposal of produced water will have a material adverse effect on our operations.

 

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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 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. 

 

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 natural gas production sources in the United States on an annual basis, which include certain of our operations. 

 

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, natural 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.

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Several states, including Texas, and local jurisdictions have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, the Texas Legislature adopted legislation, effective September 1, 2011, requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process. The RRC adopted rules and regulations implementing this legislation that apply to all wells for which the RRC issues an initial drilling permit after February 1, 2012. The law requires that the well operator disclose the list of chemical ingredients subject to the requirements of OSHA for disclosure on an internet website and also file the list of chemicals with the RRC with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the RRC.

 

Further, in May 2013, the RRC adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular. In addition, the Texas Legislature adopted new legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. The RRC has adopted rules and regulations implementing this legislation that apply to all wells for which the RRC issues an initial drilling permit after February 1, 2012. The new law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) for disclosure on an internet web site and also file the list of chemicals with the RRC with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the RRC.

 

We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

 

A variety of federal and state laws and regulations govern the environmental aspects of natural gas and oil production, transportation and processing. These laws and regulations may impose liability in the event of discharges, including for accidental discharges, failure to notify the proper authorities of a discharge, and other noncompliance. Compliance with such laws and regulations may increase the cost of oil and natural 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.

 

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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. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The federal government has issued indictments under the Migratory Bird Treaty Act to several oil and gas companies after dead migratory birds were found near reserve pits associated with drilling activities. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.

 

NEPA

 

Additionally, significant federal decisions, such as the issuance of federal permits or authorizations for certain oil and gas exploration and production activities may be subject to the National Environmental Policy Act (“NEPA”). The NEPA requires federal agencies, including the Department of Interior, to evaluate major federal agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. This process has the potential to delay oil and gas development projects.

 

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.

 

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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 natural gas to point-of-sale locations.

 

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

 

Our crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.

 

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

 

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

 

Federal Leases. For those operations on federal oil and natural 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.

 

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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.

 

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.

 

Seasonal Nature of Business

 

Generally, the demand for oil and natural gas fluctuates depending on the time of year. Seasonal anomalies such as mild winters or hot summers may sometimes lessen this fluctuation. Further, pipelines, utilities, local distribution companies, and industrial end users utilize oil and natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can also lessen seasonal demand.

 

Operational Hazards and Insurance

 

The oil business involves a variety of operating risks, including the risk of fire, explosions, blow outs, pipe failures and, in some cases, abnormally high pressure formations which could lead to environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. If any of these should occur, we could incur legal defense costs and could be required to pay amounts due to injury, loss of life, damage or destruction to property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations.

 

In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed.

 

Current Employees

 

As of December 31, 2017, we had 27 full-time employees, and intend to continue to add additional personnel as our operational requirements grow. Our employees are not represented by any labor union. We consider our relations with our employees to be satisfactory and have never experienced a work stoppage or strike.

 

We also retain certain independent consultants and contractors to provide various professional services, including additional land, legal, engineering, geology, environmental and tax services on a contract or fee basis as necessary for our operations.

 

Principal Executive Office

 

Our principal executive offices are located 300 E. Sonterra Blvd., Suite No. 1220, San Antonio, Texas 78258, and our telephone number is (210) 999-5400. Our Internet website can be found at https://www.lilisenergy.com/. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act of 1934 will be available through our Internet website as soon as reasonably practical after we electronically file such material with, or furnish it to, the SEC. The information on, or that can be accessed through, our website is not incorporated by reference into this Annual Report and should not be considered part of this Annual Report.

 

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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 common stock. You should carefully consider all of the risks described in this Annual Report, in addition to the other information contained in this Annual Report, 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 unable to access additional capital, it could negatively impact our production, our income and ultimately our ability to retain our leases.

 

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, Series B preferred and Series C preferred shares. Our capital program may 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 plan to finance our capital expenditures with cash on hand, cash flow from operations and future issuances of debt and/or equity securities. Our cash flow from operations and access to capital is subject to a number of factors, including:

 

·our estimated proved oil and natural gas reserves;
·the amount of oil and natural gas we produce from existing wells;
·the prices at which we sell our production;
·the costs of developing and producing our oil and natural gas reserves;
·our ability to acquire, locate and produce new reserves;
·the ability and willingness of banks to lend to us; and
·our ability to access the equity and debt capital markets.

 

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 2018 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, 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.

 

Oil, natural gas and NGL prices are highly volatile. If commodity prices experience substantial decline, our operations, financial condition, and level of expenditures for the development of our oil, natural gas and NGL reserves may be materially and adversely affected.

 

The prices we receive for our oil, natural gas, and NGL production heavily influence our revenue, operating results, profitability, access to capital, future rate of growth and carrying value of our properties. Oil, natural gas, and NGLs 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, natural gas, and NGLs experience a substantial decline, our operations, financial condition and level of expenditures for the development of our oil, natural gas and NGL 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:

 

·changes in global supply and demand for oil and natural gas;
·the actions of the Organization of Petroleum Exporting Countries, or OPEC;
·the price and quantity of imports of foreign oil and natural gas;
·political conditions, including embargoes, in or affecting other oil-producing activity;
·the level of global oil and natural gas exploration and production activity;
·the level of global oil and natural gas inventories;

 

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·weather conditions;
·technological advances affecting energy consumption; and
·the price and availability of alternative fuels.

 

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.

 

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.

 

We entered into the First Lien Credit Agreement in 2016, the Second Lien Credit Agreement in 2017 and the Riverstone First Lien Credit Agreement in 2018 (as such terms are hereinafter defined and as described in more detail herein). As of December 31, 2017, $30.8 million was outstanding under our First Lien Credit Agreement (which was subsequently paid off with loan proceeds of the Riverstone First Lien Credit Agreement) and $155.8 million was outstanding on under our Second Lien Credit Agreement.

 

If we further utilize our credit facilities in the future or obtain additional financing, our level of indebtedness could affect our operations in several ways, 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.

 

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

 

Our Riverstone First Lien Credit Agreement and Second Lien Credit Agreement contain restrictive covenants that limit our ability to, among other things:

 

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

 

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.

  

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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.

 

Värde Partners, Inc. and its affiliates (collectively, “Värde”) beneficially own a significant portion of our common stock. Värde is not limited in their ability to compete with us, and the waiver of the corporate opportunity provisions in the certificate of designation relating to our Series C Preferred Stock, may allow Värde to benefit from corporate opportunities that might otherwise be available to us. As a result, conflicts of interest could arise in the future between us and Värde, including their portfolio companies concerning conflicts over our operations or business opportunities.

 

Värde is a family of private investment funds that beneficially owns a significant portion of our common stock as a result of the conversion rights available to them under the Second Lien Credit Agreement and the Series C Preferred Stock (as hereinafter defined and described), and it has investments in other companies in the energy industry. The Series C Preferred Stock was issued on January 30, 2018. As a result, Värde may, from time to time, acquire interests in businesses that directly or indirectly compete with our business, as well as businesses that are our customers or suppliers. As such, Värde or its portfolio companies may acquire or seek to acquire the same assets that we seek to acquire and, as a result, those acquisition opportunities may not be available to us or may be more expensive for us to pursue. Any actual or perceived conflicts of interest with respect to the foregoing could have an adverse impact on the trading price of our common stock.

 

The certificate of designation governing the preferences, rights and limitations of the Series C Preferred Stock, provides that Värde (including portfolio investments of Värde) is not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. In particular, subject to the limitations of applicable law, if Värde, or any agent, shareholder, member, partner, director, officer, employee, investment manager or investment advisor of Värde who is also one of our directors or officers, becomes aware of a potential business opportunity, transaction or other matter, they will have no duty to communicate or offer that opportunity to us.

 

Värde may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Furthermore, such businesses may choose to compete with us for these opportunities, possibly causing these opportunities to not be available to us or causing them to be more expensive for us to pursue. As a result, our renouncing our interest and expectancy in any business opportunity that may be from time to time presented to Värde could adversely impact our business or prospects if attractive business opportunities are procured by such parties for their own benefit rather than for ours.

 

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

 

Our disclosure controls and procedures and internal controls may not prevent all possible errors and fraud. A control system, no matter how well conceived and operated, can provide only reasonable 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. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur without detection, which could have a material adverse effect on our business.

 

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.

 

A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis. During the audit of our internal control over financial reporting for the year ended December 31, 2017, errors were identified in the Company’s computation of the full cost ceiling test limitation. For a discussion of our internal control over financial reporting and a description of the identified material weakness, see "Management's Report on Internal Control Over Financial Reporting" included in Item 9A of this report.

 

Effective internal controls are necessary for us to provide reasonable assurance with respect to our financial reports and to effectively prevent fraud. If we cannot provide reasonable assurance with respect to our financial reports and effectively prevent fraud, our reputation and operating results could be harmed. Internal control over financial reporting may not prevent or detect misstatements because of its inherent limitations, including the possibility of human error, the circumvention or overriding of controls, or fraud. Further, the complexities of our quarter-end and year-end closing processes increase the risk that a weakness in internal controls over financial reporting may go undetected. Therefore, even effective internal controls can provide only reasonable assurance with respect to the preparation and fair presentation of financial statements. In addition, projections of any evaluation of effectiveness of internal control over financial reporting to future periods are subject to the risk that the control may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

 

A material weakness in our internal control over financial reporting could adversely impact our ability to provide timely and accurate financial information. We have identified remediation steps, including enhanced analytical analysis and improved management review of the full cost ceiling test calculation in order to remediate this material weakness. We plan to complete this remediation process as quickly as possible. However, if our remedial measures are insufficient to address the material weakness or if additional material weaknesses or significant deficiencies in our internal control over financial reporting are discovered or occur in the future, we may not be able to timely or accurately report our financial condition, results of operations or cash flows or maintain effective disclosure controls and procedures. If we are unable to report financial information timely and accurately or to maintain effective disclosure controls and procedures, we could be subject to, among other things, regulatory or enforcement actions by the SEC and the NYSE, including a delisting from the NYSE, securities litigation, debt rating agency downgrades or rating withdrawals, any one of which could adversely affect the valuation of our common stock and could adversely affect our business prospects.

 

Decreases in oil and natural gas prices may require us to take write-downs of the carrying values of our oil and natural gas properties, potentially requiring earlier than anticipated debt repayment and negatively impacting the trading value of our securities.

 

Accounting rules require that we review periodically the carrying value of our oil and natural gas properties for possible impairment through the performance of a ceiling test. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties.

 

We perform the ceiling test at least quarterly and, in the event capitalized costs of the full cost pool exceed this ceiling, we would recognize an impairment expense. We recognized an impairment expense of approximately $10.5 million and approximately $4.7 million for the years ended December 31, 2017 and 2016, respectively.

 

Future write-downs could occur for numerous reasons, including, but not limited to continued reductions in oil and natural 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 natural 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. If commodity prices decline, we could incur full cost ceiling impairments in future quarters. Impairment charges would not affect cash flow from operating activities, but could have a material adverse effect our net income and stockholders’ equity.

 

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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.

 

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 could materially affect the quantities and present value of our reserves which could adversely affect our business, results of operations, and financial condition.

 

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 unweighted average of first-day-of-the-month oil and natural gas benchmark prices, adjusted for marketing and other differentials 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.

 

If our reserve estimates or the underlying assumptions prove inaccurate, it could have a negative impact on our earnings and net income, and most likely the trading price of our securities.

 

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, 2017, we had hedging agreements in place on approximately 1,000 Bbl per day, or 83% of our expected production from proved developed producing reserves for the period from January 1, 2018 through June 30, 2018, as forecast under the reserve report prepared by our independent reserve engineers dated December 31, 2017.

 

Our identified drilling locations are scheduled to be drilled over a period of 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 our 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 and producing 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 as such studies are merely an interpretive tool.

 

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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:

 

·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.

 

Additionally, 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.

 

If we decide to drill a certain location, there is a risk that no commercially productive oil or natural gas reservoirs will be found or produced, or 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. 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.

 

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 our exploration and development activities.

 

We derive essentially all of our revenues from the sale of our oil, natural gas and NGLs 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.

 

Additionally, 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.

 

Our industry is highly competitive, which may adversely affect our operations and performance.

 

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 include: leasehold prospects under which oil and natural gas reserves may be discovered; drilling rigs and related equipment to explore for such reserves; and knowledgeable personnel to conduct all phases of oil and natural gas operations. We must compete for such resources with both major oil and natural gas companies and independent operators.

 

Many of our 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, the breach of our obligations under the oil and natural 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 personnel or attract capital, a slowdown in our operations and decline in revenue; and a decline in the market price of our common stock.

 

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 and the acumen and the assumptions of the evaluation personnel. Generally, it is not feasible to review in depth every individual property, well, facility and/or file involved in 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.

 

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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 for the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed oil and natural gas well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and such curative work entails expense. Failure to cure any title defects may adversely impact our ability in the future to increase production and reserves. In the future, we may suffer a monetary loss from title defects or title failure. Additionally, unproved and unevaluated acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss which could adversely affect our financial condition, results of operations and cash flows.

 

Our producing properties are located in the Delaware Basin, making us vulnerable to risks associated with operating in one major geographic area.

 

All of our estimated proved reserves at December 31, 2017, were located in the Delaware Basin in Winkler, Loving, and Reeves Counties, Texas and Lea County, New Mexico. As a result of this concentration, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil or natural gas produced from the wells in this area.

 

In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural 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.

 

We may 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 approximately 90% of our acreage. As we carry out our exploration and development programs, we may enter into arrangements with respect to existing or future drilling locations that result in wells 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.

 

Our limited ability to exercise control over the operations of any drilling locations operated by other operators may cause a material adverse effect on results of operations and financial condition.

 

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The marketability of our production is dependent upon transportation and processing facilities and third parties over which or whom 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 natural gas production available to third-party purchasers. We deliver our produced crude oil and natural gas 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 our development plans. 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, mechanical reliability or other reasons, including adverse weather conditions or work-loads. 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.

 

On August 10, 2017, we entered into a long-term agreement with Lucid relating to gas gathering, processing and associated services to support our drilling program. Pursuant to the agreement, Lucid will receive, gather and process our gas production from certain production areas located in Lea County, New Mexico and in Loving and Winkler Counties, Texas. The agreement secures incremental midstream capacity for us in the production areas committed to the new agreement. We commenced services with Lucid on our New Mexico properties in November 2017 and expect to commence services on our Texas properties in early 2018.

 

The shut-in of our wells could negatively impact our production, liquidity, and, ultimately, our operations, results, and performance.

 

Our production depends, in part, upon our wells that are capable of commercial production not being shut-in (i.e., suspended from production). The lack of availability of capacity on third-party systems and facilities (see "Risk Factors-Risks Relating to Our Business-The marketability of our production is dependent upon transportation and processing facilities and third parties over which or whom we may have no control.”) or the shut-in of an oil field’s production, among other reasons, could result in the shut-in of our wells. As of December 31, 2017, we had 3 gross (2.60 net) wells shut in awaiting infrastructure.

 

If we experience low oil production volumes due to the shut-in of our wells, we would experience a reduction in our available liquidity and we may not have the ability to generate sufficient cash flows from operations and, therefore, sufficient liquidity to meet our anticipated working capital, debt service, and other liquidity needs. A significant decline in oil production due to the shut-in of our wells could adversely affect our financial position, financial results, cash flows, access to capital and ability to grow.

 

Unless we find new oil and natural 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 natural 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 natural gas reserves and production and, therefore, our cash flow and revenue are highly dependent on our success in efficiently obtaining additional reserves. We may not be able to develop, find or acquire reserves to replace our current and future production at costs or other terms acceptable to us, or at all, in which case our business, financial condition and results of operations would be materially and adversely affected.

 

The results of our planned exploratory and development drilling are subject to drilling and completion execution risks, and drilling results may not meet our economic expectations for reserves or production.

 

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. 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, 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.

 

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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 natural 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.

 

We are exposed to operating hazards and uninsured risks.

 

Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the risk of:

 

·fire, explosions and blowouts;
·negligence of personnel;
·inclement weather;
·pipe or equipment failure;

  · abnormally pressured formations;

  · environmental accidents such as oil spills; and

  · natural gas environment (including groundwater contamination).

 

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.

 

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.

 

In accordance with customary industry practices, 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. 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. Losses and liabilities arising from uninsured or underinsured events may have a material adverse effect on our financial condition and operations, including the loss of our total investment in a particular prospect.

 

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.

 

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A failure of technology systems, data breach or cyberattack could materially affect our operations.

 

Information technology solution failures, network disruptions, breaches of data security and cyberattacks could disrupt our operations by causing delays or cancellation of customer orders, impeding processing of transactions and reporting financial results, resulting in the unintentional disclosure of customer, employee or our information, or damaging our reputation. A system failure, data security breach or cyberattack could have a material adverse effect on our financial condition, results of operations or cash flows.

 

Our information technology systems may be vulnerable to security breaches beyond our control, including those involving cyberattacks using viruses, worms or other destructive software, process breakdowns, phishing or other malicious activities, or any combination of the foregoing. Such breaches could result in unauthorized access to information, including customer, employee, or other company confidential data. We do not carry insurance against these risks, although we do invest in security technology, perform penetration tests from time to time, and design our business processes to attempt to mitigate the risk of such breaches. However, there can be no assurance that security breaches will not occur. Moreover, the development and maintenance of these measures requires continuous monitoring as technologies change and efforts to overcome security measures evolve. We have experienced, and expect to continue to experience, cyber security threats and incidents, none of which has been material to us to date. However, a successful breach or attack could have a material negative impact on our operations or business reputation and subject us to consequences such as litigation and direct costs associated with incident response.

 

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 may be dependent upon partnering arrangements.

 

As of December 31, 2017, we had 27 full-time employees. We leverage the services of independent consultants and contractors to perform various professional services, including engineering, oil and natural gas well planning and supervision, and land, legal, environmental 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 Ron Ormand, our Executive Chairman of the Board, James (Jim) Linville, our Chief Executive Officer, Joseph Daches, our Chief Financial 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, oil and natural gas properties, prospects and leaseholds. 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. 

 

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

 

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 Natural 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 natural 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 natural 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 natural 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.”

 

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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.

 

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 natural 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, natural gas and NGLs 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 natural 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. 

 

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 natural 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.

 

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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.

 

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 natural 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 natural 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 oil and natural gas. 

 

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;

 

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·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 natural 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.

 

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 Natural Gas Act (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 U.S. Commodity Futures Trading Commission (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.”

 

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Risks Relating to Our Securities

 

The market price of our common stock 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.

 

The market price of our securities may 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. 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. 

  

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 stockholders. Any preferred stock that is issued may rank ahead of our common stock, in terms of dividends, liquidation rights and voting rights. We currently have one series of preferred stock issued and outstanding, which ranks senior to our common stock with respect to dividends and rights on the liquidation, dissolution or winding up of the Company, 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 of our common stock. To the extent outstanding restricted stock units, warrants or options to purchase our common stock under our 2016 Omnibus Incentive Plan or our 2012 Equity Incentive Plan are exercised, the price vesting triggers under the performance shares granted to our executive officers are satisfied, or additional shares of restricted stock are issued to our employees, holders of our common 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 facilities and preferred stock prohibit us from paying any dividends. In the future, we may agree to further restrictions. Any return to stockholders will therefore be limited to the appreciation of their stock.

 

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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, the lack of coverage may adversely affect the trading price of our shares. The trading market for our shares will rely in part on the research and reports that securities analysts publish about us and our business. If one or more of the analysts who cover our 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.

 

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

 

The existence of certain provisions under Nevada law could delay or prevent a change in control of the Company, which could adversely affect the price of our common stock. Additionally, Nevada law imposes certain restrictions on mergers and other business combinations between us and any holder of 10% or more of our outstanding common stock.

 

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.

 

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PART II

 

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

 

Recent Market Prices

 

On July 24, 2017, our common stock commenced trading on the NYSE American under its symbol “LLEX.” From May 9, 2017 to July 23, 2017, our common stock traded on the NYSE MKT under its current symbol “LLEX.”

 

Prior to trading on the NYSE markets, from March 4, 2017 to May 8, 2017, our common stock traded on the NASDAQ Stock Market LLC under the symbol “LLEX”. From May 27, 2016 to March 13, 2017, our common stock was listed on the OTCQB Venture Marketplace under the symbol “LLEX”. From February 11, 2016 to May 26, 2016, our common stock traded on The Nasdaq Capital Market (“Nasdaq”) under the symbol “LLEX.” Prior to February 11, 2016, our common stock traded on the Nasdaq Global Market under the symbol “LLEX.”

 

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  
    2018  
First Quarter (through March 5, 2018)   $ 5.44     $ 3.10  
                 
    2017  
Fourth Quarter   $ 5.50     $ 4.14  
Third Quarter   $ 5.25     $ 2.96  
Second Quarter   $ 5.69     $ 3.41  
First Quarter   $ 5.22     $ 2.90  

 

   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 

 

As of March 5, 2018, there were 158 owners of record of our common stock. We estimate that there are approximately 1,705 beneficial holders of our common stock.

 

Dividend Policy

 

We have never paid cash dividends on our common stock and do not anticipate paying 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 of Directors may deem relevant at that time.

 

We are currently restricted from declaring any dividends pursuant to the terms of our Riverstone First Lien Credit Agreement, Second Lien 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” for further information.

 

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, 2017.

 

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Equity Compensation Plans

 

Information regarding equity compensation plans is set forth in Item 11 of this Annual Report and is incorporated herein by reference.

 

Item 6. Selected Financial Data

 

Not applicable.

 

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

 

The following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes included elsewhere in this Annual Report. The following discussion includes forward-looking statements, including, without limitation, statements relating to our plans, strategies, objectives, expectations, intentions and resources. Our actual results could differ materially from those discussed in these forward-looking statements as a result of many factors, including those discussed under “Risk Factors” and elsewhere in this Annual Report.

 

Overview

 

Lilis is an independent oil and natural gas company focused on the acquisition, development, and production of conventional and unconventional oil and natural gas properties in the core of the Delaware Basin in Winkler, Loving, and Reeves Counties, Texas and Lea County, New Mexico.

 

Our Business and Strategy

  

We believe our significant inventory of oil and liquids-rich drilling opportunities in the Delaware Basin provide us with a platform for continued future growth. As of December 31, 2017, we had accumulated approximately 35,200 gross (15,700 net) acres in the core of the Delaware Basin in Winkler, Loving, and Reeves Counties, Texas and Lea County, New Mexico, with approximately 33,080 gross (14,430 net) acres in Winkler, Loving, and Reeves Counties, Texas and approximately 2,120 gross (1,270 net) acres in Lea County, New Mexico. Our leasehold position is largely contiguous, which we believe will enable us to maximize development efficiency and manage our costs.

 

As of December 31, 2017, our proved reserves were approximately 11,453 MBOE (million barrels of oil equivalent). Our proved reserves consist of 63% oil, 23% natural gas and 14% NGL. Of those reserves, 37% of our proved reserves are classified as proved developed and approximately 63% are classified as proved undeveloped.

 

In addition, 34% of our net acreage position was held by production at December 31, 2017, and we operated approximately 90% of our acreage, which we believe gives us significant control over the pace of our development and the ability to design a more efficient and profitable drilling program to maximize recovery of oil and natural gas.

 

In 2017, we also entered into a long-term gas gathering, processing and purchase agreement with an affiliate of Lucid Energy Group (“Lucid”) to support our active drilling program in the Delaware Basin. Lucid will receive, gather and process our gas production from certain production areas located in Lea County, New Mexico and in Loving and Winkler Counties, Texas. The agreement secures sufficient term and capacity for Lilis during our development and exploitation life cycle of the production areas committed to the new agreement.

 

Our focus is on the development of our oil and natural gas properties in the Delaware Basin, primarily through the drilling of horizontal wells, which we believe will provide attractive returns on a majority of our acreage positions. 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 completed our first horizontal well in January 2017, and have completed six additional wells since that time. On March 31, 2017, we completed the divestiture of all our oil and natural gas properties located in the DJ Basin to complete our transformation to a pure play Permian Basin oil and natural gas company.

 

As of March 1, 2018, we have accumulated approximately 35,800 gross (16,200 net) acres in what we believe to be the core of the Delaware Basin in Winkler, Loving, and Reeves Counties, Texas and Lea County, New Mexico. Our leasehold position is largely contiguous, allowing us to maximize development efficiency and manage full cycle finding costs. Approximately 35% of our acreage position is held by production, and we are the named operator on nearly 100% of our producing acreage, which gives us significant control over the pace of our development and our ability to design a more efficient and profitable drilling program that maximizes recovery of hydrocarbons.

 

We expect that substantially all of our estimated 2018 capital expenditure budget will be focused on the development and expansion of our Delaware Basin acreage and operations. We also plan to continue selectively and opportunistically pursuing strategic acreage acquisitions and organic leasing prospects in the Delaware Basin.

 

Our business objective is to increase stockholder value by growing our Delaware Basin leasehold position, reserves, production and cash flows at attractive rates of return on invested capital. We continue to focus on developing our existing acreage position, gaining additional operational control and expanding our core assets in the Delaware Basin. We plan to achieve our business objective by implementing a business strategy focused on the following:

 

  · Execute our Operated, Horizontal Drilling Program to Grow Production from our Delaware Basin Leasehold . We plan to drill and develop our existing acreage base of approximately 35,800 gross (16,200 net) acres in the Delaware Basin, which we believe will maximize our resource potential and value to our stockholders. Through the development of our properties, we seek to de-risk our acreage position 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, which we believe includes at least seven productive zones. We estimate that all productive zones within our properties may support approximately 900 future drilling locations, including over 400 longer lateral locations, and we expect that inventory to increase with the closing of our pending acquisition from OneEnergy Partners Operating, LLC. We focused our horizontal development in 2017 on the Wolfcamp B formation but intend to expand our target zones to the Wolfcamp A, Wolfcamp XY and 2nd Bone Spring during 2018. Our long-term gas gathering, processing and purchase agreement with Lucid will support our active drilling program and alleviate production constraints we have experienced.

  

  · Focus on Delineation of our Existing Acreage. We plan to focus on the delineation and de-risking of our existing acreage. We expect that our drilling activity will also grow our drilling inventory and the identified resource potential of our Delaware Basin properties. We believe that our current reserves represent only a small portion of the resource potential within our acreage. Our development plan for 2018 contemplates the continued delineation of our acreage both geographically and geologically by testing our eastern acreage and by drilling and completing wells within additional prospective benches, including the Wolfcamp A, Wolfcamp XY and the 2nd Bone Spring.

   

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  · Leverage our Extensive Operational Expertise to Reduce Costs and Enhance Returns. As of December 31, 2017, we operated approximately 90% of our acreage position, giving us significant control over the pace of our development and allowing us to increase value through operational and cost efficiencies. We intend to obtain the highest possible returns on the capital we expend on our development projects using results from the wells we have completed and the operational expertise of our management team. We also plan to focus on operational efficiencies, including salt water disposal and midstream costs, and capital costs of our development wells in order to maximize returns to our stockholders.

   

  · Pursue Selective Acquisitions and Organic Leasing to Grow Our Leasehold Position. Since entering the Delaware Basin in June 2016, we have grown our net acreage position approximately 376% from 3,400 net (7,200 gross) acres to approximately 16,200 net (35,800 gross) acres as of March 1, 2018. On January 30, 2018, we announced our entry into a pending Purchase and Sale Agreement with OneEnergy Partners Operating, LLC to acquire 2,798 net acres in New Mexico, which are largely overlapping or contiguous with our existing properties, for approximately $70 million (the “OEP Acquisition”).  Pro forma for the closing of the OEP Acquisition, we expect we expect our acreage position to approximately 19,000 net acres.  Our most significant acquisition in 2017 included approximately 4,400 net acres, approximately 92% of which overlapped our existing acreage position. Our acquisitions to date have added approximately 600 drilling locations with multiple stacked pay zones. In addition to our continued evaluation of strategic acquisition opportunities in the Delaware Basin, we will continue to expand our leasehold position through our organic leasing program.

 

  · Maintain Fiscal Discipline and Financial Liquidity. We actively manage the level of our development, leasing and acquisition activity in response to commodity prices, access to capital, and to the performance of our wells. We hold significant control over the pace of our drilling activity as a result of our operatorship on approximately 90% of our properties. During 2017, we commenced an active hedging program to provide certainty regarding our cash flow and protect returns from our development activity in the event of decreases in the prices received for our production. In addition, we have structured our balance sheet with the intent to reduce our leverage profile over time. The Second Lien Term Loan (as hereinafter defined) that we primarily relied upon to finance our capital spending and operations in 2017 is convertible, and we announced the issuance of $100 million in convertible, perpetual Series C preferred stock on January 31, 2018. In addition, the closing of our recently announced OEP Acquisition, which carries a purchase price of approximately $70 million, will be funded in part with $30 million of common stock to be issued to the seller.

   

We expect that our 2018 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 acreage acquisitions in the Delaware Basin. 

 

Market Conditions and Commodity Pricing

 

Our financial results depend on many factors, including the price of oil, natural gas and NGLs and our ability to market our production on economically attractive terms. We generate the majority of our revenues from sales of oil, natural gas and NGLs. The prices of these products are critical factors to our success and volatility in the prices of oil and natural gas could impact our results of operations. In addition, our business requires substantial capital to acquire properties and develop our non-producing properties. Declines in these prices would reduce our revenues and result in lower cash inflow which would make it more difficult for us to pursue our plans to acquire new properties and develop existing properties. Declines in oil, natural gas, and NGL prices may also adversely affect our ability to obtain additional funding on favorable terms.

 

We believe our long-term agreement with Lucid relating to gas gathering, processing and associated services to support our production operations will enable us to avoid many potential issues relating to the transportation of our production. Pursuant to our agreement, Lucid will receive, gather and process our natural gas production from certain production areas located in Lea County, New Mexico and in Loving and Winkler Counties, Texas. The agreement secures incremental midstream capacity for us in the production areas committed.

 

We believe we are well-positioned to manage the challenges presented in a lower pricing environment, and we can execute our planned 2018 development program and capital expenditures with a combination of cash, cash flow, and proceeds from the exercise of outstanding warrants.

 

Impact of New Tax Reform

 

The New Tax Cuts and Jobs Act (the “Act”) was signed into law on December 22, 2017. The Act makes broad and complex changes to the U.S. tax code applicable to certain items in 2017 as well as those applicable to 2018 and subsequent years.

 

The applicable items that will affect 2017 include but are not limited to (1) bonus depreciation that will allow for full (100%) expensing of qualified property acquired and placed in service after September 27, 2017 and (2) limitations on the deductibility of certain executive compensation under IRC Sec. 162(m) related to plans after November 2, 2017.

 

The Act also establishes new tax laws that will affect 2018, including but not limited to, (1) reduction of U.S. federal corporate tax rate to twenty one percent; (2) the elimination of the corporate alternative minimum tax (AMT); (3) limitation on the deduction of interest expense; (4) the repeal of the of the domestic production activity deduction (DPAD); and (5) limitations on net operating losses (NOL’s) generated after December 31, 2017 to eighty percent of taxable income. The NOL’s generated in 2018 and beyond are to be carried forward indefinitely with no carryback.

 

The Act preserved the deductibility of Intangible Drilling Costs (IDC’s) for federal income tax purposes. The IDC’s have recently been capitalized and amortized for tax purposes to avoid negative AMT consequences which would result in the reduction of AMT NOL’s. The Act eliminates AMT for tax years beginning on or after January 1, 2018 which provides the company latitude in its tax treatment of IDC’s for both current year and future tax planning purposes.

 

ASC 740 requires the recognition of the tax effects of the Act for annual periods that include December 22, 2017. At December 31, 2017, the Company has made reasonable estimates of the effects on its existing deferred tax balances. The Company has remeasured certain federal deferred tax assets and liabilities based on the rates at which they are expected to reverse in the future, which is generally twenty one percent. The provisional amount recognized related to the remeasurement of its federal deferred tax balance was $9.5 million, which was subject to a valuation allowance at December 31, 2017.

 

We will continue to analyze the Act and future IRS regulations, refine its calculations and gain a more thorough understanding of how individual states are implementing this new law. This further analysis could potentially affect the measurement of deferred tax balances or potentially give rise to new deferred tax amounts.

  

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Results of Operations

 

During the year ended December 31, 2017, we worked actively to increase our natural gas production takeaway and processing capacity for our expanding production. We successfully brought online our fifth Wolfcamp B horizontal well located in Lea County, New Mexico. This well is our most geologically eastern well and is the closest well to the Central Basin Platform in our current acreage position. As of December 31, 2017, we have production flowing from our 10 horizontal wells and 14 legacy vertical wells with an estimated productive capacity of approximately 2,494 net BOE per day, on a combined equivalent oil, natural gas and NGL basis.

 

Our production for the year ended December 31, 2017, was temporarily impacted by curtailments resulting from operational and equipment issues with our current gathering and processing service provider. Primarily as a result of this curtailment of approximately 39.5% of our productive capacity, our average realized production was approximately 1,576 BOE per day for the year ended December 31, 2017. This temporary curtailment is expected to be resolved with expanded available natural gas takeaway and processing capacity under our new contract with Lucid. Production takeaway under the Lucid contract began in November 2017 from our New Mexico properties and in December 2017 from a portion of our Texas properties.

 

The results of operations of Brushy Resources are included with those of Lilis commencing June 23, 2016. As a result, results of operations for the year ended December 31, 2017 are not necessarily comparable to the twelve-month period in 2016. Additionally, all discussion related to historical representations of common stock, unless otherwise noted, gives retroactive effect to the reverse split on June 23, 2016 for all periods presented.

 

Year Ended December 31, 2017 Compared to Year Ended December 31, 2016

 

The following sets forth selected revenue and production data for the years ended December 31, 2017 and 2016:

 

   For the Year Ended
December 31,
     
   2017   2016   Change   %
Change
 
Net production:                    
Oil (Bbls)   371,993    61,088    310,905    509%
Natural gas (Mcf)   776,164    332,643    443,521    133%
NGL (Bbl)   73,875    11,357    62,518    550%
Total (BOE)   575,229    127,863    447,366    350%
Average daily production (BOE/d)   1,576    350    1,226    350%
                     
Average realized sales price:                    
Oil (Bbl)  $47.92   $39.59   $8.33    21%
Natural gas (Mcf)   2.74    2.54    0.20    8%
NGL (Bbl)   22.49    15.22    7.27    48%
Total (BOE)  $37.57   $26.87   $10.70    40%
                     
Oil, natural gas and NGL revenues (in thousands):                    
Oil revenue  $17,826   $2,418   $15,408    637%
Natural gas revenue   2,125    844    1,281    152%
NGL revenue   1,661    173    1,488    860%
Total  $21,612   $3,435   $18,177    529%

 

Revenues

 

Total revenue was $21.6 million for the year ended December 31, 2017, as compared to $3.4 million for the year ended December 31, 2016, representing an increase of $18.2 million or 529%. Our increase in revenue was associated primarily with an increase in production and sales of production from our seven Delaware Basin wells placed on production during 2017.

 

Oil revenues increased 637% due to an increase in oil sales volume of 509% and an increase in the average realized per barrel oil price of 21%. Natural gas revenues increased 152% due to an increase in natural gas sales volumes of 133% and an increase in the average realized per Mcf natural gas price of 8%. NGL revenues increased 860% due to an increase in NGL sales volumes of 551%, and an increase in NGL realized price of 48%.

 

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

 

Our production during the year ended December 31, 2017, increased from 127,863 BOE in 2016 to 575,229 BOE in 2017, an increase of 350%. This increase in production was primarily attributable to seven additional wells being completed and placed on production.

 

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The following table shows a comparison of production costs for the years ended December 31, 2017 and 2016:

 

    For the Year Ended
December 31,
       
    2017     2016     Change     %
Change
 
Production Costs per BOE:                                
Production costs   $ 12.21     $ 12.43     $ (0.22 )     -2 %
Production taxes     2.06       (1.30 )     3.36       -258 %
Depreciation, depletion, amortization and accretion     12.21       12.25       (0.04 )     -0 %
Total (BOE)   $ 26.48     $ 23.38     $ 3.10       13 %
                                 
Operating Expenses                                
Production costs   $ 7,023     $ 1,590     $ 5,433       342 %
Production taxes     1,187       (167 )     1,354       -811 %
General and administrative     49,851       14,227       35,624       250 %
Depreciation, depletion, amortization and accretion     7,025       1,698       5,327       314 %
Impairment of evaluated oil and natural gas properties     10,505       4,718       5,787       123 %
Total Operating Expenses   $ 75,591     $ 22,066     $ 53,525       243 %

  

Production Costs

 

Production costs were $7.0 million for the year ended December 31, 2017, compared to $1.6 million for the year ended December 31, 2016, an increase of $5.4 million, or 342%. The increase in production costs was primarily due to increased production volumes associated with the addition of seven wells placed on production in the Delaware Basin during the year ended December 31, 2017. Production costs per BOE decreased to $12.21 for the year ended December 31, 2017, from $12.43 for the year ended December 31, 2016, a decrease of $0.22 per BOE, or -2%. The ratio change in production volume from year ended December 31, 2016 to year ended December 31, 2017 was almost the same as the ratio change in production cost for same periods resulting in the low variance of $0.22 in production cost per BOE and the high production cost per BOE despite significant increase in production during 2017.

 

Production Taxes

 

Production taxes were $1.2 million for the year ended December 31, 2017, compared to $(0.2) million for the year ended December 31, 2016, an increase of $1.4 million. 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 increased to $2.06 per BOE during the year ended December 31, 2017 from $(1.30) per BOE during the year ended December 31, 2016. As discussed above, the increase in production taxes corresponds to the increase in production revenues during the year ended December 31, 2017. These taxes are likely to vary in the future depending on the production volumes we generate from various states, and on the possibility that any state may raise its production tax rate. The $(0.2) million in production taxes during the year ended December 31, 2016 was due to certain ad valorem and severance tax estimates that were higher than the actual amount billed, thus resulting in a tax benefit to us.

 

General and Administrative Expenses

 

General and administrative expenses (“G&A”) were $49.9 million during the year ended December 31, 2017, compared to $14.2 million during the year ended December 31, 2016, an increase of $35.6 million or 250%. The increase in G&A was primarily due to an increase in payroll of $15.6 million, an approximate $15.4 million increase in stock-based compensation and an increase of approximately $4.6 million in other G&A during the year ended December 31, 2017. The increase of $15.6 million in payroll was primarily attributable to added employees, severance pay and bonuses. The $15.3 million increase in stock-based compensation during 2017 was caused in part by added employees and higher average prices of the Company’s stock.

  

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Depreciation, Depletion, and Amortization

 

Depreciation, depletion, and amortization (“DD&A”) was $7.0 million during the year ended December 31, 2017, compared to $1.7 million during the year ended December 31, 2016, an increase of $5.3 million, or 314%. Our DD&A rate decreased to $12.21 per BOE during the year ended December 31, 2017 from $12.25 per BOE during the year ended December 31, 2016. The DD&A expense increased due to an increase in volumes produced by 447,366 BOE or 350%, from 127,863 BOE during the year ended December 31, 2016 to 575,229 BOE during the year ended December 31, 2017.

 

Impairment of Evaluated Oil and Natural Gas Properties

 

We recorded impairment charges of $10.5 million and $4.7 million during the years ended December 31, 2017 and 2016, respectively. Under the full cost method of accounting, we are required on a quarterly basis to determine whether the book value of our oil and natural gas properties is less than or equal to the “ceiling,” based upon the expected after tax present value of the future net cash flows discounted at 10% from our proved reserves. Any excess of the net book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense. For the year ended December 31, 2017, higher capital expenditures with slower than expected development of proved reserves contributed to the excess of net book value of our oil and natural gas properties over the ceiling resulting in the recognition of an impairment charge of $10.5 million. For the year ended December 31, 2016, the impairment charge of $4.7 million resulted from the impact of less favorable commodity prices which adversely affected estimated proved reserve volumes and future estimated revenues.

 

    Years Ended December 31,              
    2017     2016     Variance     %  
    (In Thousands)              
Other income (expenses):                                
Other income   $ 18     $ 90     $ (72 )     -80 %
Inducement expense     -       (8,307 )     8,307       100 %
Gain on extinguishment of debt and modification of convertible debentures     -       852       (852 )     -100 %
Loss from commodity derivatives, net     (1,063 )     -       (1,063 )     - %
Loss from fair value changes of debt conversion and warrant derivatives     (6,260 )     (1,222 )     (5,038 )     -100 %
Loss in fair value changes of conditionally redeemable 6% preferred stock     (41 )     (701 )     660       94 %
Interest expense     (18,757 )     (4,924 )     (13,833 )     -281 %
Total other income (expenses)   $ (26,103 )   $ (14,212 )   $ (11,891 )     -84 %

 

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Inducement Expense

 

During the year ended December 31, 2016, inducement expense of $8.3 million was incurred as a result of debt and equity restructuring in connection with the Brushy Resources merger. There was no inducement expense incurred during the year ended December 31, 2017.

 

Loss from Commodity Derivatives

 

During the fourth quarter of 2017, oil price derivatives were entered into with counterparties. Upon entering into the derivative transactions, oil prices increased. As a result, for the year ended December 31, 2017, we recorded a loss of $0.2 million on settlements and a loss of $0.9 million on the unsettled position as a result of the changes in fair value of the oil commodity derivatives. During the year ended December 31, 2016, we did not participate in any commodity derivative transactions.

 

Loss from Fair Value Changes of Debt Conversion and Warrant Derivative

 

The change in fair values of derivative instruments comprised a loss of $6.3 million during the year ended December 31, 2017, as compared to a loss of $1.2 million during the year ended December 31, 2016.

 

  · Second Lien Term Loan Derivative Liability. On April 26, 2017, we entered into the Second Lien Credit Agreement (as hereinafter defined). The Second Lien Term Loan and the Delayed Draw Term Loans (as such terms are hereinafter defined) funded thereunder during the fourth quarter of 2017 included a make-whole premium and a conversion feature, which is required to be recorded as an embedded derivative and bifurcated from its host contract. These features are therefore recorded as derivative liabilities at fair value for each reporting period based upon values determined through the use of the discounted lattice model. The embedded derivatives were recorded at closing as a derivative liability with a fair value of $65.6 million. At December 31, 2017, the fair value of the derivative liabilities associated with the loan conversion features was $72.7 million. As a result, we recorded an unrealized loss of $7.1 million on the change in fair value of derivative liabilities associated with the loan conversion features.

 

·SOS Warrant Liability. On June 23, 2016, in conjunction with the merger with Brushy Resources, we issued to SOS Investment 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 years ended December 31, 2017 and 2016, we incurred an unrealized loss of $0.04 million and an unrealized gain of $0.02 million, respectively on the SOS warrant liability.

 

  · Heartland Warrant Liability. On January 8, 2015, we entered into a credit agreement with Heartland Bank (the “Heartland Credit Agreement”). In connection with the Heartland Credit Agreement, we issued to Heartland Bank a warrant to purchase up to 22,500 shares of our common stock at an exercise price of $25.00. The warrant contained a price protection feature that would have automatically reduced the exercise price if we entered into another agreement pursuant to which warrants were issued with a lower exercise price and would also have triggered an adjustment to the number of underlying shares of common stock. On June 14, 2017, we executed an amended and restated warrant agreement with Heartland Bank whereby we issued a warrant to purchase 160,714 of common stock at an exercise price of $3.50 to replace the original warrant to purchase 22,500 shares of common stock to settle a disagreement regarding the fair value change pursuant to the anti-dilution provisions in the original warrant. The amended and restated warrant agreement no longer contains the same anti-dilution provisions. As a result of the reissuance of the warrants, we recorded $0.04 million realized gain and $0.03 million unrealized gain in fair value of the derivative liability related to such warrants during the years ended December 31, 2017 and 2016, respectively.

 

·Bristol Warrant Liability. On September 2, 2014, we entered into a consulting agreement with Bristol Capital, LLC (“Bristol”), pursuant to which we issued Bristol a warrant to purchase up to 100,000 shares of our common stock at an exercise price of $20.00 (or, in the alternative, options exercisable for 100,000 shares of common stock, but in no case, both). The agreement had a price protection feature that automatically reduced the exercise price of the warrant if we entered into another consulting agreement pursuant to which warrants were issued with a lower exercise price, which was triggered in year 2016.  On March 14, 2017, we issued 77,131 shares of common stock to Bristol pursuant to a settlement agreement for a cashless exercise of the warrant.  The Bristol warrant was also revalued on March 14, 2017 resulting in a realized gain in fair value of $0.8 million and decreasing the Bristol derivative liability to $0.4 million.   As a result of the cashless exercise, we reclassified the $0.4 million of Bristol derivative liability to additional paid-in capital as of March 31, 2017.  For the years ended December 31, 2017 and 2016, we recorded $0.8 million of realized gain and $0.2 million of unrealized loss on the Bristol warrant, respectively.

 

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Interest Expense

 

Interest expense for the year ended December 31, 2017, was $18.8 million, compared to $4.9 million for the year ended December 31, 2016. For the year ended December 31, 2017, we incurred interest expense of $1.9 million for quarterly interest payments on notes payable and term loans, $6.6 million of paid-in-kind interest, $8.5 million related to amortized debt discount on our Second Lien Term Loans and $1.8 million of amortized debt issuance costs, as compared to the year ended December 31, 2016, when we incurred $1.7 million of interest expense and $3.2 million of non-cash interest relating to amortized debt issuance costs on debentures, convertible notes and non-convertible notes.

 

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 and 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.

 

Based upon current commodity price expectations for 2018, we believe that with the net proceeds received on January 31, 2018, we will be able to fund our currently planned development program and operations, including our working capital requirements, with a combination of cash and cash flow. As of March 2, 2018, we have a total cash balance of approximately $83.7 million. Our Board has approved a drilling and completion capital expenditure program of $103.2 million for the year ending December 31, 2018, and a total operational capital expenditure program of $115.5 million, excluding capital expenditures for leasing activity and acquisitions. In addition, 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 2018 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 in the event of capital constraints or reduced returns on investment as a result of commodity price weakness.

 

Over the long term, we expect growth in our production as a result of our development program to allow us to fund an increasing portion of our capital expenditures from cash flow.  We expect that we will fund the remaining portion of our capital expenditures using proceeds from a combination of debt, preferred stock, and equity issuance.   

 

Information about our cash flows for the year ended December 31, 2017, are presented in the following table (in thousands):

 

    Year ended December 31,  
    2017     2016  
Cash provided by (used in):                
Operating activities   $ (7,243 )   $ (6,309 )
Investing activities     (147,502 )     (19,130 )
Financing activities     160,469       37,067  
Net change in cash   $ 5,724     $ 11,628  

   

Operating activities. For the year ended December 31, 2017, net cash used in operating activities was $7.2 million, compared to $6.3 million for the year ended December 31, 2016. The increase of $0.9 million in cash used in operating activities was primarily attributable to higher general and administrative costs as a result of our increased operational activity during 2017.

  

Investing activities. For the year ended December 31, 2017, net cash used in investing activities was $147.5 million compared to $19.1 million for the year ended December 31, 2016. The $147.5 million in cash used in investing activities was primarily attributable to the following:

    

  · An increase of $68.5 million in drilling and completion costs, including six Delaware Basin wells of which five were completed during the year ended December 31, 2017 compared to one well drilled during the prior year. There were minimal drilling activities in the DJ Basin during the year ended December 31, 2016;
  · An increase of $2.2 million in workover costs associated with vertical wells to increase proved reserves;
  · An increase of $78.1 million attributable to the acquisition of additional working interests in oil and natural gas leases of which $20.8 million are related to oil and natural gas leases in Winkler and Loving Counties, Texas, $49.7 million are related to oil and natural gas leases in Lea County, New Mexico, and $7.6 million are related to oil and leases in Reeves County, Texas; and
  · Offset by net proceeds of $1.3 million received from the divestiture of the DJ Basin properties and non-operated properties.

 

Financing activities. For the year ended December 31, 2017, net cash provided by financing activities was $160.5 million compared to cash provided by financing activities of $37.1 million during the year ended December 31, 2016. The $160.5 million in net cash provided by financing activities included the following:

 

  ·

An increase of $6.7 million in net proceeds from the exercise of the accordion features of the First Lien Term Loan (as hereinafter defined);

  ·

An increase of $29.3 million in net proceeds from the Bridge Loan under the amended First Lien Term Loan financing transactions, including $15 million in net proceeds from the Incremental Bridge Loan (as hereinafter defined);

  · An increase of $79.5 million in net proceeds from the Second Lien Term Loan (as hereinafter defined) financing transactions;

  

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·

An increase of $70.0 million in net proceeds from the Delayed Draw Term Loan (as hereinafter defined) under the amended Second Lien Credit Agreement financing transactions.

·An increase of $0.7 million in proceeds received from the exercise of stock warrants and stock options;
·Proceeds of $18.4 million from the March 2017 Private Placement (as hereinafter defined), net of financing costs.

 

These increases in proceeds were offset by the following:

 

·Repayment of Series B Preferred Stock (including dividends) in the amount of $2.3 million;
·Repayment of the First Lien Term Loan in the amount of $38.1 million; and
·Payments of $3.7 million relating to payment of taxes withheld on stock-based compensation.

 

First Lien Credit Agreement and Bridge Loans

 

On September 29, 2016, we entered into a first lien credit agreement by and among us and our wholly owned subsidiaries, Brushy Resources, Impetro Operating and Resources, and the lenders party thereto and T.R. Winston & Company, LLC acting as initial collateral agent (the “First Lien Credit Agreement”).

 

The First Lien Credit Agreement provided for a $50 million three-year senior secured term loan with initial commitments of $31 million. On February 7, 2017, pursuant to the terms of the First Lien 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 “First Lien Term Loan”).

 

In connection with the exercise of the accordion advance feature for $7.1 million, we incurred $0.4 million in commitment fees and also amended certain warrants held by the lenders to purchase up to approximately 738,638 shares of common stock, such that the exercise price per share was lowered from $2.50 to $0.01. We accounted for these repriced warrants as additional debt discount for $1.0 million, to be accreted, together with the remaining $0.6 million debt discount at December 31, 2016, over the remaining term of the loan. On April 26, 2017, we fully paid off the amount outstanding of $38.1 million including accrued interest on the First Lien Term Loan. As a result, for the fiscal year ended December 31, 2017, we fully amortized approximately $3.0 million of remaining deferred financing costs and debt discount. This amount was recorded as a non-cash component of interest expense.

 

On April 24, 2017, and subsequently on April 26, 2017, July 25, 2017, and October 19, 2017, we entered into the first, second, third, and fourth amendments (together, the “First Lien Amendments”), respectively, to the First Lien Credit Agreement. The First Lien Amendments, among other things, added Lilis Operating and Hurricane Resources as guarantors, added certain lenders, and extended further credit in the form of an initial bridge loan in an aggregate principal amount of $15.0 million (the “Initial Bridge Loan”). The Initial Bridge Loan was fully drawn on April 24, 2017, and is secured by the same first priority liens on substantially all of our assets as the First Lien Term Loan. Additionally, pursuant to the First Lien Amendments, the lenders made further extensions of credit, in addition to the currently existing loans under the First Lien Credit Agreement (the “Bridge Loans”), in the form of an additional, incremental bridge loan in an aggregate principal amount of $15.0 million (the “Incremental Bridge Loan”, and together with the Bridge Loans, the “First Lien Loans”). The First Lien Loans, including the Incremental Bridge Loan, were fully drawn as of October 19, 2017.

 

The First Lien Credit Agreement, as amended, (a) provides that, effective as of October 1, 2017, the unpaid principal of the First Lien Loans will bear (i) cash interest at a rate per annum of 10% and (ii) additional interest at a rate per annum of 6%, payable only in-kind by increasing the principal amount of the First Lien Loans by the amount of such interest due on each interest payment date and (b) permits the loans under the Second Lien Credit Agreement to equal an increased amount of up to $175.0 million. The First Lien Loans mature on October 21, 2018 and may be repaid in whole or part at any time at our option, subject to the payment of certain specified prepayment premiums. Additionally, the First Lien Loans are subject to mandatory prepayment with the net proceeds of certain asset sales and casualty events, subject to our right to reinvest the net proceeds of asset sales and casualty events within 180 days.

 

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Second Lien Credit Agreement

 

On April 26, 2017, we entered into a Second Lien Credit Agreement by and among us and certain of our subsidiaries, as guarantors (the “Guarantors”), Wilmington Trust, National Association, as administrative agent, and the lenders party thereto (the “Second Lien Credit Agreement”), comprised of convertible loans in an aggregate initial principal amount of up to $125 million. The first tranche of an $80 million term loan (the “Second Lien Term Loan”) was fully drawn and funded on April 26, 2017. The second tranche of up to $45 million in delayed-draw term loans (the “Delayed Draw Term Loan” and, together with the Second Lien Term Loan, the “Second Lien Loans”) was funded on October 4, 2017 and an additional $25 million on November 10, 2017. Each tranche of Second Lien Loans will bear interest at a rate per annum of 8.25%, compounded quarterly in arrears and payable only in-kind by increasing the principal amount of the loan by the amount of the interest due on each interest payment date.

 

On October 3, 2017, we entered into a first amendment to the Second Lien Credit Agreement (“Amendment No. 1 to the Second Lien Credit Agreement”). The purpose of Amendment No. 1 to the Second Lien Credit Agreement is to waive certain conditions precedent to the drawing of the Delayed Draw Term Loan under the Second Lien Credit Agreement and to provide for the funding of such Delayed Draw Term Loan upon the signing of the lease acquisition agreement with KEW Drilling, a Delaware limited partnership. We borrowed the full $45.0 million of the availability under the Delayed Draw Term Loan on October 4, 2017.

 

On October 19, 2017, we entered into a second amendment to the Second Lien Credit Agreement (“Amendment No. 2 to the Second Lien Credit Agreement”). Amendment No. 2 to the Second Lien Credit Agreement permits us to incur the Incremental Bridge Loan under the First Lien Credit Agreement.

 

On November 10, 2017, we entered into a third amendment to the Second Lien Credit Agreement (“Amendment No. 3 to the Second Lien Credit Agreement”). Amendment No. 3 to the Second Lien Credit Agreement increased by $25 million the amount of Delayed Draw Term Loans available for borrowing under the Second Lien Credit Agreement. The additional $25.0 million of Delayed Draw Term Loan was drawn on November 10, 2017. Proceeds of the additional loans may be used to fund oil and natural gas property acquisitions, subject to certain limitations, drilling and completions costs or for other general corporate purposes.

 

The Second Lien Loans are secured by second priority liens on substantially all of our and our Guarantors’ assets, and all of the obligations thereunder are unconditionally guaranteed by each of the Guarantors. The Second Lien Loans mature on April 26, 2021. The Second Lien Loans are subject to mandatory prepayment with the net proceeds of certain asset sales, casualty events and debt incurrences, subject to our right to reinvest the net proceeds of asset sales and casualty events within 180 days and, in the case of asset sales and casualty events, prepayment of the Bridge Loan. We may not voluntarily prepay the Second Lien Loans prior to March 31, 2019, except (a) in connection with a Change of Control (as defined in the Second Lien Credit Agreement) or (b) if the closing price of our common stock on the principal exchange on which it is traded has been equal to or greater than 110% of the Conversion Price (as defined below) for at least 20 of the 30 trading days immediately preceding the prepayment. We are required to pay a make-whole premium in connection with any mandatory or voluntary prepayment of the Loans.

 

Each tranche of the Second Lien Loans is separately convertible at any time, in full and not in part, at the option of Värde Partners, Inc., the Lead Lender, as follows:

 

·70% of the principal amount of each tranche of Second Lien Loans, together with accrued paid-in-kind interest and a make-whole premium on such principal amount (the “Conversion Sum”), will convert into a number of newly issued shares of common stock determined by dividing the total of the Conversion Sum by $5.50 (subject to certain customary adjustments, the “Conversion Price”); and

 

·30% of the Conversion Sum will convert on a dollar for dollar basis into a new second lien term loan (the “Take Back Loans”).

 

The terms of the Take Back Loans will be substantially the same as the terms of the Second Lien Loans, except that the Take Back Loans will not be convertible and will bear interest payable in cash at a rate of LIBOR plus 9% (subject to a 1% LIBOR floor).

 

Additionally, we will have the option to convert the Second Lien Loans, in whole or in part, into shares of common stock at any time or from time to time if, at the time of exercise of our conversion option, the closing price of the common stock on the principal exchange on which it is traded has been at least 150% of the Conversion Price then in effect for at least 20 of the 30 immediately preceding trading days. Conversion at our option will occur on the same terms as conversion at the lender’s option.

 

As discussed in Note 6 to our consolidated financial statements in Item 8 of this Annual Report, we separately account for the embedded conversion features as a derivative instrument in accordance with accounting guidance relating to recording embedded derivatives at fair value. The initial fair value of the embedded derivatives was recorded as a debt discount to the convertible Second Lien Term Loan. The debt discount is amortized over the term of the Second Lien Term Loan using effective interest rate.

 

Restrictive Covenants

 

As of December 31, 2017, the Company’s First Lien Credit Agreement and Second Lien Credit Agreement contained various covenants, including restrictions on additional indebtedness, payment of cash dividends on common stock and preferred stock, and maintenance of certain financial ratios. The First Lien Credit Agreement, as amended, required that, commencing with the testing period ending at December 31, 2018, we satisfy an asset coverage ratio (“ACR”) test by maintaining an ACR of 1.00 to 1.00 or greater. In addition, the Second Lien Credit Agreement requires us to maintain, commencing with the testing period ending June 30, 2018, an ACR of 1.00 to 1.00. or greater.

 

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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 an additional approximately 2.6 million shares of common stock. Each unit consists of one share of common stock and a warrant to purchase 0.50 shares of common stock, at a price per unit of $3.85. Each warrant has an exercise price of $4.50 and may be subject to redemption by us, upon prior written notice, if the price of our common stock closes at or above $6.30 for 20 trading days during a consecutive 30 trading day period. As of December 31, 2017, we received aggregate gross proceeds of $20.0 million and issued 5,194,821 shares of common stock and warrants to purchase 2,597,420 shares of common stock.

 

Subsequent Events

  

Purchase and Sale Agreement

 

On January 30, 2018, we entered into a Purchase and Sale Agreement (the “Purchase and Sale Agreement”) with OneEnergy Partners Operating, LLC (“OEP”), pursuant to which we agreed to purchase from OEP, and OEP agreed to sell to us, certain oil and gas properties and related assets for a purchase price of $70 million, subject to customary purchase price adjustments (the “OEP Acquisition”).

 

The unadjusted purchase price for the OEP Acquisition will consist of $40 million in cash and $30 million in shares of our common stock , valued at a price per share equal to (i) the volume-weighted average trading price of the common stock on the NYSE American for the 20 consecutive trading days ending on and including the first trading day preceding the closing date of the OEP Acquisition multiplied by (ii) 1.05, but in no event may such price be less than $4.25 or greater than $5.25. We intend to fund the cash portion of the purchase price with a portion of the net proceeds from the transaction described under “Preferred Stock Issuance” below.

 

The properties to be acquired by us pursuant to the Purchase and Sale Agreement consist of approximately 2,798 net leasehold acres in the Delaware Basin in Lea County, New Mexico, with average daily net production for the year ended December 31, 2017 of approximately 425 barrels of oil equivalent.

 

The Purchase and Sale Agreement contains customary terms and conditions, including title and environmental due diligence provisions, representations and warranties, covenants and indemnification provisions. The Purchase and Sale Agreement also includes registration rights provisions pursuant to which, among other matters, (i) we will be required to file with the SEC a registration statement under the Securities Act, registering for resale the shares of common stock issued to OEP pursuant to the Purchase and Sale Agreement and (ii) OEP will have piggyback rights to include shares of common stock in certain underwritten offerings.

 

We expect to close the OEP Acquisition in March 2018, subject to the satisfaction of customary closing conditions.

 

Preferred Stock Issuance

 

On January 30, 2018, we entered into a Securities Purchase Agreement (the “Securities Purchase Agreement”) with certain private funds affiliated with Värde Partners, Inc. (the “Purchasers”), pursuant to which we agreed to issue and sell to the Purchasers, and the Purchasers agreed to purchase from us, 100,000 shares of a newly created series of preferred stock of the Company, designated as “Series C 9.75% Convertible Participating Preferred Stock” (the “Series C Preferred Stock”), for a purchase price of $1,000 per share, or an aggregate of $100 million. Värde Partners, Inc. is the lead lender, and certain private funds affiliated with Värde Partners, Inc. are lenders, under our Second Lien Credit Agreement.

 

Closing of the issuance and sale of the shares of Series C Preferred Stock pursuant to the Securities Purchase Agreement occurred on January 31, 2018. We intend to use the net proceeds from the sale of the shares of Series C Preferred Stock to fund the cash portion of the consideration for the OEP Acquisition and a portion of our 2018 capital expenditures budget.

 

The terms of the Series C Preferred Stock are set forth in the Certificate of Designation for the Series C Preferred Stock (the “Certificate of Designation”) filed by us with the Secretary of State of the State of Nevada on January 31, 2018. The following is a description of the material terms of the Series C Preferred Stock and the Securities Purchase Agreement.

 

Ranking. The Series C Preferred Stock ranks senior to our common stock with respect to dividends and rights on the liquidation, dissolution or winding up of the Company.

 

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Stated Value. The Series C Preferred Stock has a per share stated value of $1,000, subject to increase in connection with the payment of dividends in kind as described below (the “Stated Value”).

 

Dividends. Holders of shares of Series C Preferred Stock will be entitled to receive cumulative preferential dividends, payable and compounded quarterly in arrears on January 1, April 1, July 1 and October 1 of each year, commencing April 1, 2018, at an annual rate of 9.75% of the Stated Value until April 26, 2021, after which the annual dividend rate will increase to 12.00% if paid in full in cash or 15.00% if not paid in full in cash. Dividends are payable, at our option, (i) in cash, (ii) in kind by increasing the Stated Value by the amount per share of the dividend or (iii) in a combination thereof. We expect to pay dividends in kind for the foreseeable future. In addition to these preferential dividends, holders of shares of Series C Preferred Stock will be entitled to participate in any dividends paid on the common stock on an as-converted basis.

 

Optional Redemption. We have the right to redeem the Series C Preferred Stock, in whole or in part at any time (subject to certain limitations on partial redemptions), at a price per share equal to (i) the Stated Value then in effect multiplied by (a) 120% if redeemed during 2018, (b) 125% if redeemed during 2019 or (c) 130% if redeemed after 2019, plus (ii) accrued and unpaid dividends thereon and any other amounts payable by us in respect thereof (the “Optional Redemption Amount”). The Series C Preferred Stock is perpetual and is not mandatorily redeemable at the option of the holders, except upon the occurrence of a Change of Control (as defined in the Certificate of Designation) as described below.

 

Conversion. Each share of Series C Preferred Stock is convertible at any time at the option of the holder into a number of shares of common stock equal to (i) the applicable Optional Redemption Amount divided by (ii) a conversion price of $6.15, subject to adjustment (the “Conversion Price”). The Conversion Price will be subject to proportionate adjustment in connection with stock splits and combinations, dividends paid in stock and similar events affecting the outstanding common stock. Additionally, the Conversion Price will be adjusted, based on a broad-based weighted average formula, if we issue, or are deemed to issue, additional shares of common stock for consideration per share that is less than the lesser of (i) $5.25 and (ii) the Conversion Price then in effect, subject to certain exceptions and to the Share Cap (as defined below).

 

We have the right to force the conversion of any or all of the outstanding shares of Series C Preferred Stock if (i) the volume-weighted average price per share of the common stock on the principal exchange on which it is then traded has been at least 140% of the Conversion Price then in effect for at least 20 of the 30 consecutive trading days immediately preceding the exercise by us of the forced conversion right and (ii) certain trading and other conditions are satisfied.

 

To comply with rules of the NYSE American, the Certificate of Designation provides that the number of shares of common stock issuable on conversion of a share of Series C Preferred Stock may not exceed (i) the Stated Value divided by (ii) $4.42 (which was the closing price of the common stock on the NYSE American on January 30, 2018) (the “Share Cap”) prior to approval by our stockholders of the issuance of shares of common stock in excess of the Share Cap upon conversion of shares of Series C Preferred Stock. The Securities Purchase Agreement requires us to seek such stockholders approval at our next special or annual meeting of stockholders, which must occur within six months after the initial issuance of the Series C Preferred Stock. We intend to seek such stockholders approval at our 2018 annual meeting of stockholders.

 

Change of Control. Upon the occurrence of a Change of Control (as defined in the Certificate of Designation), each holder of shares of Series C Preferred Stock will have the option to:

 

  · cause us to redeem all of such holder’s shares of Series C Preferred Stock for cash in an amount per share equal to (i) the Optional Redemption Amount plus (ii) 2.5% of the Stated Value, in each case as in effect immediately prior to the Change of Control;

 

  · convert all of such holder’s shares of Series C Preferred Stock into the number of shares of common stock into which such shares are convertible immediately prior to the Change of Control; or

 

  · continue to hold such holder’s shares of Series C Preferred Stock, subject to any adjustments to the Conversion Price or the number and kind of securities or other property issuable upon conversion resulting from the Change of Control and to our or our successor’s optional redemption rights described above.

 

Liquidation Preference. Upon any liquidation, dissolution or winding up of the Company, holders of shares of Series C Preferred Stock will be entitled to receive, prior to any distributions on our common stock or other capital stock ranking junior to the Series C Preferred Stock, an amount per share of Series C Preferred Stock equal to the greater of (i) the Optional Redemption Amount then in effect and (ii) the amount such holder would receive in respect of the number of shares of common stock into which a share of Series C Preferred Stock is then convertible.

 

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Board Designation Rights. The Certificate of Designation provides that holders of shares of Series C Preferred Stock will have the right, voting separately as a class, to designate (i) two members of our board of directors (the “Board”) for as long as the shares of common stock issuable on conversion of the outstanding shares of Series C Preferred Stock represent at least 15% of the outstanding shares of common stock (giving effect to conversion of all outstanding shares of Series C Preferred Stock) and (ii) one member of the Board for as long as the shares of common stock issuable on conversion of the outstanding shares of Series C Preferred Stock represent at least 7.5% of the outstanding shares of common stock (giving effect to conversion of all outstanding shares of Series C Preferred Stock).

 

The Securities Purchase Agreement separately grants to the Purchasers substantially identical rights to appoint members of the Board as long as the Purchasers and their affiliates beneficially own (as defined in Rule 13d-3 under the Securities Exchange Act of 1934, as amended) shares of common stock issued or issuable upon conversion of shares of Series C Preferred Stock representing the 15% and 7.5% thresholds of the outstanding common stock described above. However, the number of members of the Board the Purchasers have the right to designate under the Securities Purchase Agreement will be reduced by the number of directors holders of shares of Series C Preferred Stock have the right to appoint under the Certificate of Designation.

 

The Board members designated by holders of shares of Series C Preferred Stock pursuant to the Certificate of Designation or by the Purchasers pursuant to the Securities Purchase Agreement must be reasonably acceptable to the Board and its Nominating and Corporate Governance Committee, acting in good faith, but any investment professional of Värde Partners, Inc. or its affiliates will be deemed to be reasonably acceptable. In addition, such Board designees must satisfy applicable SEC and stock exchange requirements and comply with our corporate governance guidelines.

 

In accordance with our bylaws, the Board has increased the number of directors constituting the entire Board from seven to nine to allow for the appointment of the Board members designated by the holders of shares of Series C Preferred Stock. We are required to appoint the two Board members initially designated by the holders of shares of Series C Preferred Stock within ten business days after notice to the us from the holders of the identity of such designees, subject to confirmation that such designees meet the qualifications described above. Pursuant to the terms of the Securities Purchase Agreement, Markus Specks and John Johanning were designated by the Purchasers for appointment to the Board. Mr. Specks and Mr. Johanning serve as managing directors and technical director, respectively, of Värde Partners, Inc. and/or its affiliates. On March 1, 2018, the Board approved the appointments of Mr. Specks and Mr. Johanning to the Board.

 

Voting Rights; Negative Covenants. In addition to the Board designation rights described above, holders of shares of Series C Preferred Stock will be entitled to vote with the holders of shares of our common stock, as a single class, on all matters submitted for a vote of holders of shares of common stock. When voting together with the common stock, each share of Series C Preferred Stock will entitle the holder to a number of votes equal to (i) the Stated Value as of the applicable record date or other determination date divided by (ii) $4.42 (the closing price of the common stock on the NYSE American on January 30, 2018).

 

The Certificate of Designation provides that, as long as any shares of Series C Preferred Stock are outstanding, we may not, without the prior affirmative vote or prior written consent of the holders of a majority of the outstanding shares of Series C Preferred Stock:

 

  · amend our articles of incorporation or bylaws in any manner that materially and adversely affects any rights, preferences, privileges or voting powers of the Series C Preferred Stock or holders of shares of Series C Preferred Stock;

 

  · issue, authorize or create, or increase the issued or authorized amount of, the Series C Preferred Stock, any class or series of capital stock ranking senior to or in parity with the Series C Preferred Stock, or any security convertible into or evidencing the right to purchase any shares of Series C Preferred Stock or any such senior or parity stock, other than equity, the proceeds of which, are used to immediately redeem all of the outstanding shares of Series C Preferred Stock pursuant to our optional redemption rights described above;

 

  · subject to certain exceptions, declare or pay any dividends or distributions on, or redeem or repurchase, or permit any of its controlled subsidiaries to redeem or repurchase, shares of our common stock or any other shares of our capital stock ranking junior to the Series C Preferred Stock, subject to certain exceptions;

 

  · authorize, issue or transfer, or permit any of our controlled subsidiaries to authorize, issue or transfer, any equity (including any obligation or security convertible into, exchangeable for or evidencing the right to purchase any such equity) in any of our subsidiaries other than (i) equity issued or transferred to us or one of our wholly-owned subsidiaries or (ii) equity, the proceeds of which, are used to immediately redeem all of the outstanding shares of Series C Preferred Stock pursuant to the our optional redemption rights described above; or

 

  · subject to certain exceptions, modify the number of directors constituting the entire Board at any time when holders of shares of Series C Preferred Stock have the right to designate a member of the Board.

 

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The Certificate of Designation further provides that, as long as shares of Series C Preferred Stock having an aggregate Optional Redemption Amount of at least $50,000,000 are outstanding, we may not, and may not permit any of our controlled subsidiaries to, without the prior affirmative vote or prior written consent of the holders of a majority of the outstanding shares of Series C Preferred Stock:

 

  · subject to certain exceptions, incur indebtedness or permit to exist any liens on our or our subsidiaries’ assets or properties;

 

  · enter into, adopt or agree to any “restricted payment” or similar provision that restricts or limits the payment of dividends on, or the redemption of, shares of Series C Preferred Stock under any credit facility, indenture or other similar instrument that would be more restrictive on the payment of dividends on, or redemption of, shares of Series C Preferred Stock than those existing as of the date on which shares of Series C Preferred Stock were first issued;

 

  · liquidate or dissolve the Company;

 

  · enter into any material new line of business or fundamentally change the nature of our business, including any acquisition of oil and gas properties outside the Permian Basin; or

 

  · enter into certain transactions with our affiliates unless made on an arm’s-length basis and approved by a majority of the disinterested members of the Board.

 

Transfer Restrictions. The Certificate of Designation provides that shares of Series C Preferred Stock and shares of common stock issued on conversion of shares of Series C Preferred Stock may not be transferred by the holder of such shares, other than to an affiliate of such holder, prior to July 31, 2018. On and after July 31, 2018, such shares will be freely transferable, subject to applicable securities laws.

 

Standstill. The Securities Purchase Agreement includes a customary standstill provision pursuant to which the Purchasers agreed that they will not, directly or indirectly, take certain actions with respect to us or our securities until the earlier of (i) the date on which the Purchasers and their affiliates are no longer entitled to designate any member of the Board pursuant to the Certificate of Designation or the Securities Purchase Agreement and (ii) our failure to pay dividends on the Series C Preferred Stock in full in cash on any dividend payment date occurring after April 26, 2021.

 

Other Terms. The Securities Purchase Agreement contains other terms, including representations, warranties and covenants, that are customary for a transaction of this sort.

 

Registration Rights Agreement

 

On January 31, 2018, in connection with the closing of the issuance of shares of Series C Preferred Stock pursuant to the Securities Purchase Agreement, we entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with the Purchasers pursuant to which, among other matters, we will be required to file with the SEC a registration statement under the Securities Act registering for resale the shares of common stock issuable upon conversion of shares of Series C Preferred Stock. The Registration Rights Agreement also grants to the Purchasers demand and piggyback rights with respect to certain underwritten offerings of our common stock and contains customary covenants and indemnification and contribution provisions.

 

Riverstone First Lien Credit Agreement

 

On January 30, 2018, we entered into an Amended and Restated Senior Secured Term Loan Credit Agreement (the “Riverstone First Lien Credit Agreement”) by and among us, our subsidiaries party thereto as guarantors, Riverstone Credit Management LLC, as administrative agent and collateral agent, and the lenders party thereto. Effective at closing under the Riverstone First Lien Credit Agreement, which occurred on January 31, 2018, the Riverstone First Lien Credit Agreement amended and restated the First Lien Credit Agreement.

 

Pursuant to the Riverstone First Lien Credit Agreement, the lenders thereunder agreed to make term loans to us in the aggregate principal amount of $50 million (the “Riverstone First Lien Loans”), all of which were funded in full at closing at an original issue discount of 1.0% of the principal amount. The Riverstone First Lien Credit Agreement provides the potential for additional term loans of up to $30 million, as requested by us and subject to certain conditions, which additional loans were uncommitted at closing.

 

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We used approximately $31.5 million of the proceeds of the Riverstone First Lien Loans to repay in full our obligations under and retire the First Lien Credit Agreement, which was scheduled to mature in October 2018. We may use the remaining proceeds for capital expenditures, acquisitions and other general corporate purposes, including payment of transaction expenses.

  

Amendment to Second Lien Credit Agreement

 

On January 31, 2018, we entered into a fourth amendment to the Second Lien Credit Agreement (“Amendment No. 4 to the Second Lien Credit Agreement”). The purpose of Amendment No. 4 to the Second Lien Credit Agreement was to, among other matters:

 

  · permit us to enter the Riverstone First Lien Credit Agreement and incur the Riverstone First Lien Loans and related liens;

  · permit us to issue the Series C Preferred Stock; and

  · after the issuance of the Series C Preferred Stock pursuant to the Securities Purchase Agreement, reduce from two to one the maximum number of members of the Board the lenders under the Second Lien Credit Agreement will have the right to appoint following the conversion of the convertible loans under the Second Lien Credit Agreement.

  

Amendments to Riverstone First Lien Credit Agreement and Second Lien Credit Agreement

  

On February 20, 2018, we entered into the following amendments to our existing credit agreements: (i) Amendment No. 1 to the Riverstone First Lien Credit Agreement and (ii) Amendment No. 5 to the Second Lien Credit Agreement. Pursuant to these amendments and a consent letter received from the Purchasers, in their capacity as the holders of all of the issued and outstanding shares of Series C Preferred Stock, we have been granted the right to repurchase shares of our common stock for an aggregate purchase price up to $10 million (subject to certain exceptions and conditions).

 

The commencement of any repurchase of shares of our common stock will be subject to compliance with applicable law, Board approval, and market conditions.

 

Departure of Executive Officers

 

On February 16, 2018, Ariella Fuchs ceased serving as our Executive Vice President, General Counsel, and Secretary. We entered into an agreement with Ms. Fuchs pursuant to which she will receive severance and other consideration pursuant to the terms of her employment agreement and the accelerated vesting of 247,500 stock options and 198,000 shares of restricted stock under stock award agreements plus additional nominal consideration.

 

On March 6, 2018, Brennan Short ceased serving as our Chief Operating Officer. His responsibilities have been assumed by our current management and our existing consultants.

 

Effects of Inflation and Pricing

 

The oil and gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry puts pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Material changes in prices impact the current revenue stream, estimates of future reserves, borrowing base calculations of bank loans and the value of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel. We anticipate business costs will vary in accordance with commodity prices for oil and natural gas, and the associated increase or decrease in demand for services related to production and exploration.

 

Off-Balance Sheet Arrangements

 

As of December 31, 2017, we did not have any off-balance sheet arrangements, and it is not anticipated that we will enter into 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 (“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 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.

 

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Our most significant financial estimates are associated with our estimated proved oil and natural 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 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 natural gas properties are located within the United States, and therefore 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. 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 natural gas reserves. 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 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 natural gas reserve estimates as of December 31, 2017, using the average, first-day-of-the-month price during the 12-month period ended December 31, 2017.

 

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

 

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 amortization base and becomes subject to the depletion calculation.

 

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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.

 

Derivative Instruments

 

All derivative instruments are recorded on the consolidated balance sheet at fair value as either an asset or a liability with changes in fair value recognized currently in earnings. Although derivative instruments are used by the Company to manage the price risk attributable to its expected oil and natural gas production, those derivative instruments have not been designated as accounting hedges under the accounting guidance. All of our derivatives are accounted for as mark-to-market activities. Under ASC Topic 815, “Derivatives and Hedging,” these instruments are recorded on the consolidated balance sheets at fair value as either short term or long-term assets or liabilities based on their anticipated settlement date. The Company nets derivative assets and liabilities by commodity for counterparties where a legal right to such offset exists. Changes in the derivatives' fair values are recognized in current earnings since the Company has elected not to designate its current derivative contracts as cash flow hedges for accounting purposes.

 

The Company has recognized certain conversion features within its Second Lien Term Loan as embedded derivatives that have been bifurcated from the Loan, as defined in Note 4 to our consolidated financial statements in Item 8 of this Annual Report on Form 10-K, and accounted for separately from the debt. Additionally, warrants issued to SOSV Investment LLC (“SOS”) to purchase up to 200,000 shares of the Company’s common stock contain a price protection feature that will automatically reduce the exercise price should the Company enter into another agreement pursuant to which warrants are issued at a lower exercise price. The price protection feature has been recognized as an embedded derivative and accounted for separately.

  

Revenue Recognition

 

We recognize 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.

 

We use the entitlements method of accounting for oil, natural gas, and NGL 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. We had no material oil, or NGL entitlement assets or liabilities as of December 31, 2017 or 2016.

  

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 15 of this Annual Report.

 

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

 

Not applicable.

 

Item 8. Financial Statements and Supplementary Data

 

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

 

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

 

Item 9A. Controls and Procedures

 

Evaluation of Disclosure Controls and Procedures

 

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the Exchange Act. Based on that evaluation, and as described below, management identified a material weakness in the Company’s internal control over financial reporting further discussed below. Internal control over financial reporting is an integral component of the Company’s disclosure controls and procedures. As a result of this material weakness, the Company’s Chief Executive Officer and Chief Financial Officer concluded that, as of the end of the period covered by this Annual Report, the Company’s disclosure controls and procedures were not effective as of December 31, 2017.

 

Management concluded that the consolidated financial statements included in this Annual Report fairly present, in all material respects, the financial position of the Company at December 31, 2017 and 2016, and the consolidated results of operations and cash flows for each of the two years in the period ended December 31, 2017 in conformity with U.S. GAAP.

  

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Management’s Annual Report on Internal Control Over Financial Reporting

 

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Exchange Act). Even an effective system of internal control over financial reporting, no matter how well designed, has inherent limitations, including the possibility of human error, circumvention of controls or overriding of controls and, therefore, can provide only reasonable assurance with respect to reliable financial reporting. Furthermore, the effectiveness of a system of internal control over financial reporting in future periods can change as conditions change. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. 

 

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, 2017, 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 our internal control over financial reporting was not effective as of December 31, 2017 as a result of the material weakness discussed below.

 

A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis. During the audit of our internal control over financial reporting for the year ended December 31, 2017, errors were identified in the Company’s computation of the full cost ceiling test limitation. Design and operating effectiveness deficiencies failed to identify the computational errors which primarily related to the treatment of wells-in-process and future income tax effects. Management has concluded these deficiencies in internal control over financial reporting constituted a material weakness. The errors did not affect the reported results of operations or disclosures in any interim or annual period.

 

BDO USA, LLP, an independent registered public accounting firm, has audited our internal control over financial reporting as of December 31, 2017, as stated in their attestation report set forth under the caption “Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting.”

 

Changes in Internal Control Over Financial Reporting

 

The Company identified a material weakness during the quarter ending June 30, 2017, as described in our Form 10-Q. The Company took measures to remediate the material weakness during the quarters ended September 30, 2017 and December 31, 2017, which included the use of comprehensive checklists to identify and review complex accounting issues, additional guidance obtained from expert accounting technical consultant with respect to the appropriate application of GAAP on non-routine and complex transactions.

 

Management believes that the measures described above have remediated the material weakness identified in our June 30, 2017 Form 10-Q.

 

There has been no other change in our internal control over financial reporting during the three months ended December 31, 2017 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

Plan of Remediation of Material Weakness

 

Management has identified remediation steps, including enhanced analytical analysis and improved management review of the full cost ceiling test calculation in order to remediate this material weakness.

 

Item 9B. Other Information

 

None.

  

PART III

 

Item 10. Directors, Executive Officers and Corporate Governance

 

The following table sets forth information regarding our executive officers, certain other officers and directors as of March 7, 2018. The Board believes that all the directors named below are highly qualified and have the skills and experience required for effective service on the Board.  The directors’ and officers’ individual biographies below contain information about their experience, qualifications and skills that led the Board to nominate, elect or appoint them.

 

Name   Age    Director Since   Position
             
Ronald D. Ormand   59   2015   Executive Chairman of the Board of Directors
Nuno Brandolini   64   2014   Director
R. Glenn Dawson   61   2016   Director
General Merrill McPeak   82   2015   Director
Peter Benz   57   2016   Director
Mark Christensen   49   2017   Director
G. Tyler Runnels   62   2017   Director
John Johanning   32   2018   Director
Markus Specks   33   2018   Director
James Linville   52       Chief Executive Officer
Joseph C. Daches   51       Executive Vice President, Chief Financial Officer and Treasurer
Seth Blackwell   30       Executive Vice President of Land and Business Development  

 

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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 (our “Board”). 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.

 

The following biographies describe the business experience of our directors and executive officers:

 

Ronald D. Ormand: Executive Chairman of the Board of Directors. Mr. Ormand joined our 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 also 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.

 

Mr. Ormand’s qualifications to serve as the Executive Chairman of the Board of Directors include extensive leadership and industry experience, including as a Senior Executive at Magnum Hunter Resources Corporation, Chairman and Head of Investment Banking at MLV, and Head of US Oil and Gas for CIBC.

 

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. Since 2014, Mr. Brandolini has served as Managing Member and Chief Executive Officer of Scorpion Capital, LLC, a private investment company. From 2004 to 2014, 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. 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.

 

As a result of his experience holding executive positions with several private equity firms and his experience as a member of the board of directors of Cheniere Energy, Inc., Mr. Brandolini possesses particular knowledge and experience working with oil and gas companies that strengthen the Board’s collective qualifications, skills, and experience

 

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R. Glenn Dawson: Director. Mr. Dawson joined our Board of Directors on January 13, 2016. Mr. Dawson has over 36 years of experience in oil and gas exploration in North America and since March 2016, has served as 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 its 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 and served as President and CEO of NuLoch Resources, Inc. in 2005, which was acquired by MHR in 2012. 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 Mr. Dawson’s professional experience as the President and Chief Executive Officer of Cuda Energy, Inc. and former President of Bakken Hunter, along with his extensive experience in the oil and gas industry, he possesses particular knowledge and experience in the operations of oil and gas companies that strengthen the Board’s collective qualifications, skills, and experience. 

 

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 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, Loyance Biotherapeutics 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. From 2010 through 2017, General McPeak served as 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.

 

As a result of his professional experience, General McPeak possesses particular knowledge and experience, including, without limitation, his service as Chief of Staff of the U.S. Air Force and position as founding investor and chairman of Ethicspoint (subsequently Navex Global), that strengthen the Board’s collective qualifications, skills, and experience.

 

Peter Benz: Director. Mr. Benz joined our Board of Directors on June 23, 2016, in connection with the completion of the merger with Brushy Resources. Mr. Benz served on Brushy Resource’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 his professional experiences, Mr. Benz possesses particular knowledge and experience in developing companies and capital markets that strengthen our Board of Director’s collective qualifications, skills, and experience.

 

G. Tyler Runnels: Director. Mr. Runnels was appointed to the Board of Directors in September 2017. He is the Chairman and Chief Executive Officer of T.R. Winston & Company (“TRW”). Mr. Runnels has been with TRW since 1990 and became its Chairman and Chief Executive Officer in 2003 when he acquired control of the firm. He has over 30 years of investment banking experience and has led over $2 billion of debt and equity financings, mergers and acquisitions, initial public offerings, bridge financings, and financial restructurings across a variety of industries, including healthcare, oil and gas, business services, manufacturing, and technology. Mr. Runnels serves on the Pepperdine University President’s Campaign Cabinet. Mr. Runnels received a B.S. and MBA from Pepperdine University, and he holds FINRA Series 7, 24, 55, 63 and 79 licenses.

 

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As a result of his professional experience, Mr. Runnels possesses particular knowledge and experience in financing and financial services that strengthen our Board of Director’s collective qualifications, skills, and experience.

 

Mark Christensen: Director. Mr. Christensen was appointed to the Board of Directors in September 2017. Mr. Christensen is the Founder, President and CEO of KES 7 Capital Inc. in Toronto, Canada, and a registrant of the Ontario Securities Commission (OSC). Prior to founding KES 7, Mr. Christensen was Vice Chairman, Head of Global Sales and Trading at GMP Securities, one of Canada’s largest independent investment banks, where he served as a member of the Executive Committee, Compensation Committee and New Names Committee. Mr. Christensen has experience in a broad range of corporate and capital market transactions, from mergers and acquisitions to public and private financings, that total in the tens of billions of dollars. His background in geology and geophysics has provided him with valuable insight into the energy industry, enabling him to advise both institutional investors and energy companies from around the globe. Mr. Christensen holds a Master of Science degree from the University of Windsor in Canada and a Bachelor of Science Degree from the University of Hull in the United Kingdom.

 

As a result of his professional experience, Mr. Christensen possesses particular knowledge and experience in providing advisory services to numerous institutional investors and companies active in the oil and gas industry strengthen our Board of Director’s collective qualifications, skills, and experience.

 

John Johanning: Director. Mr. Johanning was appointed to the Board of Directors in March 2018. Mr. Johanning is the Technical Director of Värde Partners, Inc.’s (“Värde”) energy business. Mr. Johanning joined Värde in May 2017 and presides over the Petroleum Engineering and Geoscience aspects of Värde’s investments in energy. Mr. Johanning is involved in the performance of current Varde investments across active onshore US basins as well as new business decisions in both opportunity screening and asset and company valuations. Prior to joining Värde, from January 2014 until May 2017, Mr. Johanning was a Vice President at Evercore Partners (“Evercore”) in Houston, where he was influential in numerous transactions totaling over $10 billion in transaction value. While at Evercore, Mr. Johanning advised numerous energy companies and financial sponsors on value-maximizing transactions. Mr. Johanning's advisory mandates ranged over a variety of different transaction types including acquisitions and divestures of assets, corporate mergers, and capital raises. Mr. Johanning also worked across all oilfield sectors, gaining transactional experience in the upstream, midstream, downstream and oil field service sectors of the business. Mr. Johanning began his career as a Reservoir Engineer at BP from 2008 to 2014. Based in Houston, he developed oil and gas assets across several US Basins, including the Permian of West Texas and Southeast New Mexico and the Texas Gulf Coast Basin, among others. While in the South Texas Reservoir Management team, Mr. Johanning was responsible for the resource appraisal of a 400,000+ gross acre Eagle Ford Shale position that was deeply rooted in geological and well completion data. While at BP, Mr. Johanning gained a detailed technical understanding of oil and gas assets through the various facets of the business, including Production Engineering, Reservoir Engineering, Drilling and Completions, Geology and Geophysics, as well as Land, Legal and Finance functions. Mr. Johanning graduated from The University of Texas in at Austin in 2008 with a B.S. in Petroleum Engineering.

 

As a result of his professional experience, Mr. Johanning possesses particular knowledge and experience in the operations of oil and gas companies that strengthen our Board of Director’s collective qualifications, skills and experience.

 

Markus Specks: Director. Mr. Specks was appointed to the Board of Directors in March 2018. Mr. Specks is a Managing Director of Värde Partners, Inc. and Head of the firm's Houston office. Mr. Specks leads Värde's energy business, and has experience managing credit, equity, and structured asset-level investments across the energy sector. He serves on Värde 's Investment Committee, as well as several boards of private energy companies. Prior to joining Värde in 2008, Mr. Specks worked in investment banking at Lazard, focusing on middle-market M&A advisory. Mr. Specks holds a B.A. in Government from Lawrence University in Wisconsin.

 

As a result of his professional experience, Mr. Specks possesses particular knowledge and experience in developing companies and capital markets, particularly with oil and gas companies, that strengthen our Board of Director’s collective qualifications, skills, and experience.

 

James (“Jim”) Linville: Chief Executive Officer. Effective August 4, 2017, our Board appointed James Linville to the position of Chief Executive Officer. Mr. Linville was the Company’s President since June 26, 2017 until his appointment to Chief Executive Officer. Mr. Linville most recently held the position of Senior Director of Operations and Development for US Energy Development Corporation (“US Energy”) from January 2016 to June 2017, where he was a senior technical engineering, operational and resource development professional in the company. During his time at US Energy, Mr. Linville led a team of field and office staff consisting of drilling, completions, operations, engineering, reservoir, regulatory and environmental safety professionals. Additionally, Mr. Linville was a member of the Capital Committee at US Energy, tasked with deploying up to approximately $200 million annually in a portfolio of energy related investments, primarily within the Delaware Basin and Eagle Ford. Prior to US Energy, Mr. Linville was Director of Operations at American Energy Permian Basin (“AEPB”) from January 2015 to July 2015, where he managed field operations, completions, production and facilities engineering for a large Midland Basin Wolfcamp shale horizontal development program. Prior to moving into his position as Director of Operations at AEPB, Mr. Linville was Director of Acquisitions at American Energy Partners, LP (“AELP”) from February 2014 to January 2015, where he assembled and led the acquisitions team, consisting of numerous petro-professionals (Reservoir, Operations, Geoscience, Land), who were responsible for screening over 400 acquisition opportunities. While at AELP, Mr. Linville participated in and managed over 100 acquisition evaluations with aggregate value greater than $12 billion. Previously, Mr. Linville was employed at Devon Energy Corporation from January 2001 to January 2014, where he held various engineering and management roles. Prior to Devon Energy Corporation, Mr. Linville held various leadership and engineering (reservoir, production, drilling) and operational roles at Eastern American Energy, Consolidated Oil & Gas, Hallwood Petroleum, Unocal and his own firm Derrick Engineering Corporation. Mr. Linville earned his Bachelor of Science in Petroleum Engineering from New Mexico Tech and his Master of Science in Environmental Engineering from Marshall University. Throughout his career, he has held numerous leadership roles within the Society of Petroleum Engineers (SPE) and was an Industry Advisory Board member at New Mexico Tech and the Oklahoma City SPE Chapter. In addition, Mr. Linville is a Registered Professional Engineer.

 

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. 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.

 

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Seth Blackwell: Executive Vice President of Land and Business Development. Seth Blackwell joined Lilis in December 2016. Mr. Blackwell is a Certified Professional Landman with extensive knowledge and experience in all facets of land management. Prior to joining Lilis, from October 2012 to December 2016, 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 Landmen, North Houston Association of Professional Landmen and the Houston Association of Professional Landmen. 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.

 

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 2017 and through the date of this Annual Report, except as follows:

 

·

Brennan Short, our former COO, filed his Form 3 and one Form 4, reporting two transactions, subsequent to the time prescribed by Section 16(a) of the Exchange Act.

·R. Glenn Dawson filed one Form 4, reporting one transaction, subsequent to the time prescribed by Section 16(a) of the Exchange Act.
·Vertex Fund filed its Form 3 and one Form 4, reporting one transaction, subsequent to the time prescribed by Section 16(a) of the Exchange Act.
·Ronald Ormand filed one Form 4, reporting one transaction, subsequent to the time prescribed by Section 16(a) of the Exchange Act.

 

Board of Directors and Board Committees

 

Our Board of Directors conducts its business through meetings and through its committees. Our Board of Directors held eighteen meetings in 2017 and took action by unanimous written consent on twelve 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 in accordance with the standards for companies listed on the New York Stock Exchange, or the NYSE and the rules and regulations promulgated by the SEC, 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 the independence of its directors. The Board has determined that six of our current directors, Mr. Brandolini, General McPeak, Mr. Benz, Mr. Dawson, Mr. Specks and Mr. Johanning are “independent directors” under the NYSE standards and SEC rules and regulations 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.

 

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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, a nominating and corporate governance committee and a reserves committee. The membership and function of these committees are described below.

 

Audit Committee

 

During the year ended December 31, 2017, each of Mr. Brandolini, General McPeak and Mr. Benz served on the audit committee, who are all currently serving on the audit committee. 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 has determined that each of Mr. Brandolini, General McPeak and Mr. Benz meet the independence requirements of the SEC and NYSE rules and the financial literacy requirements of the NYSE.

 

The audit committee met five times during the year ended December 31, 2017, and acted by written consent once. The audit committee also met separately on several occasions in connection with meetings of the full Board. 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 and Mr. Dawson.  Mr. Dawson is the chairman of the compensation committee.

 

The compensation committee met seven times during the year ended December 31, 2017, and acted by written consent six times. The compensation committee also met separately on several occasions in connection with meetings of the full Board. Consistent with the listing requirements of the NYSE, the Compensation Committee is composed entirely of independent members of our Board of Directors, as each member meets the independence requirements set by the NYSE and applicable federal securities laws.

 

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, and 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 twice during the year ended December 31, 2017, but met separately on several occasions in connection with meetings 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, potential candidates to become members of the Board, recommending membership on standing committees of the Board, developing and recommending to the entire Board 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 whether a mitigation plan is appropriate with respect to any exception 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 2017, there have been no material changes to the procedures by which security holders may recommend nominees to our Board of Directors.

 

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Reserves Committee

 

Our reserves committee currently consists of Mr. Ormand and Mr. Dawson, who is the chairman of the reserves committee.

 

The primary responsibilities of the reserves committee include retaining and terminating independent petroleum engineering consultants (the “IPEC”) retained to assist the Company in the annual and quarterly review of hydrocarbon reserves and approving their compensation and terms of their engagement, establishing expectations of the IPEC and their accountability to the reserves committee, ensuring that the IPEC are independent, and reviewing the Company’s significant reserve engineering principles, policies, internal procedures and assumptions relating to the Company’s reserve estimates and disclosure.

 

Additionally, at the request of our Board, the reserves committee chairperson currently performs certain technical responsibilities with respect to the operational activities of the Company.

 

Communications with our 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: Chief Financial Officer. All communications are compiled by the chief financial officer and forwarded to our 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 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: Chief Financial Officer. 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

 

COMPENSATION DISCUSSION AND ANALYSIS

 

Below is a discussion and analysis of our compensation programs as they applied to our named executive officers—or NEOs—for 2017. Our fiscal year is the calendar year.

 

Our NEOs for 2017 were: (1) James Linville, Chief Executive Officer; (2) Abraham “Avi” Mirman, former Chief Executive Officer; (3) Joseph C. Daches, Chief Financial Officer, Executive Vice President, and Treasurer; (4) Kevin Nanke, former Chief Financial Officer; (5) Ariella Fuchs, former Executive Vice President, General Counsel, and Secretary; (6) Brennan Short, former Chief Operating Officer; and (7) Ronald D. Ormand, Executive Chairman.

 

Compensation Philosophy and Objectives

 

Our compensation programs are designed to motivate our executives and employees and enable them to participate in the growth of our business, while also driving the creation of long-term stockholder value. We provide our executive officers with both variable and fixed compensation, including base salaries, short-term cash incentive compensation, and long-term equity incentive compensation. We strive to balance short-term awards, such as annual performance-based bonuses, with longer-term performance awards, such as equity awards, in order to provide incentives for both short- and long-term performance.

 

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Role of Our Compensation Committee

 

Our compensation committee is appointed by our Board of Directors—or our Board—to discharge the Board’s responsibilities relating to the compensation of our Chief Executive Officer—or our CEO—and our other executive officers. The compensation committee has overall responsibility for approving and evaluating all compensation plans, policies, and programs of the Company as they affect our executive officers.

 

During 2017, our compensation committee consisted of Nuno Brandolini, R. Glenn Dawson, and General Merrill A. McPeak (Chair). At least annually, the compensation committee: (1) reviews and approves the corporate goals and objectives applicable to the compensation of our CEO; (2) evaluates our CEO’s performance in light of those goals and objectives; and (3) determines and approves our CEO’s compensation level based on this evaluation. The compensation committee also, on at least an annual basis, reviews and approves the annual base salaries and annual incentive opportunities of our executive officers other than our CEO. The compensation committee also, periodically and as and when appropriate, reviews and approves the following as they affect our executive officers: (1) all other incentive awards and opportunities, including both cash-based and equity-based awards and opportunities; (2) any employment agreements and severance arrangements; (3) any change in control agreements and severance protection plans and change in control provisions affecting any elements of compensation and benefits; and (4) any special or supplemental compensation and benefits for our executive officers and former executive officers.

 

Our compensation committee is governed by a written charter, a copy of which is available on the Investor Relations section of our website at: http://investors.lilisenergy.com/.

 

Role of Our Compensation Consultant

 

Our compensation committee has sole authority over the selection, use, and retention of any compensation consultant or any other experts engaged to assist the compensation committee in discharging its responsibilities. In February 2017, the compensation committee engaged Longnecker & Associates (“Longnecker”) to assist with its overall compensation review and decision-making.  In May 2017, Longnecker conducted an independent, comprehensive, broad-based analysis of our executive compensation program, and the compensation committee used this analysis as one of several reference points in making decisions regarding 2017 compensation. Longnecker’s objectives were to:

 

  · review the total direct compensation (base salary, annual incentives, and long-term incentives) for the NEOs;

 

  · assess the competitiveness of executive compensation, based on revenue size, asset size, enterprise value and market capitalization, as compared to the peer group and published survey companies in the oil and gas industry; and

 

  · provide conclusions and recommend considerations for total direct compensation.

 

Longnecker also provides guidance on industry best practices. This information assists us in developing and implementing compensation programs generally competitive with those of other companies in our industry and other companies with which we generally compete for executive talent.

 

Longnecker performed services solely on behalf of the compensation committee. In accordance with the rules and regulations of the SEC and the NYSE, the compensation committee assessed the independence of Longnecker and concluded that no conflicts of interest exist that would prevent Longnecker from providing independent and objective advice.  

 

The companies used for the executive compensation comparisons in May 2017 included the following:

 

SM Energy Company RSP Permian, Inc.
Laredo Petroleum, Inc. Matador Resources Company
Parsley Energy, Inc. Callon Petroleum Company
Carrizo Oil & Gas, Inc. Resolute Energy Corporation
Sanchez Energy Corporation SRC Energy Inc.
Gulfport Energy Corporation Centennial Resource Development, Inc.
PDC Energy, Inc. Jagged Peak Energy Inc.

 

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Longnecker also reviewed survey data as a reference point to compare the compensation of our executives to those of a broad range of companies. The published surveys utilized by Longnecker included the following:

 

  · Economic Research Institute, Executive Compensation Assessor;
  · Mercer, Inc., 2016 Mercer Total Compensation Survey for the Energy Sector;
  · Towers Watson, 2016 CSR General Industry Top Management Compensation Survey Report; and
  · Longnecker & Associates, Energy Industry Long-Term Incentive Compensation Survey.

 

Elements of Compensation

 

The compensation earned by our NEOs for 2017 consisted of base salary, short-term cash incentive compensation, long-term equity incentive compensation consisting of awards of restricted shares and stock options, and miscellaneous employee benefits.

 

We pay each of our NEOs a base salary, which is reviewed annually and not considered to be “at risk,” as it does not vary with the performance of the Company. This base salary is designed to compensate the NEOs for the performance of their duties and responsibilities. Our NEOs are also eligible for annual performance cash bonuses, including certain NEOs being eligible for cash bonuses pursuant to their employment agreements, as described further below under Employment Agreements.

 

Historically, we have provided our NEOs with both short-term and long-term incentive compensation through our 2012 Equity Incentive Plan—or 2012 EIP—and our 2016 Omnibus Incentive Plan—or 2016 Plan—both of which are described in detail below. These plans have been designed to align a meaningful portion of NEO compensation with the financial performance of the Company. Upon our 2016 Plan becoming effective, we stopped granting awards under our 2012 EIP.

 

Our NEOs generally participate in the same health care, disability, life insurance, and other benefit plans made available to our other employees. However, our executives receive a limited number of additional benefits and perquisites described in more detail in the All Other Compensation column of the Summary Compensation Table below. These additional benefits and perquisites generally are provided to our NEOs for their convenience and financial security.

 

Employment Agreements

 

Mr. Linville. We entered into an employment agreement with Mr. Linville dated June 26, 2017, in connection with his appointment as our President. The agreement provides, among other things, that Mr. Linville will receive a base salary of (1) $400,000 from the effective date of the agreement to the one-year anniversary of the effective date and (2) $450,000 from the one-year anniversary of the effective date of his agreement to the two-year anniversary of the effective date. Mr. Linville also received a lump sum cash signing bonus of $100,000 under the agreement. Additionally, Mr. Linville is eligible to receive a lump sum cash retention bonus equal to no less than $200,000 on the one-year anniversary of the effective date of the agreement, subject to his continued service. Mr. Linville is also eligible to receive annual bonuses and 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.

 

On August 4, 2017, we amended our employment agreement with Mr. Linville to reflect his removal as our President and appointment as our CEO. All other terms of the employment agreement remained unchanged.

 

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The initial term of Mr. Linville’s agreement ended December 31, 2017, and the agreement began to renew automatically for additional one-year periods beginning on December 31, 2017. Either party may give notice of non-renewal at least 180 days before the end of the then-current term.

 

On June 26, 2017, Mr. Linville received a grant of 325,000 stock options under our 2016 Plan, with an exercise price of $4.84, which such grant of stock options was conditioned on stockholders’ approval, which was obtained on July 13, 2017. 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. Also, on June 26, 2017, Mr. Linville received a grant of 175,000 shares of restricted stock under our 2016 Plan, with a fair value of $4.84 per share at grant date, which such grant of stock was conditioned on stockholders’ approval, which was obtained on July 13, 2017. 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 his continued service.

 

Under his employment agreement, upon a termination by us without cause or a termination by him for good reason, Mr. Linville will be entitled to (1) a lump sum severance payment equal to 12 months of base salary, (2) 12 months of COBRA premiums, and (3) a lump sum payment equal to $200,000 (representing an amount equal to Mr. Linville’s unpaid sign-on retention bonus). Upon a termination by us without cause or a termination by Mr. Linville for good reason within 12 months after 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. Linville will be entitled to a lump sum severance payment equal to six months of COBRA premiums. All severance payments under Mr. Linville’s employment agreement are subject to his execution of a release of claims against us. The severance payments are also subject to reduction in order to avoid any excise tax associated with Section 280G of the Internal Revenue Code—or the Code—but only if that reduction would result in Mr. Linville receiving a greater net after tax benefit as a result of the reduction.

 

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

 

Mr. Daches. We entered into an employment agreement with Mr. Daches dated January 23, 2017, in connection with his appointment as our Executive Vice President, Chief Financial Officer, and Treasurer. We amended this agreement on May 5, 2017 to eliminate Mr. Daches’ eligibility to receive certain “cash incentive bonuses” that had been tied to BOE and EBITDAX production thresholds, and we replaced those bonuses with an immediate bonus paid out in a mix of cash and stock.

 

The agreement provides, among other things, that Mr. Daches will receive a base salary of (1) $300,000 from the effective date of the agreement to the one-year anniversary of the effective date; (2) $350,000 from the one-year anniversary of the effective date of the agreement to the two-year anniversary if the effective date; and (3) $375,000 after the two-year anniversary. Under his agreement, Mr. Daches’ base salary will be reviewed annually by our Board to determine whether it should be increased. In 2017, Mr. Daches received a $50,000 cash bonus for our Company’s timely filing of its 2016 Annual Report on Form 10-K, in accordance with his employment agreement. Mr. Daches is also eligible to receive bonuses and awards of equity and non-equity compensation and to participate in the annual and long-term compensation plans of the Company, in each case as determined by our Board. The target annual bonus for Mr. Daches set forth in his agreement is 250,000 shares of restricted stock.

 

The initial term of Mr. Daches’ agreement ended on December 31, 2017, and the agreement began to renew automatically for additional one-year periods beginning on December 31, 2017. Either party may give notice of non-renewal at least 180 days before the end of the then-current term.

 

On December 15, 2016, Mr. Daches received a grant of 750,000 stock options under our 2016 Plan, with an exercise price of $2.98. 34% of the options vested on the grant date, 33% vested on December 15, 2017, and 33% will vest on the second anniversary of the grant date, subject to continued service. On May 5, 2017, Mr. Daches received a grant of 235,000 shares of restricted stock with a fair value of $4.26 per share at grant date. 100% of the restricted stock award vested on the grant date. On October 5, 2017, Mr. Daches received a grant of 400,000 shares of restricted stock with a fair value of $5.00 per share at grant date. 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

 

Under his employment agreement, upon a termination by us without cause or a termination by him for good reason, Mr. Daches 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 Mr. Daches for good reason within 12 months after 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. Daches will be entitled to a lump sum severance payment equal to six months of COBRA premiums. All severance payments under Mr. Daches’ employment agreement are subject to his execution of a release of claims against us. The severance payments are also subject to reduction in order to avoid any excise tax associated with Code Section 280G, but only if that reduction would result in Mr. Daches receiving a greater net after tax benefit as a result of the reduction.

 

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

 

Ms. Fuchs. On July 5, 2016, we entered into an employment agreement with Ms. Fuchs under which she served as our General Counsel. This agreement became effective June 24, 2016 upon the closing of our merger with Brushy. We amended this agreement on May 5, 2017 to eliminate Ms. Fuchs’ eligibility to receive certain “cash incentive bonuses” that had been tied to BOE and EBITDAX production thresholds, and we replaced those bonuses with an immediate bonus paid out in a mix of cash and stock.

 

The initial term of Ms. Fuchs’ agreement ended on December 31, 2017, and the agreement began to renew automatically for additional one-year periods beginning on December 31, 2017.

 

Ms. Fuchs’ initial base salary under her agreement was $250,000. Ms. Fuchs was entitled to, and received, a bonus under the agreement equal to $112,500, which was paid in cash on the first regular payroll date after June 24, 2016 (the closing date of the merger with Brushy). Ms. Fuchs was 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.

 

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 was 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. On December 15, 2016, Ms. Fuchs received an additional grant of 375,000 stock options under our 2016 Plan, with an exercise price of $2.98. This grant was 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.

 

On May 5, 2017, Ms. Fuchs received a grant of 150,000 shares of restricted stock with a fair value of $4.26 per share at grant date. 100% of the restricted stock award vested on the grant date. On October 5, 2017, Ms. Fuchs received a grant of 300,000 shares of restricted stock with a fair value of $5.00 per share at grant date. This grant was 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.

 

Under her employment agreement, Ms. Fuchs’ was 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 after a change in control, she was 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 was entitled to a lump sum severance payment equal to six months of COBRA premiums. All severance payments under Ms. Fuchs’ employment agreement were subject to her execution of a release of claims against us. The severance payments are also subject to reduction in order to avoid any excise tax associated with Code Section 280G, 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 are 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.

 

On February 16, 2018, Ariella Fuchs ceased serving as the Executive Vice President, General Counsel, and Secretary of the Company. Upon Ms. Fuchs’ separation, all unvested equity awards held by Ms. Fuchs vested on an accelerated basis.

 

Mr. Short. In connection with his appointment as our Chief Operating Officer, we entered into an employment agreement with Mr. Short dated January 27, 2017. The agreement provides, among other things, that Mr. Short will receive a base salary of $300,000 per year, to be reviewed annually by our Board to determine whether the salary should be increased. The agreement also provides for additional bonuses based on our achievement of certain performance measures. Mr. Short is also eligible to receive bonuses and awards of equity and non-equity compensation and to participate in annual and long-term compensation plans of the Company, in each case as determined by our Board.

 

The initial term of Mr. Short’s agreement ended on December 31, 2017, and the agreement began to renew automatically for additional one-year periods beginning on December 31, 2017. Either party may give notice of non-renewal at least 180 days before the end of the then-current term.

 

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On January 27, 2017, Mr. Short received a grant of 250,000 stock options under our 2016 Plan, with an exercise price of $4.35. This grant was scheduled to vest over two years, with 34% of the options vesting on the grant date, 33% vesting on January 27, 2018, and 33% to vest on the second anniversary of the grant date, subject to his continued service. Also on January 27, 2017, Mr. Short received a grant of 75,000 shares of restricted stock under our 2016 Plan. This grant was scheduled to vest over two years, with 34% of the shares vesting on the grant date, 33% vesting on January 27, 2018, and 33% to vest on the second anniversary of the grant date, subject to continued service. On May 2, 2017, Mr. Short received a grant of 500,000 stock options under our 2016 Plan, with an exercise price of $4.48; 250,000 of these options vested upon the grant date, and the remaining 250,000 options vest based on the achievement of specified performance goals (generally, 50,000 options will vest per completion of one well under our Company’s authorization for expenditures budget), 50,000 of which have vested as of March 2018. On October 5, 2017, Mr. Short received a grant of 400,000 shares of restricted stock under our 2016 Plan, with an exercise price of $5.00. This grant was scheduled to vest over two years, with 34% of the options 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.

 

Under his employment agreement, upon a termination by us without cause or a termination by him for good reason, Mr. Short 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 Mr. Short for good reason within 12 months after 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. Short will be entitled to a lump sum severance payment equal to six months of COBRA premiums. All severance payments under Mr. Short’s employment agreement are subject to his execution of a release of claims against us. The severance payments are also subject to reduction in order to avoid any excise tax associated with Code Section 280G, but only if that reduction would result in Mr. Short receiving a greater net after tax benefit as a result of the reduction.

 

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

 

On March 6, 2018, Mr. Short ceased serving as our Chief Operating Officer and, as a result of such cessation, all of Mr. Short’s unvested equity awards were relinquished.

 

Mr. Ormand. On July 5, 2016, we entered into an employment agreement with Mr. Ormand, under which he serves as our Executive Chairman. The initial term of the agreement ended on December 31, 2017, and the agreement began to renew automatically for additional one-year periods beginning on December 31, 2017. Either party may give notice of non-renewal at least 180 days before the end of the then-current term.

 

Mr. Ormand’s base salary under his agreement (which will be reviewed by our Board for adjustments) was $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.

 

On July 7, 2016, Mr. Ormand received a grant of restricted stock under our 2016 Plan covering 1.25 million shares of our 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. On December 15, 2016, Mr. Ormand received an additional grant of 250,000 stock options under our 2016 Plan, with an exercise price of $2.98. 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.

 

On October 5, 2017, Mr. Ormand received a grant of 500,000 shares of restricted stock with a fair value of $5.00 per share at grant date. This grant is scheduled to vest over 2 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.

 

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 after 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 of a release of claims against us. The severance payments are also subject to reduction in order to avoid any excise tax associated with Code Section 280G, 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.

 

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Mr. Mirman. On July 5, 2016, we entered into a new employment agreement with Mr. Mirman, under which he served as our CEO. This agreement became effective June 24, 2016 upon the closing of our merger with Brushy. The initial term of Mr. Mirman’s agreement was scheduled to end on December 31, 2017. We amended this agreement on May 5, 2017 to eliminate Mr. Mirman’s eligibility to receive certain “cash incentive bonuses” that had been tied to BOE and EBITDAX production thresholds, and we replaced those bonuses with an immediate bonus paid out in a mix of cash and stock.

 

Mr. Mirman’s base salary under his agreement was $350,000 for the first year of the agreement, $375,000 for the second year, and $425,000 for the third year. Mr. Mirman was entitled to a bonus under the agreement equal to $175,000, payable in cash on the first regular payroll date after June 24, 2016 (the closing date of the merger with Brushy). Mr. Mirman was 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.

 

Mr. Mirman was granted stock options covering 1,250,000 shares on June 24, 2016 and 500,000 shares on December 15, 2016. To satisfy the requirements of Code Section 162(m), our 2016 Plan included an annual limit on grants of stock options and SARs to any individual participant of 10,000,000 shares, which was automatically adjusted to 1,000,000 shares as a result of our 1-for-10 reverse stock split effective June 23, 2016. The 2016 option grants to Mr. Mirman inadvertently exceeded this award limit. As a result, our compensation committee approved a rescission in June 2017 of 250,000 of the options granted in June 2016 and the entire December 2016 option grant. Our compensation committee believed these awards otherwise represented appropriate compensation opportunities for Mr. Mirman and in June 2017, our compensation committee approved options and restricted stock awards to replace the value of the rescinded option awards. On May 5, 2017, Mr. Mirman received a grant of 280,000 shares of restricted stock with a fair value of $4.26 per share at grant date. 100% of the restricted stock award vested on the grant date.

 

Under his employment agreement, Mr. Mirman was 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 after a change in control, he was 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 was entitled to a lump sum severance payment equal to six months of COBRA premiums. All severance payments under Mr. Mirman’s employment agreement were subject to his execution of a release of claims against us. The severance payments were also subject to reduction in order to avoid any excise tax associated with Code Section 280G, 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 were subject to clawback in the event required by applicable law. Further, Mr. Mirman was subject to non-competition, non-solicitation, anti-raiding, and confidentiality provisions under his employment agreement.

 

On August 1, 2017, the SEC filed a civil complaint against multiple parties, including our then CEO, Mr. Mirman. The allegations in the complaint are unrelated to the business of the Company, and predate Mr. Mirman’s tenure with the Company. On August 3, 2017, Abraham Mirman notified us of his resignation as our CEO, and as a member of our Board, effective as of August 4, 2017. Mr. Mirman also resigned from all positions held with our subsidiaries. Mr. Mirman’s decision to resign was not the result of any disagreement with us, our Board, or management, or any matter relating to our operations, policies, or practices.

 

In connection with Mr. Mirman’s resignation, we entered into a Separation and Consulting Agreement with him on August 3, 2017—the Mirman Agreement—setting forth the terms of Mr. Mirman’s separation from the Company and his prospective consulting services.

 

Under the Mirman Agreement, in satisfaction of all of our obligations under his employment agreement, Mr. Mirman received the following severance payments: (1) a lump-sum cash payment of $1,000,000; (2) premium payments for continuing COBRA coverage for 18 months; and (3) reimbursement of reasonable attorneys’ fees incurred in connection with his separation. Further, all unvested equity awards held by Mr. Mirman vested on August 12, 2017 as a result of his separation.

 

In addition, we engaged Mr. Mirman as an independent consultant to provide services of a consulting or advisory nature as we may reasonably request with respect to our business. Mr. Mirman’s consultancy commenced August 5, 2017 and is scheduled to terminate on August 5, 2018, unless terminated earlier or extended by mutual agreement in accordance with the terms of the Mirman Agreement. In consideration for his consulting services, we will pay Mr. Mirman a monthly consulting fee of $41,660.67.

 

The Mirman Agreement also contains restrictive covenants covering confidentiality, non-competition, non-solicitation, and non-disparagement, and a release of claims against us.

 

Mr. Nanke. Effective as of July 5, 2016, we entered into an employment agreement with Mr. Nanke, under which he served as our Executive Vice President and Chief Financial Officer. The initial term of Mr. Nanke’s agreement was scheduled to end on December 31, 2017. The agreement provided for a $125,000 cash bonus due upon signing and a $275,000 salary per year, to be reviewed annually by our Board. The agreement also provided for additional bonuses due based on our achievement of certain performance measures.

 

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On June 24, 2016, Mr. Nanke received a grant of 625,000 stock options at an exercise price of $1.34. This grant was scheduled to vest over two years, with 34% vesting on the grant date, 33% vesting on June 24, 2017, and 33% to vest on June 24, 2018.

 

Under his employment agreement, Mr. Nanke was 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. Nanke for good reason within 12 months after a change in control, he was 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. Nanke was entitled to a lump sum severance payment equal to six months of COBRA premiums. All severance payments under Mr. Nanke’s employment agreement were subject to his execution of a release of claims against us. The severance payments were also subject to reduction in order to avoid any excise tax associated with Code Section 280G, but only if that reduction would result in Mr. Nanke receiving a greater net after tax benefit as a result of the reduction.

 

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

 

On February 13, 2017, we entered into a separation agreement with Mr. Nanke—or the Nanke Agreement—covering his termination from our Company. Mr. Nanke acknowledged that his termination was not for “good reason” (as defined in his employment agreement), but that the termination did constitute an “involuntary termination” (as defined in the employment agreement). Under the Nanke Agreement, Mr. Nanke released all claims against us related to his employment. We agreed to provide Mr. Nanke with (1) a lump sum severance payment equal to 24 months of his base salary as in effect immediately prior to his termination; (2) a lump sum payment equal to 24 months of COBRA premiums; and (3) a lump sum bonus payment of $175,000. All severance payments were subject to Mr. Nanke’s execution of release of claims against us. The Nanke Agreement also contains restrictive covenants covering confidentiality, non-competition, non-solicitation, and non-disparagement.

 

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

 

Our Board and stockholders approved our 2012 EIP in August 2012. Our 2012 EIP provided for grants of equity incentives, including stock options, stock appreciation rights—or SARs—restricted shares, 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 our 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 our 2012 EIP, as discussed below.

 

2016 Omnibus Incentive Plan

 

Background. Our 2016 Plan was approved by our Board effective April 20, 2016 and approved by our stockholders at the 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 our officers, employees, directors, consultants, and advisors and the officers, employees, directors, consultants, and advisors of our affiliates. Tax-qualified incentive stock options may be granted only to our employees.

 

Administration. Our 2016 Plan may be administered by our Board or our compensation committee. Our compensation committee 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. A maximum of 13,000,000 shares of our common stock are available for grant under our 2016 Plan. 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. 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.

 

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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 us, 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 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; SARs; restricted shares; RSUs; other types of equity or equity-based awards; and performance awards.

 

No Repricing. Without stockholder approval, our compensation committee is not authorized under our 2016 Plan 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, RSU, 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 we may adopt from time to time.

 

Transferability. Awards granted under our 2016 Plan 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.

 

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 fully 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 fully if the award recipient has a separation from service within two years after the 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.

 

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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 was initially approved by our 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 2017

 

During our fiscal year ended December 31, 2017, we granted 4,266,345 shares of restricted common stock and 3,260,000 options to purchase shares of common stock to our employees and directors. Also, during 2017, 1,606,937 stock options and 696,469 shares of restricted stock previously issued and unvested were forfeited or cancelled in connection with the termination of certain employees, the departure of certain directors and/or shares cancelled to cover tax withholding on vested restricted shares. 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.

 

Stockholder Feedback and Consideration of 2017 Say-on-Pay Vote

 

Our compensation committee and Board considered the results of the “say-on-pay” vote at our annual meeting of stockholders held on July 13, 2017, where the compensation of our NEOs was approved by over 99% of the stockholders that voted on the matter (not including broker non-votes). Our compensation committee believes that this stockholder vote indicates strong support for our executive compensation program and considered the strong stockholder support in determining our 2017 compensation practices. Our Board encourages stockholders to contact the Board and share any concerns about our executive compensation program, but given the strong level of stockholder support for our executive compensation program in 2017, the compensation committee did not engage in any formal outreach program to stockholders on executive compensation matters in 2017. We will hold an advisory vote on executive compensation every year until the next required advisory vote with respect to the frequency of advisory votes on executive compensation, which will occur at our annual meeting of stockholders in 2018. We are and will remain committed to being responsive to stockholder feedback, and the results of our annual “say on pay” votes inform the compensation committee’s discussions about the executive pay program.

 

Deductibility

 

Code Section 162(m) limits the deductibility of compensation in excess of $1,000,000 paid to any one NEO in any calendar year. Under the tax rules in effect before 2018, compensation that qualified as “performance-based” under Section 162(m) was deductible without regard to this $1 million limit. However, the Tax Cuts and Jobs Act, which was signed into law December 22, 2017, eliminated this performance-based compensation exception effective January 1, 2018, subject to a special rule that “grandfathers” certain awards and arrangements that were in effect on or before November 2, 2017. As a result, compensation that our compensation committee structured in 2017 and prior years with the intent of qualifying as performance-based compensation under Section 162(m) that is paid on or after January 1, 2018 may not be fully deductible, depending on the application of the special grandfather rules. Moreover, from and after January 1, 2018, compensation awarded in excess of $1,000,000 to our NEOs generally will not be deductible. While the Tax Cuts and Jobs Act will limit the deductibility of compensation paid to our NEOs, our compensation committee will—consistent with its past practice—continue to retain flexibility to design compensation programs that are in the best long-term interests of the Company and our stockholders, with deductibility of compensation being one of a variety of considerations taken into account.

 

Risks Relating to our Compensation Policies and Practices

 

We have undertaken an analysis of our compensation policies and practices to assess whether risks arising from such policies and practices are reasonably likely to have a material adverse effect on our Company. The analysis was performed by our management with oversight by our compensation committee. We analyzed risks relating to the different components of our compensation structure, to the time horizons of our compensation components, to the goals and objectives used to determine performance-based compensation, and to any contractual obligations by us to accelerate the payment of compensation. Based on that analysis, we have concluded that the risks arising from our compensation policies and practices are not reasonably likely to have a material adverse effect on the Company.

 

 66 

 

 

Compensation Committee Interlocks and Insider Participation

 

During 2017, none of the members of our compensation committee was an officer or employee of the Company or any of our subsidiaries. In addition, during the last fiscal year, none of our executive officers served as a member of the board of directors or compensation committee of any entity in which a member of our Board or compensation committee is an executive.

 

 67 

 

 

Compensation Committee Report

 

Our compensation committee has reviewed and discussed the Compensation Discussion and Analysis above with management. Based on their review and discussions with management, the members of our compensation committee recommended to our Board that the Compensation Discussion and Analysis be included in this Annual Report.

 

Compensation Committee:

Nuno Brandolini

R. Glenn Dawson

 

 68 

 

 

Summary Compensation Table

 

The following table provides information regarding compensation paid to our NEOs for the years ended December 31, 2017, 2016, and 2015 (in each case only for years in which the individual was one of our NEOs).

 

Name and Principal
Position
  Year    

Salary

($)(1)

   

Bonus

($)(2)

   

Stock
Awards

($)(3)

   

Option
Awards

($)(4)

   

All Other
Compensation

($)(5)

   

Total

($)

 
James Linville
(Chief Executive Officer)
    2017       207,576       100,000       847,000       861,250       12,438       2,028,340  
Abraham “Avi” Mirman
(Former CEO)(6)
    2017       323,782       1,932,200       2,804,313             1,269,608       6,329,903  
      2016       350,000       175,000             4,295,894       22,484       4,843,378  
      2015       325,466       100,000       90,000       1,397,721       31,504       1,944,691  
Joseph C. Daches
(Chief Financial Officer)
    2017       383,333       1,248,900       3,001,100             25,788       4,659,121  
Kevin Nanke
(Former CFO)(7)
    2017       17,804                         776,179       793,983  
      2016       257,500       225,000             815,216       32,373       1,330,089  
      2015       200,000       200,000       99,000       608,291       24,634       1,131,925  
Brennan Short
(Former COO) (8)
    2017       345,128       637,500       2,326,250       1,880,000       23,638       5,212,516  
Ronald D. Ormand
(Executive Chairman) (9)
    2017       379,167       625,000       2,500,000             25,788       3,529,955  
      2016       150,000             1,875,000       533,092       69,502       2,627,594  
Ariella Fuchs
(Former EVP, General Counsel, & Secretary) (10)
    2017       300,000       1,148,500       1,500,000             17,687       2,966,187  
      2016       240,000       112,500             1,288,768       8,417       1,649,685  
      2015       182,083             48,000       234,887       10,538       475,508  

  

(1)The base salary amounts in this column represent actual base compensation paid or earned through the end of the applicable year.
(2)The amounts in this column include annual bonuses paid for the applicable year. See Employment Agreements in the Compensation Discussion and Analysis above for more information on individual bonuses paid for 2017.
(3)The amounts in this column represent the aggregate grant date fair value of stock awards granted during the applicable year. 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. The amounts in this column for 2017 are detailed below under Grants of Plan-Based Awards.
(4)

The amounts in this column represent the grant date fair value of stock options granted in the applicable year computed in accordance with FASB ASC Topic 718. 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 elsewhere in this Annual Report. The amounts in this column for 2017 are detailed below under Grants of Plan-Based Awards.

(5)The amounts in this column for 2017 consist of the following:

 

Name  Reimbursement of
Health Insurance
Premiums
($)
   Company
Contribution to
401(k) Plan
($)
   Severance Benefits
($)
   Total
($)
 
James Linville   12,438    -    -    12,438 
Avi Mirman   25,788    -    1,243,820    1,269,608 
Joseph Daches   25,788    -    -    25,788 
Kevin Nanke   -    -    

776,179

    

776,179

 
Brennan Short   23,638    -    -    23,638 
Ronald Ormand   25,788    -    -    25,788 
Ariella Fuchs   17,687    -    -    17,687 

 

(6)Effective August 4, 2017, Mr. Mirman resigned as our CEO, and as a member of our Board. See Employment Agreements in the Compensation Discussion and Analysis above for more information regarding Mr. Mirman’s resignation.
(7)

Effective February 13, 2017, we entered into a separation agreement with Mr. Nanke in connection with his termination from our Company. See Employment Agreements in the Compensation Discussion and Analysis above for more information regarding Mr. Nanke’s separation.

(8)On March 6, 2018, Brennan Short ceased serving as the Chief Operating Officer of the Company.

(9)Effective July 11, 2016, Mr. Ormand began to serve as Executive Chairman of our Board, which is an officer position. Prior to July 11, 2016, Mr. Ormand was a nonemployee director of our Board and his compensation from January 1 to July 10, 2016 is reflected under All Other Compensation for 2016.

(10)On February 16, 2018, Ariella Fuchs ceased serving as the Executive Vice President, General Counsel, and Secretary of the Company.

 

 69 

 

 

Grants of Plan-Based Awards

 

The following table provides information regarding awards granted to our NEOs under our 2016 Plan during 2017.

 

       Estimated Future Payouts Under
Equity Incentive Plan Awards
(1)
                     
Name  Grant Date   Threshold
(#)
    Target
(#)
    Maximum
(#)
    All Other 
Stock 
Awards:

Number of
Shares of
Stock or
Units
(#)(2)
    All Other
Option
Awards:
Number of
Securities
Underlying
Options
(#)(3)
    Exercise 
or Base

Price of
Option
Awards
($/Sh)
    Grant Date 
Fair Value
of Stock 
and Option 
Awards

($)
 
James Linville  6/26/2017                   325,000    4.84    861,250 
   6/26/2017               175,000            847,000 
Avi Mirman  5/5/2017               280,000            1,192,800 
   6/16/2017               389,657    750,000    5.31    6,051,579 
Joseph Daches  5/5/2017               235,000            1,001,100 
   10/5/2017               400,000            2,000,000 
Kevin Nanke                              
Brennan Short  1/27/2017                   250,000    4.35    1,087,500 
   1/27/2017               75,000        4.35    326,250 
   5/2/2017                   250,000    4.48    1,120,000 
   5/2/2017           250,000            4.48    1,120,000 
   10/5/2017               400,000        5.00    2,000,000 
Ronald Ormand  10/5/2017               500,000        5.00    2,500,000 
Ariella Fuchs  5/5/2017               150,000        4.26    639,000 
   10/5/2017               300,000            1,500,000 

 

(1)

For the stock options granted to Mr. Short on May 2, 2017, 250,000 vested immediately and the remainder were scheduled to vest upon the achievement of specified performance goals (50,000 options were scheduled to vest per completion of each well under our Company’s authorization for expenditures budget, until all of the options are vested or forfeited). All such unvested options have been relinquished in connection with Mr. Short’s separation of employment with the Company in March 2018.

(2)This column shows the number of RSAs granted in 2017 to our NEOs under our 2016 Plan.

-For the RSAs granted to Mr. Linville on June 26, 2017, 34% vested and settled immediately and the remainder will vest and settle in two equal installments, subject to continued services, on the first two anniversaries of the grant date.

-For the RSAs granted to Mr. Mirman, Mr. Daches, and Ms. Fuchs on May 5, 2017, 100% vested and settled immediately.

-For the RSAs granted to Mr. Mirman on June 16, 2017, 66% vested and settled immediately and the remainder vested and settled on August 12, 2017 on an accelerated basis under the terms of the Mirman Agreement.

-For the RSAs granted to Mr. Daches, Mr. Short, Mr. Ormand, and Ms. Fuchs on October 5, 2017, 34% vested and settled immediately and the remainder will vest and settle in two equal installments, subject to acceleration provisions and continued services, on the first two anniversaries of the grant date. The unvested RSAs granted to Ms. Fuchs vested and settled in connection with her separation of employment with the Company in February 2018. 

-For the RSAs granted to Mr. Short on January 27, 2017, 34% vested and settled immediately and the remainder were scheduled to vest and settle in two equal installments, subject to acceleration provisions and continued services, on the first two anniversaries of the grant date. The unvested RSAs granted to Mr. Short were relinquished in connection with the separation of his employment with the Company in March 2018.

(3)This column shows the number of stock options granted in 2017 to our NEOs under our 2016 Plan.

-For the stock options granted to Mr. Linville on June 26, 2017, 34% vested immediately and the remainder will vest in two equal installments, subject to continued services, on the first two anniversaries of the grant date.

-All of Mr. Mirman’s stock options vested August 12, 2017 upon his separation under the terms of the Mirman Agreement.

-For the stock options granted to Mr. Short on January 27, 2017, 34% vested immediately and the remainder were scheduled to vest in two equal installments, subject to acceleration provisions and continued services, on the first two anniversaries of the grant date. The unvested stock options granted to Mr. Short were relinquished in connection with the separation of his employment with the Company in March 2018.

 

 70 

 

 

Outstanding Equity Awards at Fiscal Year-End

 

The following table provides information regarding all outstanding equity awards held by our NEOs as of December 31, 2017.

 

    Option Awards   Stock Awards  
Name   Number of
Securities
Underlying
Unexercised
Options
(#)
Exercisable
    Number of
Securities
Underlying
Unexercised
Options
(#)
Unexercisable
    Equity
Incentive
Plan
Awards:
Number of
Securities
Underlying
Unexercised
Unearned
Options
(#)
    Option
Exercise
Price
($)
    Option
Expiration
Date
  Number of
Shares of
Stock That
Have Not
Vested
(#)
    Market Value
of Shares of
Stock That
Have Not
Vested
($)(1)
 
James Linville     110,500       214,500 (2)           4.84     6/26/2027     115,500 (3)      590,205  
Avi Mirman(4)     1,000,000                   1.34     6/24/2026            
      750,000                   5.31     6/16/2027            
Joseph Daches     502,500       247,500 (5)           2.98     12/15/2026     264,000 (6)     1,349,040  
Kevin Nanke(7)     625,000                   1.34     6/24/2026            
Brennan Short     85,000       165,000 (8)           4.35     1/27/2027     313,500 (10)      1,601,985  
      250,000             250,000 (9)     4.48     5/2/2027            
Ronald Ormand     31,667                   16.50     4/20/2025     742,500 (11)      3,794,175  
      167,500       82,500 (5)           2.98     12/15/2026            
Ariella Fuchs     251,250       123,750 (12)           1.34     6/24/2026     198,000 (6)      1,011,780  
      251,250       123,750 (5)           2.98     12/15/2026          

 

Vesting of options and stock awards reflected in this table is subject to continuous service with our Company, except that unvested awards may vest upon termination by us without cause, termination by the officer for good reason, or termination due to the officer’s disability or death (in each case as set forth in the applicable award agreement or employment agreement).

 

(1)

The market value of the stock awards is based on the closing price per share of our common stock on the NYSE on December 31, 2017, which was $5.11.

(2)

Options vest in equal installments on each of June 26, 2018 and 2019, subject to continued service.

(3)Restricted stock vests on June 26, 2018 and 2019 in equal installments, subject to continued service.
(4)For Mr. Mirman, effective August 12, 2017, all unvested options and restricted stock accelerated under the Mirman Agreement.
(5)

Options vest on December 15, 2018, subject to acceleration provisions and continued service. The unvested options granted to Ms. Fuchs were subject to accelerated vesting in connection with her separation from the Company in February 2018. 

(6)

Restricted stock vests on October 5, 2018 and 2019 in equal installments, subject to acceleration provisions and continued service. The unvested restricted stock granted to Ms. Fuchs was subject to accelerated vesting in connection with her separation from the Company in February 2018. 

(7)For Mr. Nanke, effective February 13, 2017, all unvested options and restricted stock accelerated under the Nanke Agreement.
(8)

Options vest in equal installments on January 27, 2018 and 2019, subject to acceleration provisions and continued service. The unvested options granted to Mr. Short were relinquished in connection with his separation of employment with the Company in March 2018. 

(9)Options vest upon the achievement of specified performance goals (50,000 options will vest per completion of each well under our Company’s authorization for expenditures budget, until all options are vested or forfeited). The unvested options granted to Mr. Short were relinquished in connection with his separation of employment with the Company in March 2018.
(10)

49,500 shares of restricted stock vest in equal installments on January 27, 2018 and 2019, subject to acceleration provisions and continued service. 264,000 shares of restricted stock vest on October 5, 2018 and 2019 in equal installments, subject to acceleration provisions and continued service. The unvested shares of restricted stock granted to Mr. Short were relinquished in connection with his separation of employment with the Company in March 2018. 

(11)412,500 shares of restricted stock vest in equal installments on June 24, 2018, subject to acceleration provisions and continued service. 330,000 shares of restricted stock vest on October 5, 2018 and 2019 in equal installments, subject to acceleration provisions and continued service.

(12)

Options vest on June 24, 2018, subject to acceleration provisions and continued service. The unvested options granted to Ms. Fuchs were subject to accelerated vesting in connection with her separation from the Company in February 2018. 

 

 71 

 

 

Option Exercises and Stock Vested

 

The following table provides information regarding the exercise of stock options by our NEOs and the vesting of restricted stock during 2017.

 

    Option Awards     Stock Awards  
Name   Number of Shares
Acquired on Exercise
(#)
    Value Realized on
Exercise
($)
    Number of Shares
Acquired on Vesting
(#)
    Value Realized on
Vesting
($)
 
James Linville     -       -       59,500       287,980  
Avi Mirman     -       -       669,657       3,261,879  
Joseph Daches     -       -       371,000       1,681,100  
Kevin Nanke     -       -       -       -  
Brennan Short     -       -       161,500       764,150  
Ronald Ormand     -       -       170,000       850,000  
Ariella Fuchs     -       -       252,000       1,149,000  

 

 72 

 

 

Pension Benefits

 

We do not maintain any plans that provide for payments or other benefits at, following, or in connection with retirement, of the sort that would otherwise require us to include a Pension Benefits table as contemplated by SEC rules.

 

Nonqualified Deferred Compensation

 

We do not maintain any defined contribution or other plans that provide for the deferral of compensation on a basis that is not tax-qualified, of the sort that would otherwise require us to include a Nonqualified Deferred Compensation table as contemplated by SEC rules.

 

 73 

 

 

Potential Payments Upon Termination or Change-In-Control

 

The following table provides information regarding the payments and benefits to which each of our NEOs would be entitled to in the event of termination of such executive’s employment with our Company and in the event of a change in control of our Company. Except as otherwise noted, the amounts shown (1) are estimates only and (2) assume that the applicable termination of employment was effective, or that the change in control occurred, as of December 31, 2017.

 

For further information regarding the agreements that provide for payment(s) to our NEOs at, following, or in connection with any service termination, or a change in control of the Company, see Employment Agreements in the Compensation Discussion and Analysis section above.

 

Name   Cash
($)
    Equity
($)(1)
    Perquisites/Benefits
($)
    Total
($)
 
James Linville                                
Death     400,000       677,955             1,077,955  
Disability           677,955       11,400 (2)     689,355  
By Lilis without Cause or by NEO for Good Reason (No CIC)     600,000 (3)     677,955       22,800 (4)     1,300,755  
CIC with Involuntary Termination     1,000,000 (5)     677,955       45,600 (6)     1,723,555  
Avi Mirman(7)                                
Joseph Daches                                
Death     400,000       2,946,540             3,346,540  
Disability           2,946,540       11,400 (2)     2,957,940  
By Lilis without Cause or by NEO for Good Reason     400,000 (8)     2,946,540       22,800 (4)     3,369,340  
CIC with Involuntary Termination     800,000 (9)     2,946,540       45,600 (6)     3,792,140  
Kevin Nanke(10)                                
Ariella Fuchs (11)                                
Brennan Short (12)                                
Ronald Ormand                                
Death     500,000       3,675,082             4,465,988  
Disability           3,675,082       11,400 (2)     3,977,388  
By Lilis without Cause or by NEO for Good Reason     500,000 (8)     3,675,082       22,800 (4)     4.488,788  
CIC with Involuntary Termination     1,000,000 (9)     3,670,082       45,600 (6)     5,011,588  

  

(1)Represents the value of accelerated vesting of option awards and stock awards. Amounts reflected assume that all applicable performance targets for any performance-vesting awards are achieved.
(2)Reflects an amount equal to 6 months of COBRA premiums.
(3)Represents a lump sum severance payment equal to 12 months of base salary plus acceleration of a $200,000 sign-on retention bonus.
(4)Reflects an amount equal to 12 months of COBRA premiums.
(5)Represents a lump sum severance payment equal to 24 months of base salary plus acceleration of a $200,000 sign-on retention bonus.
(6)Reflects an amount equal to 24 months of COBRA premiums.
(7)Pursuant to his resignation on August 3, 2017, we entered into a separation and consulting agreement with Mr. Mirman. Under the terms of the agreement, Mr. Mirman was provided with (1) a lump sum cash payment of $1,000,000; (2) premium payments for continuing COBRA coverage for 18 months with a value of approximately $34,000; and (3) reimbursement of reasonable attorneys’ fees incurred in connection with his separation with a value of approximately $156,000. In addition, all of Mr. Mirman’s unvested options and restricted stock accelerated pursuant to the terms of his separation and consulting agreement, valued at approximately $4.4 million. 
(8)Represents a lump sum severance payment equal to 12 months of base salary.
(9)Represents a lump sum severance payment equal to 24 months of base salary.
(10)Pursuant to his termination on February 13, 2017, we entered into a separation agreement with Mr. Nanke. Under the terms of the agreement, he was provided with (1) a lump sum severance payment equal to 24 months of his base salary ($275,000); (2) a lump sum payment equal to 24 months of COBRA payments ($51,000); and (3) a lump sum payment bonus payment of $175,000. Mr. Nanke also held 418,750 unexercised stock option grants with an exercise price of $1.34, which vested at the time of his separation.

(11)In connection with her separation from the Company in February 2018, we entered into an agreement with Ms. Fuchs pursuant to which she will receive severance and other consideration pursuant to the terms of her employment agreement and stock award agreements plus additional nominal consideration.

(12)

In connection with his separation of employment with the Company in March 2018, in accordance with the terms of his employment agreement and stock award agreements, Mr. Short did not receive severance or other consideration.

 

 74 

 

 

DIRECTOR COMPENSATION

 

The following table shows the total compensation for our nonemployee directors for their service to our Board during 2017. All references to “directors” in this Director Compensation section are to nonemployee members of our Board.

 

Name  Fees Earned
or Paid in
Cash
($)
   Stock Awards
($)(1)
   Option Awards
($)
   All Other
Compensation
($)
   Total
($)
 
G. Tyler Runnels(2)   19,076                19,076 
Nuno Brandolini(3)   60,000    171,825            231,825 
General Merrill McPeak(4)   85,000    171,825            256,825 
R. Glenn Dawson(5)   85,000    415,000             500,000 
Peter Benz(6)   85,000    171,825             256,825 
Mark Christensen(7)   19,076                19,076 

 

(1)

Represents restricted stock awards. 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 awards and do not correspond to the actual economic value that may be received for the awards. On January 31, 2017, Mr. Brandolini, General McPeak, and Mr. Benz were each granted 15,000 shares of restricted stock and Mr. Dawson was granted 103,750 shares of restricted stock. These awards all vested in full immediately. On October 17, 2017, Mr. Brandolini, General McPeak, and Mr. Benz were each granted 22,500 shares of restricted stock, which all vested in full immediately.

(2)Mr. Runnels was appointed to our Board on September 6, 2017.
(3)Mr. Brandolini was appointed to our Board on February 13, 2014.
(4)General McPeak was appointed to our Board on January 29, 2015.
(5)Mr. Dawson was appointed to our Board on January 13, 2016.
(6)Mr. Benz was appointed to our Board on June 23, 2016.
(7)Mr. Christensen was appointed to our Board on September 6, 2017.

 

Nonemployee Director Compensation Program. Our nonemployee Board members are paid a base annual cash retainer that is intended to compensate the directors for (1) attendance at all meetings to which the director has been assigned; (2) voluntary attendance at meetings to which the director has not been assigned; (3) time spent by the director to continue to improve industry knowledge and Board skills; and (4) ad hoc discussions and telephone calls by the director—these include discussions and calls that do not have a formal agenda noticed in accordance with the Company’s Bylaws and for which minutes are not kept.

 

Our compensation committee administers our director compensation program. In addition to the services Longnecker provided to the compensation committee on executive compensation, Longnecker reviewed market data from the Company’s compensation peer group for director compensation, including annual cash retainers, meeting fees and/or equity retainers. The peer group consisted of the same companies utilized to evaluate executive compensation. Longnecker developed recommendations for the compensation committee to consider that were designed to align the Company near the 50th percentile of the peer group.

 

Annual Cash Retainers. Directors will be paid an additional annual retainer for holding the position of Board Chairperson (in the case of a non-executive chairperson), Board Committee Chairperson, or Board Committee Member. The base annual cash retainer and committee member annual cash retainers are as follows:

 

Retainer Type   Annual Retainer Amount  
Director   $ 60,000  
Board Chair (non-executive)   $ 50,000  
Audit Committee Chair   $ 25,000  
Audit Committee Member   $ 12,500  
Reserves Committee Chair   $ 240,000 (1) 
Compensation Committee Chair   $ 25,000  
Compensation Committee Member   $ 10,000  
Nominating and Corporate Governance Chair   $ 10,000  
Nominating and Corporate Governance Committee Member   $ 7,500  

 

(1)The current annual retainer amount paid to the Reserves Committee Chair is in consideration for additional technical responsibilities currently being performed by such Chair at the request of the Board and is subject to monthly review and termination or reduction by the Board in the event that it determines that the performance by such Chair of such responsibilities is no longer advisable and in the best interests of the Company.

 

All cash retainers will be paid in quarterly installments, in the first week of each calendar quarter. All annual cash retainers may be prorated based on active status of the director.

 

Initial Restricted Stock Grant. Each new director will receive an initial grant of 10,000 restricted shares of common stock, which will be granted on the first Annual Equity Date (as defined below) for which the director serves on our Board and will vest in the following increments on the specified dates, so long as the director remains a member of our Board through the vesting date:

 

3,334 shares on the first anniversary of the director’s first Annual Equity Date;

 

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3,333 shares on the second anniversary of the director’s first Annual Equity Date; and
3,333 shares on the third anniversary of the director’s first Annual Equity Date.

 

Initial Option Award Grant. Each new director will receive an initial grant of 45,000 options to purchase shares of common stock, which will be granted on the first Annual Equity Date for which the director serves on our Board and will vest in the following increments on the specified dates, so long as the director remains a member of our Board through the vesting date:

 

25,000 options on the date of the grant;
6,667 options on the first anniversary of the director’s first Annual Equity Date;
6,667 options on the second anniversary of the director’s first Annual Equity Date; and
6,666 options on the third anniversary of the director’s first Annual Equity Date.

 

Annual Equity Grants. The “Annual Equity Date” will be the first business day on or after January 31 of each year. On each Annual Equity Date, so long as the director remains a member of our Board on such date, the Company will issue to the director a number of fully vested shares of common stock equal to $150,000 (or, in the event the director has not served a full calendar year by that date, a prorated amount) divided by the most recent per share closing price of the common stock.

 

Company Equity Compensation Plans. All director equity awards will be granted under, and subject to the terms and conditions of, the Company’s equity compensation plan in effect at the time the award is granted.

 

Change in Control. In the event of a change in control (as defined in the Company’s equity compensation plan then in effect), the Board will consider awards to directors for their service from the most recent Annual Equity Date through the change in control, in order to compensate the directors for the missed opportunity to receive an award on the next scheduled Annual Equity Date.

 

Additional Payments. Any additional cash or equity retainer may be granted by our Board based on active status of assignments of the director.

 

Annual Limits on Awards to Nonemployee Directors. The maximum number of shares subject to Company equity compensation plan awards granted during any calendar year to any director, taken together with any cash fees paid to the director during the year, may not exceed $500,000 in total value (calculating the value of any Company equity compensation plan awards based on the grant date fair value of such awards for financial reporting purposes).

 

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CEO PAY RATIO

 

As required by applicable SEC rules, we are providing the following information about the relationship of the annual total compensation of our employees and the annual total compensation of James Linville, our CEO on December 31, 2017. The pay ratio included in this information is a reasonable estimate calculated in a manner consistent with Item 402(u) of Regulation S-K.

 

For 2017, the median of the annual total compensation of all our employees (other than our CEO) was $0.5 million (inclusive of stock based compensation); and the annual total compensation of our CEO, as reported in the Summary Compensation Table included above (adjusted as noted below), and then annualized for purposes of this pay ratio disclosure, was $2.2 million. Based on this information, for 2017 the ratio of the annual total compensation of our CEO to the median of the annual total compensation of all our employees was 4 to 1.

 

We took the following steps to identify the median of the annual total compensation of all our employees, as well as to determine the annual total compensation of our median employee and our CEO.

 

1. We determined that, as of December 31, 2017, our employee population consisted of approximately 27 individuals. This population consisted of our full-time, part-time, and temporary employees employed with us as of the determination date.
2. To identify the “median employee” from our employee population, we used the amount of “gross wages” for the identified employees as reflected in our payroll records for 2017. For gross wages, we generally used the total amount of compensation the employees were paid before any taxes, deductions, insurance premiums, and other payroll withholding. We did not use any statistical sampling techniques.
3. For the annual total compensation of our median employee, we identified and calculated the elements of that employee’s compensation for 2017 in accordance with the requirements of Item 402(c)(2)(x).
4. For the annual total compensation of our CEO, we used the amount reported in the “Total” column of our 2017 Summary Compensation Table, adjusted as follows.
  a) As noted elsewhere above, Mr. Linville began serving as our CEO effective August 4, 2017, upon the resignation of Abraham “Avi” Mirman, our former CEO. We identified Mr. Linville as our CEO for this pay ratio disclosure because he was serving in that position on December 31, 2017, the date that we selected to identify our median employee.
  b) As Mr. Linville served as our CEO for only a portion of 2017, in accordance with applicable SEC rules, we annualized the amount reported in the Summary Compensation Table above. This resulted in annual total compensation for purposes of determining the ratio in the amount of $2.2 million, which exceeds the amount reported for Mr. Linville in the Summary Compensation Table by $0.2 million.
  c) To maintain consistency between the annual total compensation of our CEO and the median employee, we also added the estimated value of our CEO’s health care benefits on an annualized basis (estimated for our CEO and our CEO’s eligible dependents at $0.02 million) to the amount reported in the Summary Compensation Table, as annualized as described in b) immediately above.

  

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EQUITY COMPENSATION PLAN INFORMATION

 

The following table provides information as of December 31, 2017 regarding the number of shares of our common stock that may be issued under our equity compensation plans:

 

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 (excluding securities reflected in column
(1))
 
Equity compensation plans approved by security holders     7,301,899       $3.74       607,186  
Equity compensation plans not approved by security holders                  
Total     7,301,899       $3.74       607,186  

 

(1)Includes stock options and RSUs outstanding under our 2016 Plan and our 2012 EIP as of December 31, 2017. 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, 2017. Does not take into account outstanding RSUs.

 

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 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, we recorded the warrants as a derivative due to the price reset provision encompassed in the warrants.

 

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.

 

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

 

Securities Authorized for Issuance under Equity Compensation Plans

 

Please see “Item 11 – Equity Compensation Plan Information” above.

 

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 5, 2018, 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 5, 2018 of 53,496,205. 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 Exchange Act. 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 5, 2018 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.

 

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    Series C Preferred Stock     Common Stock  
Name and Address of Beneficial Owner   Shared
Beneficially
Owned
    % of
Class
    Lilis
common
stock
Held
Directly
    Lilis
common
stock
Acquirable
Within 60
Days(1)
    Total
Beneficially
Owned(1)
    Percent of
Class
Beneficially
Owned(1)
 
                                     
Directors and Named Executive Officers                                                
Ronald D. Ormand, Executive Chairman of the Board                 4,002,253 (2)     199,167 (3)     4,201,420       7.8 %(4)
James Linville, Chief Executive Officer                 159,352       110,500 (5)     269,852       *  
Joseph Daches, Chief Financial Officer                 578,676       502,500 (6)     1,081,176       2.0 %
Peter Benz, Director                 132,384       31,667 (7)     164,051       *  
Nuno Brandolini, Director                 499,445       119,575 (8)     619,020       1.2 %
R. Glenn Dawson, Director                 650,578       183,335 (9)     833,913       1.6 %
General Merrill McPeak, Director                 466,922       150,157 (10)     617,109       1.2 %
G. Tyler Runnels, Director                 2,121,790 (11)     128,325 (12)     2,250,115       4.2 %
Mark Christensen, Director                     1,215,843 (13)     1,043,052 (14)     2,258,895       4.1 %
Markus Specks, Director                                   *  
John Johanning, Director                                   *  
Directors and Officers as a Group (12 persons)                 10,188,207       2,702,308 (15)     12,890,335       22.9 %(16)
                                                 
5% Stockholders                                                
Abraham Mirman (Former Chief Executive Officer and Former Director)
20 Broad Hollow Road, Suite 3011B
Melville, NY 11747
                2,384,522 (17)     1,810,000 (18)     4,194,522       7.6 %
Bryan Ezralow,
23622 Calabasas Road, Suite 200,
Calabasas, CA 913012
                3,486,676 (19)     272,731 (20)     3,759,407       7.0 %
Marc Ezralow,
23622 Calabasas Road, Suite 200,
Calabasas, CA 913012
                2,783,559 (21)     220,783 (22)     3,004,342       5.6 %
J. Steven Emerson,
1522 Ensley Avenue,
Los Angeles, CA 90024
                4,064,074 (23)     324,678 (24)     4,388,752       8.2 %
Rosseau Asset Management Ltd.
181 Bay Street, Suite 2920, Box 736
Toronto, Ontario M5J 2T3
                2,712,334 (25)     (26)      2,712,334       5.1 %
Investor Company 5J5505D
Vertex One Asset Management
1021 West Hastings Street, Suite 3200
Vancouver, BC V6E 0C3
                7,189,480 (27)           7,189,480       13.4 %
Vӓrde Partners, Inc.
901 Marquette Avenue South
Suite 330, Minneapolis, MN 55402
    100,000       100 %           43,592,196 (28)     43,592,196       44.9 %

 

 

 

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

 

(1)Excluding the outstanding warrants issued in connection with our March 2017 Private Placement, the terms of the Company’s outstanding warrants, (the “Blocker Securities”) contain a provision prohibiting the conversion of the exercise of warrants into common stock of the Company if, upon 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%. Accordingly, the share numbers in the above table represent ownership after giving effect to the beneficial ownership limitations described in this footnote. However, the foregoing restrictions do not prevent such holder from exercising, as applicable, some of its holdings, selling those shares, and then exercising, as applicable, more of its holdings, while still staying below the 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. Thus, while the ownership percentages are also given with regard to this beneficial ownership limitation, specific footnotes indicate what the ownership would be as of August 24, 2017, without giving effect to limitation

 

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(2)Consists of: (i) 1,583,555 shares of common stock held directly by Mr. Ormand; (ii) 2,378,698 shares of common stock held by Perugia Investments L.P. (“Perugia”); and (iii) 40,000 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.

 

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

 

In addition, Mr. Ormand beneficially owns an aggregate of 993,102 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) 533,102 shares of common stock issuable upon exercise of warrants held by Perugia; and (ii) 460,000 shares of common stock issuable upon exercise of warrants held by The Bruin Trust.

 

(4)Including the Blocker Securities, and ignoring the Blocker Limitation, Mr. Ormand beneficially owns a total of 5,194,522 shares of common stock, which represents 9.5% of our currently issued and outstanding common stock.

 

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

 

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

 

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

 

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

 

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

 

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

 

(11)Consists of: (i) 71,744 shares of common stock held directly by Mr. Runnels; (ii) 267,436 shares of common stock held by T.R. Winston & Company, LLC (“TRW”); (iii) 534,899 shares of common stock held by TRW Capital Growth Fund, LP; (iv) 1,218,005 shares of common stock held by Runnels Family Trust DTD 1-11-2000 (“Runnels Family Trust”), for which Mr. Runnels acts as trustee with Jasmine N. Runnels, who share voting and dispositive power; (v) 29,300 shares of common stock held by High Tide, LLC (“High Tide”); (vi) 402 shares of common stock held by Pangaea Partners, LLC; and (vii) 3 shares of common stock held by SEP IRA Pershing LLC Custodian (“SEP IRA”). Mr. Runnels is the natural person with ultimate voting and dispositive power over the securities held by TRW, TRW Capital Grown Fund, LP, High Tide, Pangaea Partners, LLC and SEP IRA.

 

(12)Represents shares of common stock subject to options and warrants exercisable within 60 days.

 

In addition, Mr. Runnels beneficially owns an aggregate of 1,011,406 additional shares of common stock acquirable within 60 days, each of which is subject to a Blocker Limitation. However, Mr. Runnels’ 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) 636,046 shares of common stock issuable upon exercise of warrants held by TRW; and (ii) 375,360 shares of common stock issuable upon exercise of warrants held by Runnels Family Trust.

 

(13)Consists of: (i) 23,954 shares of common stock held directly by Mr. Christensen; (ii) 1,103,362 shares of common stock held by Trace Capital Inc. (“Trace”), for which Mr. Christensen’s wife is the natural person with ultimate voting and dispositive power; and (ii) 88,527 shares of common stock held by GM&P Holding Corp., for which Mr. Christensen is the natural person with ultimate voting and dispositive power.

 

(14)Represents shares of common stock subject to options and warrants exercisable within 60 days.

 

(15)As indicated in the above footnotes, this amount excludes an aggregate of 2,004,508 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 14,894,843 shares of common stock, which represents 25.6% of our currently issued and outstanding common stock.

 

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(17)Consists of: (i) 1,203,087 shares of common stock held by The Bralina Group, LLC; and (ii) 1,181,435 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.

 

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

 

In addition, Mr. Mirman beneficially owns an aggregate of 850,641 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) 545,454 shares of common stock issuable upon exercise of warrants held by the Bralina Group, LLC and (ii) 305,187 shares of common stock issuable upon exercise of warrants held directly by Mr. Mirman.

 

(19)Based solely on a Schedule 13G filed by Bryan Ezralow on February 13, 2018. 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 2,092,723 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 94,106 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 101,571 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 416,252 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 495,674 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 985,117 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.

  

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Collectively, the shares of common stock reported herein in which Bryan Ezralow has sole voting and dispositive power over such shares are 1,393,953 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 1,258,098 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 135,855 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. 

 

(20)Represents shares of common stock subject to warrants exercisable within 60 days.

 

In addition, Bryan Ezralow beneficially owns an aggregate of 836,712 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: (i) 295,455 shares of common stock issuable upon the exercise of warrants, held by the Bryan Trust; (ii) 43,182 shares of common stock issuable upon the exercise of warrants, held by the Irrevocable Trust; (iii) 125,889 shares of common stock issuable upon the exercise of warrants, held by Elevado; (iv) 266,088 shares of common stock issuable upon the exercise of warrants, held by EZ Colony; (v) 43,912 shares of common stock issuable upon the exercise of warrants, held by the Marital Trust; (vi) 41,285 shares of common stock issuable upon the exercise of warrants, held by the Family Trust; and (vii) 20,899 shares of common stock issuable upon the exercise of warrants, held by EMSE.

 

  (21) Based solely on a Schedule 13G filed by Marc Ezralow on February 14, 2018. 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 2,092,723 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 94,106 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 101,571 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 416,252 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 495,674 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 985,117 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 690,836 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 554,981 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 135,855 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.

 

(22)Represents shares of common stock subject to warrants exercisable within 60 days.

 

In addition, Marc Ezralow beneficially owns an aggregate of 711,710 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: (i) 43,182 shares of common stock issuable upon exercise of warrants, held the SPA Trust; (ii) 170,455 shares of common stock issuable upon exercise of warrants, held by the 1997 Trust; (iii) 125,889 shares of common stock issuable upon the exercise of warrants, held by Elevado; (iv) 266,088 shares of common stock issuable upon the exercise of warrants, held by EZ Colony; (v) 43,912 shares of common stock issuable upon the exercise of warrants, held by the Marital Trust; (vi) 41,285 shares of common stock issuable upon the exercise of warrants, held by the Family Trust; and (vii) 20,899 shares of common stock issuable upon the exercise of warrants, held by EMSE..

 

(23)Based on the Schedule 13D filed on May 19, 2017, this consists of: (i) 1,630,652 shares of common stock held by J. Steven Emerson Roth IRA Pershing LLC as Custodian (“Roth IRA Pershing”); (ii) 1,371,067 shares of common stock held by J. Steven Emerson IRA Rollover II Pershing LLC as Custodian (“IRA Rollover II Pershing”); (iii) 430,945 shares of common stock held by Emerson Partners (“Emerson”); (iv) 583,237 shares of common stock held directly by J. Steven Emerson; (v) 48,173 shares of common stock held by the Emerson Family Foundation. J. Steven Emerson is the natural person with ultimate voting or investment control over the shares of common stock held by each of Roth IRA Pershing, IRA Rollover II Pershing, Emerson and the Emerson Family Foundation.

 

 

(24)Represents shares of common stock subject to warrants exercisable within 60 days.

 

(25)Based on the Schedule 13G/A filed on February 14, 2018. The natural person with ultimate voting or investment control over the shares of common stock held is Warren Irwin.

 

(26)Rosseau Asset Management (“Rosseau”) beneficially owns an aggregate of 1,136,364 additional shares of common stock acquirable within 60 days, each of which is subject to a Blocker Limitation. However, Rosseau’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 1,136,364 shares of common stock issuable upon exercise of warrants.

 

(27)Based on the Schedule 13G filed on February 9, 2018. The natural person with ultimate voting or investment control over the shares of common stock held is John Thiessen.

 

(28)Based on the Schedule 13D/A filed on February 5, 2018. This represents shares of common stock which may be issued pursuant to the conversion of term loans under the Second Lien Credit Agreement and shares of Series C Preferred Stock within 60 days as if such term loans and Series C Preferred Stock had been converted on the date of borrowing or issuance, as applicable.

 

​Värde Partners, Inc. is the ultimate owner of the general partners (the “General Partners”), of each of The Värde Fund XI (Master), L.P., The Värde Fund XII (Master), L.P.; The Värde Master Skyway Fund, L.P., The Värde Fund VI-A, L.P., Värde Investment Partners, L.P., and Värde Investment Partners (Offshore) Master, L.P. (the “Värde Entities”), or of the General Partners’ managing members. Mr. George Hicks is the chief executive officer of Värde Partners, Inc. As such each of Värde Partners, Inc. and Mr. Hicks may be deemed to have beneficial ownership of the shares owned by each of the Värde Entities. Each of Värde Partners, Inc. and Mr. Hicks disclaims beneficial ownership of the securities held indirectly through the Värde Entities except to the extent of their pecuniary interest therein, and this disclosure shall not be deemed an admission that any such reporting person is the beneficial owner for purposes of this Annual Report or for any other purpose.

 

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

 

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

 

Transactions with Related Parties

 

We describe below transactions and series of similar transactions, since January 1, 2017, 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 “Series B Purchasers”) in connection with the Series B Preferred Stock offering.

 

On June 6, 2016, we entered into a Transaction Fee Agreement, which was subsequently amended on June 8, 2016, with TRW, a more than 5% stockholder 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 KES 7, 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 Series B Purchasers in the Series B Preferred Stock offering include the following related parties: (i) Abraham Mirman, our former Chief Executive Officer and director, purchased $1.65 million of Series B Preferred Stock through the Bralina Group, LLC for which Mr. Mirman holds shared voting and dispositive power; (ii) Ronald D. Ormand, the Chairman of our Board of Directors, purchased $1.0 million of Series B Preferred Stock through Perugia Investments LP for which Mr. Ormand holds sole voting and dispositive power; (iii) Kevin Nanke, the Company’s former Executive Vice President and Chief Financial Officer during the year ended December 31, 2016, purchased $200,000 of Series B Preferred Stock through KKN Holdings LLC, for which Mr. Nanke holds sole voting and dispositive power; (iv) R. Glenn Dawson, a director of our Company, purchased $125,000 of Series B Preferred Stock; and (v) Bryan Ezralow and Marc Ezralow, who are each a more than 5% stockholder of our Company, purchased $1.3 million of Series B Preferred Stock through various entities beneficially owned by them.

 

On April 25, 2017, the Company entered into a Series B 6.0% Convertible Preferred Stock Conversion Agreement (the “Conversion Agreement”), with all of the holders of the outstanding Series B Preferred Stock (the “Series B Holders”) to convert any outstanding shares of Series B Preferred Stock including an increase in the stated value of to reflect dividends that would have accrued through December 31, 2017 in the amount of approximately 14.3 million shares of common stock. On the same date, the Series B Holders further agreed to adopt the Amended and Restated Certificate of Designation of Preferences, Rights and Limitations of Series B 6% Convertible Preferred Stock (“A&R COD”) in order to remove certain restrictions contained therein with respect to beneficial ownership limitations, a condition of the Conversion Agreement. The A&R COD became effective on April 26, 2017, resulting in the automatic conversion of all outstanding Series B Preferred Stock. As a result of the automatic conversion, certain of our related parties received shares of our common stock: (i) Abraham Mirman received 1,639,000 shares of common stock valued at $8.4 million through the Bralina Group, LLC for which Mr. Mirman holds shared voting and dispositive power; (ii) Ronald D. Ormand received 993,334 shares of common stock valued at $5.1 million through Perugia Investments LP for which Mr. Ormand holds sole voting and dispositive power; (iii) Kevin Nanke received 198,667 shares of common stock valued at $1.0 million; (iv) R. Glenn Dawson received 117,822 shares of common stock valued at $0.6 million; (v) Bryan Ezralow received 894,001 shares of common stock valued at $4.6 million through various entities beneficially owned by him; (vi) Marc Ezralow received 745,001 shares of common stock valued at $3.8 million through various entities beneficially owned by him; (vii) Rosseau Asset Management Ltd received 1,986,667 shares of common stock valued at $10.2 million; (viii) Investor Company 5J5505D received 3,925,654 shares of common stock valued at $20.1 million; (ix) J. Steven Emerson received 1,490,000 shares of common stock valued at $7.6 million through various entities beneficially owned by him; and (x) G. Tyler Runnels received 472,827 shares of common stock valued at $2.4 million through various entities beneficially owned by him.

 

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For more information on the Series B Preferred Stock offering see Note 11 Stockholders Equity to our consolidated financial statements in Item 8 of this Annual Report on Form 10-K.

 

First Lien Credit Agreement, Drawdown, Repayment and Amendment.

 

On September 29, 2016, we entered into the First Lien Credit Agreement. Certain parties to the First Lien Credit Agreement included our related parties: (i) TRW, acting as collateral agent, (ii) Bryan Ezralow through certain of his investment entities, (iii) Marc Ezralow through certain of his investment entities, (iv) J. Steven Emerson through certain of his investment entities, and (v) Investor Company 5J5505D.

 

On February 7, 2017, pursuant to the terms of the First Lien 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 “First Lien Term Loan”). Certain parties that participated in the upsize of the First Lien Term Loan included our related parties: (i) Rosseau Asset Management Ltd ($2 million), (ii) Trace Capital Inc. ($1.6 million), and (iii) LOGiQ Capital 2016 ($1 million).

 

On April 24, 2017, we entered into an amendment to the First Lien Credit Agreement, in which the balance of the first lien credit facility in an aggregate amount of $38.1 million plus accrued and unpaid interest thereon was paid down and we extended further credit in the form of an initial bridge loan in an aggregate principal amount of $15.0 million.

 

Certain parties that were paid down pursuant to the First Lien Amendments included certain of our related parties such as TRW, acting as collateral agent, Bryan Ezralow and Marc Ezralow, through certain of their investment entities ($2.4 million), J. Steven Emerson through certain of his investment entities ($6.0 million), Rosseau Asset Management Ltd ($2.0 million), LOGiQ Capital 2016 ($1.0 million), and Investor Company 5J5505D ($20.1 million). Certain parties to the bridge loan and the incremental bridge loan included certain of our related parties such as: (i) Investor Company 5J5505D ($3.3 million), and (ii) Trace Capital Inc ($2.95 million).

 

In addition, on October 19, 2017, pursuant to the First Lien Amendments, the lenders made further extensions of credit, in addition to the currently existing loans under the First Lien Credit Agreement, in the form of an additional, incremental bridge loan in an aggregate principal amount of $15,000,000.

 

Second Lien Credit Agreement

  

On April 26, 2017, we entered into the Second Lien Credit Agreement with the lenders party thereto. Värde Partners, Inc. is the lead lender under the Second Lien Credit Agreement and, as a result of its conversion rights thereunder, it beneficially owns over 5% of our securities that are acquirable within 60 days. For more information about the Second Lien Credit Agreement, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Second Lien Credit Agreement” under Item 7 of this report.

 

March 2017 Private Placement

 

On February 28, 2017, we entered into a Securities Purchase Agreement in connection with the March 2017 Private Placement. As of December 31, 2017, we received aggregate gross proceeds of $20 million and issued 5,194,821 shares of common stock and warrants to purchase 2,597,420 shares of common stock.

  

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The subscribers include the following related parties: (i) Bryan Ezralow, the beneficial owner of 5% or more of our common stock, through the Bryan Ezralow 1994 Trust u/t/d 12/22/1994, EMSE LLC, Elevado Investment Company, LLC and the Marc Ezralow Irrevocable Trust u/t/d 6/1/2004, (ii) Marc Ezralow, the beneficial owner of 5% or more of our common stock, through the Marc Ezralow 1997 Trust u/t/d 11/26/1997, EMSE LLC, Elevado Investment Company, LLC and the SPA Trust u/t/d 9/13/2004, (iii) J. Steven Emerson, through J. Steven Emerson Roth IRA Pershing LLC as Custodian and J. Steven Emerson IRA Rollover II Pershing LLC as Custodian, (iv) G. Tyler Runnels, through TRW and the Runnels Family Trust DTD 1-11-2000, and (v) Mark Christensen, through Trace Capital Inc.. The approximate dollar value of the amount of (i) the interest of Bryan Ezralow, through the Bryan Ezralow 1994 Trust u/t/d 12/22/1994, EMSE LLC, Elevado Investment Company, LLC and the Marc Ezralow Irrevocable Trust u/t/d 6/1/2004, in the March 2017 Private Placement was $1.4 million; (ii) the interest of Marc Ezralow, through the Marc Ezralow 1997 Trust u/t/d 11/26/1997, EMSE LLC, Elevado Investment Company, LLC and the SPA Trust u/t/d 9/13/2004, in the March 2017 Private Placement was $1.2 million, (iii) the interest of J. Steven Emerson, through J. Steven Emerson Roth IRA Pershing LLC as Custodian and J. Steven Emerson IRA Rollover II Pershing LLC as Custodian, in the March 2017 Private Placement was $2.5 million, (iv) the interest of G. Tyler Runnels, through TRW and the Runnels Family Trust DTD 1-11-2000, in the March 2017 Private Placement was $0.8 million and (v) the interest of Mark Christensen, through Trace Capital Inc., in the March 2017 Private Placement was $1.0 million.

 

Additionally, 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.

 

For more information on the March 2017 Private Placement see Management’s Discussion and Analysis-Liquidity and Capital Resources-March 2017 Private Placement.

 

G. Tyler Runnels and T.R. Winston

 

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. The Company terminated this office lease on October 31, 2017.

 

Mark Christensen, Trace Capital Inc. and KES 7 Capital Inc.

 

Since January 1, 2016, Mr. Christensen has been involved in the following related party transactions with the Company, through Trace Capital Inc. (“Trace”), an entity owned by Mr. Christensen’s wife, and KES 7 Capital Inc. (“KES 7”) for which he serves as Chief Executive Officer and 100% owner. Trace has participated in the following transactions with the Company: (i) the offering of Series B Preferred Stock in June 2016 pursuant to which Trace purchased 500 shares of Series B Preferred Stock and warrants to purchase up to 227,274 shares of common stock with an exercise price of $2.50 (the “Series B Warrants”) for aggregate consideration of $500,000; (ii) the Company’s first lien credit facility entered into in September 2016, which had initial aggregate principal commitments of approximately $31 million and a maximum facility size of $50 million, and the upsize of that facility in February 2017, of which Trace held indebtedness in an aggregate amount of $2.6 million, and which resulted in the repricing of the Series B Warrants to $0.01 that were exercised in full on April 25, 2017; (iii) the Company’s March 2017 private placement of units comprised of common stock and warrants raising net proceeds of approximately $20 million pursuant to which Trace purchased units for an aggregate purchase price of approximately $1 million; (iv) the conversion of shares of Series B Preferred Stock that Trace held plus accrued dividends, which resulted in the issuance of 467,348 shares of the common stock to Trace (valued at approximately $1,495,514 based on the $3.20 closing trading price of the common stock on December 9, 2016); and (v) the amendment to the Company’s first lien credit facility on April 24, 2017 and related matters, in which the balance of the first lien credit facility in an aggregate amount of $38.1 million plus accrued and unpaid interest thereon was paid down (including the $2.6 million of indebtedness held by Trace) and in which $1.45 million was reinvested by Trace in the form of bridge loans with an aggregate amount of $15 million outstanding. Each of the initial lenders that participated in the first lien credit facility also waived their right to any prepayment premium, including Trace. Additionally, KES 7 has acted as an advisor and placement agent in connection with certain of the Company’s financing transactions resulting in aggregate fees paid by the Company of approximately $2.4 million in cash and the issuance of warrants to purchase 820,000 shares of common stock with an exercise price of $1.30 to KES 7.

 

MMZ Consulting

 

From August 15, 2016 through April 15, 2017, we engaged MMZ Consulting LLC (“MMZ”) as a third-party consultant to support our full cycle drilling & completions engineering needs. On January 29, 2017, Brennan Short, the president and owner of MMZ was hired to be our Chief Operating Officer. Since the beginning of this fiscal year, we have paid approximately $205,000 to MMZ in exchange for services rendered. Mr. Short is the sole member of MMZ.

 

Series C Preferred Stock Issuance

 

On January 30, 2018, we entered into a Securities Purchase Agreement with certain private funds affiliated with Värde Partners, Inc. (the “Series C Purchasers”), pursuant to which, on January 31, 2018, the Series C Purchasers purchased 100,000 shares of our newly created series of preferred stock of the Company, designated as “Series C 9.75% Convertible Participating Preferred Stock” (the “Series C Preferred Stock”), for a purchase price of $1,000 per share, or an aggregate of $100,000,000. Värde Partners, Inc. is the lead lender, and certain private funds affiliated with Värde Partners, Inc. are lenders, under the Company’s Second Lien Credit Agreement. Värde Partners, Inc. and its applicable affiliated funds beneficially own over 5% of our common stock as a result of their respective conversion rights under the Second Lien Credit Agreement and the Series C Preferred Stock.

 

VPD Acquisition

 

On February 28, 2018, pursuant to an agreement we entered into with VPD Texas, L.P. (“VPD”) dated that date, we acquired from VPD a 50% undivided leasehold interest in certain oil and gas properties and assets in Loving and Winkler Counties, Texas for a purchase price of approximately $10.5 million. VPD is affiliated with Värde Partners, Inc., which is the lead lender under the Second Lien Credit Agreement, and Värde Partners, Inc. and certain affiliated funds hold all of the issued and outstanding shares of Series C Preferred Stock. As such, Värde Partners, Inc. and its applicable affiliated funds beneficially own over 5% of our common stock as a result of their respective conversion rights under the Second Lien Credit Agreement and the Series C Preferred Stock.

 

Compensation of Directors

 

See “Executive Compensation-Compensation of Nonemployee Directors” above.

 

Conflict of Interest Policy

 

Our Board 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. Our 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 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 for consideration and each of these transactions was unanimously approved by our Board after reviewing the criteria set forth in the preceding two sentences.

  

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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 firms, BDO USA, LLP and Marcum LLP, for the years ended December 31, 2017 and 2016, respectively:

  

   Year Ended December 31, 
Fee Category  2017   2016 
   (In thousands) 
Audit Fees  $

1,616

   $    358 
Audit-Related Fees   

11

    341 
All Other Fees   

-

    - 
Total Fees  $

1,627

   $699 

 

Audit Fees consist of the aggregate fees for professional services rendered for the audit of our annual consolidated financial statements, our internal controls over financial reporting, and the reviews of the consolidated 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.

 

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, 2017, we had no non-audit services provided by our independent registered public accounting firm.

 

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GLOSSARY

 

In this Annual Report, the following abbreviation and terms are used:

 

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

 

Bcf. Billion cubic feet of natural gas.

 

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.

 

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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 natural gas reserves. Proved developed oil and natural 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 exis