Securities Registration Statement (s-1/a)

Date : 06/19/2017 @ 6:02AM
Source : Edgar (US Regulatory)
Stock : A^LLEX (LLEX)
Quote : 4.31  0.0 (0.00%) @ 4:10PM
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Securities Registration Statement (s-1/a)

Filed with the Securities and Exchange Commission on June 16, 2017.

 

Registration Statement No. 333-217519

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

Amendment No. 1

to  

Form S-1
REGISTRATION STATEMENT UNDER
THE SECURITIES ACT OF 1933 

 

LILIS ENERGY, INC.
(Exact name of registrant as specified in its charter)

 

Nevada   1311   74-3231613

(State or other jurisdiction of

incorporation or organization)

 

(Primary Standard Industrial

Classification Code Number)

 

(I.R.S. Employer

Identification Number)

 

  300 E. Sonterra Blvd., Suite No. 1220
San Antonio, TX 78258
(210) 999-5400
 
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)
     
 

Abraham Mirman

Chief Executive Officer

300 E. Sonterra Blvd., Suite No. 1220

San Antonio, TX 78258

(210) 999-5400

 
(Name, address, including zip code, and telephone number, including area code, of agent for service)
 
  Copies of all communications to:  
 

 

Michael A. Hedge

K&L Gates LLP

1 Park Plaza, Twelfth Floor

Irvine, CA 92614

(949) 253-0900

 

 

Approximate date of commencement of proposed sale to the public:
As soon as practicable after the effective date of this registration statement.

 

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. ☒

 

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐

 

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐

 

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer ☐ Accelerated filer ☐
Non-accelerated filer ☐  (Do not check if a smaller reporting company)    Smaller reporting company ☒
      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 7(a)(2)(B) of the Securities Act. ☐

 

 

 

  

CALCULATION OF REGISTRATION FEE

  

Title of Each Class of Securities to be Registered   Amount to
be
Registered(1)
      Proposed
Maximum
Offering
Price Per
Share(2)
    Proposed
Maximum
Aggregate
Offering
Price(2)
    Amount of
Registration
Fee(2)
 
Common stock, $0.0001 par value per share     22,727,273(3)     $ 5.03     $ 114,318,183.19     $ 13,249.48  
Common stock, $0.0001 par value per share, upon exercise of additional warrants     138,214(4)     $ 5.03     $ 695,216.42     $ 80.58  

   

(1) Pursuant to Rule 416 under the Securities Act of 1933, as amended, or the Securities Act, this registration statement also covers any additional shares of common stock which may become issuable by reason of any stock dividends, stock splits, or similar transactions which results in an increase in the number of Registrant’s outstanding shares of common stock.

 

(2) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(c) under the Securities Act, based upon the average of the high and low prices of the common stock on June 15, 2017, as reported on the NYSE MKT. The Registrant previously paid $12,274.86 of the total registration fee in connection with prior filings of this Registration Statement.

 

(3) Represents shares of common stock that the Registrant expects could be issuable upon (1) the conversion of certain convertible term loans or (2) the conversion of shares of convertible preferred stock issuable in certain circumstances upon conversion of such convertible term loans, as described in this registration statement.

 

(4) Represents an additional number of shares of common stock that the Registrant expects could be issuable upon exercise of certain warrants to purchase shares of common stock, as described in this registration statement.

 

The Registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act or until the registration statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

 

 

 

  

Information contained herein is not complete and may be changed. These securities may not be sold until the Registration Statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

 

SUBJECT TO COMPLETION, DATED JUNE 16, 2017

 

PROSPECTUS

 

 

Lilis Energy, Inc.

 

Up to 22,865,487 Shares of Common Stock

 

This prospectus relates to the offer and sale from time to time by the selling stockholders identified in this prospectus of up to an aggregate of 22,865,487 shares of common stock, par value $0.0001 per share, which we refer to as common stock, of Lilis Energy, Inc., which we refer to as us, we, the Company, the Registrant or Lilis. These shares consist of:

 

(i) 22,727,273 shares of common stock (the “Convertible Loan Securities”) that we expect could be issuable upon (a) the conversion of term loans (the “Second Lien Term Loan”) made under the Second Lien Credit Agreement, dated as of April 26, 2017, by and between Lilis Energy, Inc., the guarantors from time to time party thereto, the Lender party thereto and Wilmington Trust, National Association as administrative agent (the “Second Lien Credit Agreement”) or (b) conversion of shares of our convertible preferred stock (the “Lender Preferred Stock”) issuable in certain circumstances upon conversion of the Second Lien Term Loan. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Second Lien Credit Agreement” below for more information; and

 

(ii) 138,214 shares of common stock that we expect could be issuable upon exercise of certain warrants to purchase shares of common stock at an exercise price of $3.50 per share, such warrants having been originally issued to Heartland Bank (the “Heartland Warrant”).

 

The selling stockholders may acquire the Convertible Loan Securities pursuant to the conversion of the Second Lien Term Loan. We are required to file a registration statement pursuant to the registration rights agreement entered into with the Term Loan investors. See “Recent Sales of Unregistered Securities” below for more information.

 

The shares of common stock registered hereby may be offered and sold by the selling stockholders from time to time in the over-the-counter market or other national securities exchange or automated interdealer quotation system on which our common stock is then listed or quoted, or through one or more underwriters, broker-dealers or agents. If the shares of common stock are sold through underwriters or broker-dealers, the selling stockholders will be responsible for underwriting discounts or commissions or agent’s commissions. The shares of common stock may be sold in one or more transactions at fixed prices, at prevailing market prices at the time of the sale, at varying prices determined at the time of sale, or at negotiated prices. See “Plan of Distribution.”

 

We are not selling any shares of common stock under this prospectus, and we will not receive any of the proceeds from the offer and sale of shares of our common stock by the selling stockholders. See “Use of Proceeds” beginning on page 37 of this prospectus.

 

This prospectus describes the general manner in which shares of common stock may be offered and sold by any selling stockholders. When the selling stockholders sells shares of common stock under this prospectus, we may, if necessary and required by law, provide a prospectus supplement that will contain specific information about the terms of that offering. Any prospectus supplement may also add to, update, modify or replace information contained in this prospectus. We urge you to read carefully this prospectus, any accompanying prospectus supplement and any documents we incorporate by reference into this prospectus and any accompanying prospectus supplement before you make your investment decision.

 

Our common stock is currently listed on the NYSE MKT under the symbol “LLEX.” On June 15, 2017, the last reported sale price of shares of our common stock on the NYSE MKT was $5.00.

 

On June 23, 2016, we effected a 1-for-10 reverse split of our issued and outstanding shares of common stock. All share and per share information in this prospectus gives effect to the 1-for-10 reverse split, retroactively.

 

Investing in our securities involves a high degree of risk. See “Risk Factors” beginning on page 10 of this prospectus.

 

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

 

The date of this prospectus is         , 2017.

 

 

 

   

TABLE OF CONTENTS

 

    Page
Prospectus Summary   1
The Offering   9
Risk Factors   10
Special Note Regarding Forward-Looking Statements   35
Use of Proceeds   37
Selling Stockholders   38
Plan of Distribution   39
Dividend Policy   41
Management’s Discussion and Analysis of Financial Condition and Results of Operations   42
Business   56
Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities   73
Directors and Executive Officers   74
Executive and Director Compensation   78
Certain Relationships and Related Transactions and Director Independence   87
Security Ownership of Certain Beneficial Owners and Management   93
Description of Capital Stock   98
Legal Matters   100
Experts   100
Where You Can Find More Information   100
Glossary of Oil and Gas Terms   101
Index to Financial Statements   F-1

   

 

 

   

ABOUT THIS PROSPECTUS

 

You should rely only on the information contained in this prospectus. We have not authorized anyone to provide you with information different from that contained in this prospectus. The selling stockholders are offering to sell and seeking offers to buy shares of our common stock they acquire upon conversion of its convertible term loan debt, only in jurisdictions where offers and sales are permitted. The information contained in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or of any sale of our common stock. Unless otherwise indicated, information contained in this prospectus concerning our industry, including our market opportunity, is based on information from independent industry analysts, market research, publicly available information and industry publications. The third-party sources from which we have obtained information are generally believed to be reliable, but we cannot assure you that such information is accurate or complete. Management estimates contained in this prospectus are based on assumptions made by us using our internal research data and our knowledge of such industry and market, including reference to publicly available information released by independent industry analysts and third party sources, which we believe to be reasonable. In addition, while we believe the market opportunity information included in this prospectus is generally reliable and is based on reasonable assumptions, such data involves risks and uncertainties and is subject to change based on various factors, including those discussed under the heading “Risk Factors.” These and other factors could cause our future performance to differ materially from our assumptions and estimates. See “Special Note Regarding Forward-Looking Statements.”

 

No person is authorized in connection with this prospectus to give any information or to make any representations about us, the selling stockholders, the securities or any matter discussed in this prospectus, other than the information and representations contained in this prospectus. If any other information or representation is given or made, such information or representation may not be relied upon as having been authorized by us or any of the selling stockholders. This prospectus does not constitute an offer to sell, or a solicitation of an offer to buy the securities in any circumstances under which the offer or solicitation is unlawful. Neither the delivery of this prospectus nor any distribution of securities in accordance with this prospectus shall, under any circumstances, imply that there has been no change in our affairs since the date of this prospectus. The prospectus will be updated, and updated prospectuses made available for delivery, to the extent required by the federal securities laws.

 

For investors outside the United States: We have not and the selling stockholders have not done anything that would permit this offering or possession or distribution of this prospectus in any jurisdiction where action for that purpose is required, other than in the United States. You are required to inform yourselves about and to observe any restrictions relating to the offering of the shares of common stock and the distribution and possession of this prospectus outside of the United States. 

  

 

 

  

PROSPECTUS SUMMARY

 

This summary highlights certain information contained in other parts of this prospectus. Because it is a summary, it does not contain all of the information you should consider before investing in our securities. You should read the entire prospectus carefully, including “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Business” and our consolidated financial statements and related notes before deciding to invest in our common stock. References in this prospectus to “Lilis,” “the Company,” “we,” “our,” “ours,” “us,” or similar terms refer to Lilis Energy, Inc. and its wholly-owned subsidiary, Brushy Resources, Inc., taken together, unless the context indicates otherwise.

   

Business Overview

 

Lilis Energy, Inc. and its consolidated subsidiaries (collectively, “we,” “us,” “our,” “Lilis Energy,” “Lilis,” or the “Company”) is an upstream independent oil and gas company engaged in the acquisition, drilling and production of oil and natural gas properties and prospects. Our primary focus is drilling horizontal wells in the Delaware Basin of West Texas, which we believe will provide attractive returns on a majority of our acreage positions. Our goal is to earn economic returns to our shareholders through cash flow from new production of oil, natural gas and NGLs, as well as through derisking the development profile of our portfolio of properties in order to add overall value. Our drilling program utilizes the development of new horizontal wells across several potentially productive formations in the Delaware Basin but initially targeting the Wolfcamp formation. We drilled our first horizontal well in late 2016 and completed it in January 2017.

 

On June 23, 2016, we completed a merger transaction with Brushy Resources, Inc. (“Brushy”). The merger resulted in the acquisition of our properties in the Delaware Basin as well as the majority of our current operating activity. Our contiguous acreage position is offset by RSP Permian, Inc., Matador Resources Company, Devon Energy Corporation, Royal Dutch Shell PLC, Anadarko Petroleum Corp., and XTO Energy Inc., among other operators.

 

On March 31, 2017, we completed the divestiture of all of our oil and gas properties located in the Denver-Julesburg Basin (the “DJ Basin”), for a gross purchase price of $2 million, which completed our transformation to a pure play Permian Basin company.

 

Our Properties

 

Delaware Basin - We have accumulated over 10,000 net acres in the Delaware Basin, comprised of large contiguous blocks in Reeves, Winkler and Loving Counties, Texas and Lea County, New Mexico. Currently, 48% of our acreage position is held by production, and we are the named operator on 100% of our producing acreage. These characteristics give us control over the pace of development and the ability to design a more efficient and profitable drilling program that maximizes recovery of hydrocarbons. We expect that substantially all of our estimated 2017 capital expenditure budget will be focused on the development and expansion of our Delaware Basin acreage and operations. The aerial extent of the Delaware Basin stretches across Ward, Reeves, Loving, Winkler, Pecos, and Culberson Counties in Texas and also runs north into Lea and Eddy Counties in New Mexico. The Delaware Basin is comprised of multiple stacked petroleum systems. Drilling and completion technology has evolved with more modern vintage wells utilizing longer laterals, more numerous fracture stimulation stages, and higher volumes of proppant. Our 2017 drilling and completion program currently calls for the drilling of up to 11 gross or 9 net wells (consisting of vertical re-entries and new drills) initially targeting the Wolfcamp formation.  

 

  1  

 

  

Recent Developments

 

Operations

 

Recent Well Results - In late 2016, we commenced our horizontal drilling program in the Delaware Basin with one rig targeting the Wolfcamp. As of June 15, 2017, we have three horizontal wells on production (Bison #1H, Grizzly #1H and Hippo #1H).

 

The Bison #1H had a 24-hour peak rate of 2,375 Boe/d (75% liquids) and a peak 30-day rate of 2,144 Boe/d (74% liquids) and is currently producing. The Grizzly #1H had a 24-hour peak rate of 1,666 Boe/d (65% liquids) and a peak 30-day rate of 1,323 Boe/d (63% liquids) and is currently producing. Both the Bison #1H and Grizzly #1H are performing above the 923 MBoe and 738 MBoe type curves, respectively, and are located in the northwestern corner of Winkler County.

 

The Bison #1H targeted the Wolfcamp B and was completed utilizing 35 frac stages over a 6,897-ft stimulated interval. The Grizzly #1H also targeted the Wolfcamp B and was completed utilizing 20 frac stages over a 4,103-ft stimulated interval and is currently producing.

 

We also finished completing one additional horizontal well, the Hippo #1H, in April 2017. The Hippo #1H had a 24-hour peak rate of 1,917 Boe/d (74% liquids) and has not yet reached a peak 30-day initial production rate. The Hippo #1H also targeted the Wolfcamp B and was completed utilizing 20 frac stages over a 4,105-ft stimulated interval, it is currently being tested.

 

In addition to the Hippo #1H, we also finished the drilling of the Lion #1H with a projected treatable lateral length of 4,105-ft. Completion of the Lion #1H is scheduled for June 2017   and is anticipated to utilize the same sand loading as the Hippo #1H with 150 ft plug to plug spacing.

 

Acreage Acquisitions - Since entering the Delaware Basin in June 2016, we have grown our acreage position 186% from approximately 3,500 net acres to over 10,000 net acres primarily in our Delaware Basin-Core area.

 

Financing Activities

 

First Lien Credit Agreement

 

On April 24, 2017, and subsequently on April 26, 2017, we entered into the first and second amendments (together, the “First Lien Amendments”) to our existing first lien credit agreement, dated September 29, 2016 (the “First Lien Credit Agreement”), by and among the Company, Brushy, ImPetro Operating, LLC, a Delaware limited liability company (“Operating”) and ImPetro Resources, LLC, a Delaware limited liability company (“Resources”, and together with Brushy and Operating, the “Initial Guarantors”), the lenders party thereto (the “Original Lenders”) and T.R. Winston & Company, LLC, as initial collateral agent. Pursuant to the First Lien Amendments, among other things, certain lenders identified therein joined the Original Lenders as lenders under the First Lien Credit Agreement in connection with further extensions of credit, in addition to the existing loans under the First Lien Credit Agreement (the “Existing Loans”), in the form of an additional bridge loans in an aggregate principal amount of $15,000,000 (the “Bridge Loans”). Under the terms of the Amendments, Lilis Operating Company, LLC (“Lilis Operating,” and together with the Initial Guarantors, the “Guarantors”) shall join the Initial Guarantors as a guarantor under the First Lien Credit Agreement. The Bridge Loans was fully drawn on April 24, 2017.

 

On April 26, 2017, in connection with the closing of the Second Lien Credit Agreement, we paid off the Existing Loans in full including accrued and unpaid interest thereon.

 

The Bridge Loans, in addition to the Existing Loans, are secured by first priority liens on substantially all of the Company’s and Guarantors’ assets, including its oil and gas properties located in the Permian Basin, and all of the obligations thereunder are unconditionally guaranteed by each of the Guarantors.

 

The First Lien Credit Agreement, as amended by the First Lien Amendments, provides that the unpaid principal of the Bridge Loans will bear cash interest at a rate per annum of (i) 6% for the first six months after the execution of the Amendment and (ii) thereafter, so long as any Bridge Loan is outstanding, a rate of 10%. Additionally, the unpaid principal of the Bridge Loans will bear interest at a rate per annum of 6%, payable only in-kind by increasing the principal amount of the Bridge Loans by the amount of such interest due on each interest payment date . The Bridge Loan matures on October 24, 2018. The Bridge Loans may be repaid in whole or part at any time at the option of the Company, subject to the payment of certain specified prepayment premiums. The Bridge Loans are subject to mandatory prepayment with the net proceeds of certain asset sales and casualty events, subject to the right of the Company to reinvest the net proceeds of asset sales and casualty events within 180 days.

 

 

  2  

 

  

Redemption of 6% Redeemable Preferred Stock

 

Effective as of April 24, 2017, we have redeemed, in full, our 6% Redeemable Preferred Stock. In accordance therewith, the Company and Hexagon, LLC (f/k/a Hexagon Investments, LLC) (“Hexagon”), the only holder of the 6% Redeemable Preferred Stock, entered into a Settlement and Release Agreement, dated April 24, 2017 (the “Settlement Agreement”), which sets forth the terms of the redemption. In addition, the Settlement Agreement resolves certain other issues related to liability reimbursements on certain oil and gas properties that had previously been alleged by Hexagon. Accordingly, all prior issues with Hexagon have been resolved and the 6% Redeemable Preferred Stock has been redeemed in full.

 

Series B 6.0% Convertible Preferred Stock Conversion

 

On April 24, 2017, we and all of the holders of our Series B 6% Preferred Stock (the “Series B Holders”) agreed to adopt the Amended and Restated Certificate of Designation of Preferences, Rights and Limitations of the Preferred Stock (“A&R COD”) in order to remove certain restrictions contained therein with respect to beneficial ownership limitations. On the same date, we entered into a Series B 6.0% Convertible Preferred Stock Conversion Agreement (the “Conversion Agreement”), of our outstanding Series B 6% Convertible Preferred Stock (the “Series B Preferred Stock”).

 

Pursuant to the terms of the Conversion Agreement, we and the Series B Holders have mutually agreed that, immediately upon the effectiveness of the amended and restated Certificate of Designations of Preferences, Rights and Limitations of Series B 6% Convertible Preferred Stock, the Series B Holders will be deemed to have automatically converted all remaining shares of Series B Preferred Stock held by them into approximately 14.3 million shares of common stock, pursuant to the terms of A&R COD, such amount representing the number of shares of Common Stock into which the outstanding shares of Series B Preferred Stock held by the Series B Holders would be convertible pursuant to the terms of A&R COD, with such Conversion including an increase in the stated value of the Series B Preferred Stock to reflect dividends that would have accrued through December 31, 2017.

 

The Conversion Agreement contains customary representations and warranties by the Series B Holders and other agreements and obligations of the parties.

 

Second Lien Credit Agreement

  

On April 26, 2017, we entered into a second lien term loan credit agreement (the “Second Lien Credit Agreement”) by and among the Company, the Guarantors, Wilmington Trust, National Association, as administrative agent, and the lenders party thereto (the “Lenders”, and collectively the “Lead Lender”), pursuant to which the Lenders agreed to make convertible loans to us in an aggregate initial principal amount of up to $125 million in two tranches. The first tranche consists of an $80 million term loan (the “Second Lien Term Loan”), which was fully drawn and funded on April 26, 2017. The second tranche consists of up to $45 million of delayed draw term loans (the “Delayed Draw Loans” and, together with the Second Lien Term Loan, the “Loans”) to be funded from time to time on or before February 28, 2019, at our request, subject to certain conditions. Each tranche of Loans will bear interest at a rate of 8.25%, compounded quarterly in arrears and payable only in-kind by increasing the principal amount of the Loans by the amount of the interest due on each interest payment date.

 

The Loans are secured by second priority liens on substantially all of our and the Guarantors’ assets, including its oil and gas properties located in the Permian Basin, and all of the obligations thereunder are unconditionally guaranteed by each of the Guarantors.

 

The proceeds of the Loans will be used only to (a) repay the Existing Loans including accrued but unpaid interest thereon, (b) pay the fees, expenses and transaction costs of the transactions and (c) finance our working capital needs, including capital expenditures, and for general corporate purposes, including the exploration, acquisition and development of oil and gas property.

 

  3  

 

  

The Loans mature on April 26, 2021. The Loans are subject to mandatory prepayment with the net proceeds of certain asset sales and casualty events within 180 days and, in the case of asset sales and casualty events, prepayment of the Bridge Loans. We may not voluntarily prepay the 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 will be required to pay a customary make-whole premium in connection with any mandatory or voluntary prepayment of the Loans.

 

The Second Lien Credit Agreement contains certain customary representations and warranties and affirmative and negative covenants, including covenants relating to: maintenance of books and records, financial reporting and notification, compliance with laws, maintenance of properties and insurance; limitations on incurrence of indebtedness, investments, dividends and other restricted payments, lease obligations, hedging and capital expenditures; and maintenance of a specified asset coverage ratio. The Second Lien Credit Agreement also provides for events of default, including failure to pay any principal or interest when due, failure to perform or observe covenants, cross-default on certain outstanding debt obligations, the failure of a Guarantor to comply with the provisions of its Guaranty, and bankruptcy or insolvency events, subject to certain specified cure periods. The amounts under the Second Lien Credit Agreement could be accelerated and be due and payable upon an event of default.

  

Each tranche of the Loans is separately convertible at any time, in full and not in part, at the option of the Lead Lender, as follows:

 

· 70% of the principal amount of each tranche of Loans, together with accrued and unpaid interest and the make-whole premium on such principal amount, will convert into a number of newly issued shares of common stock determined by dividing the total of such principal amount, accrued and unpaid interest and make-whole premium by $5.50 (subject to adjustment as described below, the “Conversion Price”); and

 

· 30% of the principal amount of each tranche of Loans, together with accrued and unpaid interest and the make-whole premium on such principal amount, will convert on a dollar for dollar basis into a new term loan (the “Take Back Loans”).

 

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

 

Additionally, we will have the option to convert the 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. The number of shares of common stock issuable upon exercise of the conversion option will be determined by dividing the principal amount of the Loans converted, plus accrued and unpaid interest on such principal amount, by 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 less than the Conversion Price in effect from time, subject to certain exceptions. However, unless the Shareholder Approval (as defined below) has been obtained, these “price protection” anti-dilution adjustments cannot reduce the Conversion Price to a price less than (a) in the case of the Conversion Price for the Second Lien Term Loan, $4.26 which was the closing price of the common stock on April 25, 2017 or (b) in the case of the Conversion Price for the Delayed Draw Loans, the last closing price of the Common Stock prior to the time the Company becomes bound to incur any Delayed Draw Loan (the “Conversion Price Floor”).

 

  4  

 

  

Prior to obtaining Shareholder Approval, the number of shares of common stock issuable to any Lender upon conversion of Loans will be capped at a number of shares that would not result in that Lender, together with its affiliates and the other members of any group (as such term is used in sections 13(d) and 14(d) of the Securities Exchange Act of 1934, as amended) including such Lender, owning in excess of 19.999% of the outstanding shares of common stock or voting power of the Company on the date of conversion, after giving effect to the conversion (the “Share Cap”).

 

If the Share Cap applies to any Lender on any conversion of Loans, instead of issuing shares of common stock in excess of the Share Cap, the Company will be required to issue to the Lender affected by the Share Cap shares of a new series of preferred stock of the Company to be established if required pursuant to the terms of the Second Lien Credit Agreement (the “Lender Preferred Stock”). Holders of shares of Lender Preferred Stock, if any are issued:

 

· will have no voting rights, except for certain limited matters related to modification of the terms of the Lender Preferred Stock and similar matters or as otherwise required by Nevada corporate law;

 

· will be not be entitled to receive any preferential dividends but will participate, on as-converted basis, in any dividends declared and paid on the Common Stock; and

 

·

upon liquidation, dissolution or winding up of the Company, will be entitled to receive, in preference to holders of Common Stock, an amount per share equal to the greater of $0.01 and the amount the holders of shares of Lender Preferred Stock would receive with respect to each share of Common Stock issuable on conversion of the Lender Preferred Stock in connection with such liquidation, dissolution or winding up if all shares of Lender Preferred Stock were converted into Common Stock immediately before such event.

 

The shares of Lender Preferred Stock issued to any Lender as a result of the Share Cap will be convertible into the number of shares of common stock that were not issued to the Lender as a result of the Share Cap, but such conversion would be permitted or be mandatory only (i) after the Shareholder Approval is obtained, (ii) if such conversion would not result in the holder of the Lender Preferred Stock so converted, together with its affiliates and the other members of any “group: including such holder, owning in excess of 19.999% of the outstanding shares of common stock or voting power of the Company on the date of conversion, after giving effect to the conversion, or (iii) in connection with a Change of Control Transaction (as such term will be defined in the certificate of designations creating the Lender Preferred Stock).

 

The Second Lien Credit Agreement requires us to submit to its shareholders for their approval (the “Shareholder Approval”) the following matters as promptly as practicable after April 26, 2017:

 

· the issuance of shares of Common Stock upon conversion of the Loans or any Lender Preferred Stock at a conversion price that is less than the Conversion Price Floor if the Conversion Price were reduced to a price less than the Conversion Price Floor as a result of the anti-dilution adjustments described above; and

 

· any change of control (as defined in applicable stock exchange listing rules) that might occur as a result of the conversion of the Loans or any Lender Preferred Stock.

 

If the Shareholder Approval is obtained, the Conversion Price Floor and the Share Cap will no longer apply.

 

The Second Lien Credit Agreement provides that the Lead Lender is entitled to appoint one observer to the Board of Directors of the Company during the period prior to the conversion of the Second Lien Term Loan. The board observer is not entitled to vote on any matter and is entitled to participate only in meetings of the full Board of Directors and not any of its committees (other than any “executive” or similar committee) and to receive materials distributed to all members of the Board of Directors. The board observer may be excluded from board meetings and distributions of board materials if the Board of Directors determines in good faith that (i) such exclusion is necessary to preserve any privilege or (i) the subject matter thereof involves an actual or potential conflict of interest with respect to the board observer or any of its affiliates. The right to appoint the board observer will terminate upon conversion of the Second Lien Term Loan.

 

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Following the conversion of the Second Lien Term Loan, the Lenders, collectively, will have the right to appoint two members of the Board of Directors as long as they continue to own at least 20% of the outstanding common stock and one member of the Board of Directors as long as they continue to own at least 12.5% (but less than 20%) of the outstanding common stock. The number of directors constituting the entire Board of Directors will be increased by the number of directors the Lenders are entitled to appoint. The number of directors the Lenders have the right to appoint will be reduced if necessary so that the percentage of the number of directors constituting the entire Board of Directors represented by the directors appointed by the Lenders does not exceed the percentage of the outstanding Common Stock or voting power of the Company represented by the Common Stock held by the Lenders.

 

In connection with the execution of Second Lien Credit Agreement and funding of the Second Lien Term Loan, the Company and the Lenders entered into a Registration Rights Agreement dated as of April 26, 2017 (the “Registration Rights Agreement”) pursuant to which, among other matters, the Company will be required to file with the Securities and Exchange Commission a registration statement under the Securities Act of 1933, as amended registering for resale the shares of common stock issuable upon conversion of the Loans or any shares of common stock underlying the Lender Preferred Stock issued. The Registration Rights Agreement entitles the lenders to certain demand rights and piggyback rights with respect to underwritten offerings in common stock and contains customary covenants and indemnification and contribution provisions. We do not intend to register any shares of Lender Preferred Stock.  

   

Our Business Strategies

 

Our primary business objective is to increase shareholder value through the execution of the following strategies:

 

· Grow production, cash flow and reserves by developing our extensive Delaware Basin drilling inventory. We intend to selectively develop our acreage base in an effort to maximize its value and resource potential. We will pursue drilling opportunities that offer competitive returns that we consider to be low risk based on production history and industry activity in the area and repeatable as a result of well-defined geological properties over a large area. Through the conversion of our resource base to developed reserves, we will seek to increase our reserves, production and cash flow while generating favorable returns on invested capital. We will continue to closely monitor operators with active leases on adjoining properties, or offset operators, as they delineate adjoining acreage and zones, providing us further data to optimize our development plan over time. We believe this strategy will allow us to significantly grow our production, cash flow and reserves while efficiently allocating capital to maximize the value of our resource base.

  

· Pursue additional leasing and strategic acquisitions. We intend to focus primarily on increasing our acreage position through leasing in the immediate vicinity our existing Delaware Basin acreage, while selectively pursuing other acquisition opportunities that meet our strategic and financial objectives. Our acreage position extends through what we believe are multiple oil and natural gas producing stratigraphic horizons in the Delaware Basin, which we refer to as the stacked pay core, and we believe we can economically and efficiently add and integrate additional acreage into our current operations. Since entering the Delaware Basin in June 2016, we have grown our acreage position 186% from approximately 3,500 net acres to over 10,000 net acres as of June 15, 2017.

  

· Maximize returns by optimizing drilling and completion techniques and improving operating efficiency . We believe completion design combined with cost reductions are the biggest drivers within our control affecting field-level economics. We seek to maintain operational control of our properties in order to better execute on our strategy of enhancing returns through operating improvements and cost efficiencies Through a methodical and continuous focus on drilling efficiency, wellbore accuracy, completion design and execution, we plan to selectively re-enter vertical wells to drill horizontal laterals, reducing drilling cost and improving landing accuracy. We believe that through review of the drilling and mud logs of the vertical wells in our field we can optimize our horizontal wellbore economics and consequently increase production, cash flows, and net asset value. Additionally, our contiguous acreage position is offset by RSP Permian, Inc., Matador Resources Company, Devon Energy Corporation, Royal Dutch Shell PLC, Anadarko Petroleum Corp., and XTO Energy Inc., among other operators, and we will continue to observe and monitor their drilling activity and well results in the area to integrate best practices as we execute on our development plan.

 

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Our Competitive Strengths

 

·

Attractively positioned in the oil-rich Delaware Basin. We have accumulated a leasehold position of over 10,000 net acres in the Delaware Basin as of June 15, 2017. We believe the Delaware Basin has one of the highest rates of return among such formations in North America based on results of offset operators. In addition to leveraging our technical expertise in this core area, our geographically-concentrated acreage position allows us to capitalize on economies of scale with respect to drilling and production costs. Based on our drilling and production results to date and well-established offset operator activity in and around our project areas, we believe there are relatively low geologic risks and ample repeatable drilling opportunities across our core Delaware Basin operating area. We plan on allocating substantially all of our increased 2017 capital budget to our Delaware Basin activities.

  

· High degree of operational control . Our significant operational control allows us to execute our development program, with a focus on the timing and allocation of capital expenditures and application of the optimal drilling and completion techniques to efficiently develop our resource base. We believe this flexibility allows us to efficiently develop our current acreage and adjust drilling and completion activity opportunistically for the prevailing commodity price environment. In addition, we believe communication and data exchange with offset operators will reduce the risks associated with drilling the multiple horizontal zones of our acreage. We also believe our significant level of operational control will enable us to implement drilling and completion optimization strategies, such as pad drilling, continued reduction of spud- to- rig release days and tailored completion designs.

 

·

Experienced and incentivized management team . Our senior management team has a proven track record of building and running successful businesses focused on the development and acquisition of oil and natural gas properties. We believe our team's experience and expertise in horizontal drilling and completions in unconventional formations across multiple resource plays provides us with a distinct competitive advantage. Additionally, our management team and board of directors currently hold in aggregate approximately 15% of our outstanding common stock, which provides a meaningful incentive to increase the value of our business for the benefit of all stockholders. 

 

· Conservatively capitalized balance sheet and strong liquidity profile . As of June 15, 2017, we have approximately $46 million of cash on the balance sheet, and have discretionary access to an additional $45 million under our delayed-draw Second Lien Term Loan to fund leasing activity and acquisitions. We believe that through the availability of cash on hand, Second Lien Term Loan draw availability, and cash flow from operations, we will have sufficient liquidity to execute on our updated planned 2017 capital program.

 

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Corporate Information

 

Our principal office is located at 300 East Sonterra Blvd, Suite No. 1220, San Antonio, TX 78258, and our telephone number is (210) 999-5400. Our corporate website address is  www.lilisenergy.com . Information contained on or accessible through our website, or any other website, is not, and will not be, a part of this prospectus and is not incorporated by reference into this prospectus.

 

Additional Information

 

Additional information about us can be obtained from the documents incorporated by reference herein. See “Where You Can Find More Information” on page 100 of this prospectus.

 

 

 

 

 

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THE OFFERING

  

Common stock outstanding before this offering as of June 15, 2017:   50,419,551
     
Securities offered for resale to the public by the selling stockholders:   22,865,487
     
Common stock outstanding after this offering (which assumes the full conversion or exercise of all securities being registered pursuant to this prospectus):   73,285,038
     
Use of proceeds:   We will not receive any proceeds from the sale of our common stock offered by the selling stockholders under this prospectus. See “Use of Proceeds” beginning on page 37 of this prospectus.
     
The NYSE MKT symbol:   “LLEX”
     
  Risk factors:   Investing in our securities involves a high degree of risk. See “Risk Factors” beginning on page 10 of this prospectus for a discussion of factors you should consider before making a decision to invest in our securities.
     
Common stock splits:   On June 23, 2016, we effected a 1-for-10 reverse split of our issued and outstanding shares of common stock. All share and per share information in this prospectus gives effect to the 1-for-10 reverse split, retroactively.

 

The number of shares of common stock to be outstanding after this offering is based on 50,419,551 shares of common stock outstanding as of June 15, 2017, not giving effect to this offering. The number of shares of common stock to be outstanding after this offering does not include:

 

12,384,831 shares of common stock issuable upon the exercise of warrants outstanding as of June 15, 2017, at a weighted average exercise price of $4.60 per share not being registered in this offering;

 

7,083,500 shares of common stock issuable upon the exercise of options outstanding as of June 15, 2017, at a weighted average exercise price of $3.35 per share;

 

629,657 shares of common stock reserved for future issuance under the Lilis Energy, Inc. 2016 Omnibus Incentive Plan, or the 2016 Plan, as of June 15, 2017; and

 

9,999 restricted stock units outstanding as of June 15, 2017.

 

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RISK FACTORS

 

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

 

Risks Relating to Our Business

 

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

 

We need significant capital to continue to operate our properties and continue operations. In the near term, we intend to finance our capital expenditures with cash flow from operations, funds draw under our First Lien Term Loan and Second Lien Term Loan, and future issuance of debt and/or equity securities. Our cash flow from operations and access to capital is subject to a number of variables, including:

 

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

 

Our operations and other capital resources may not provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Further, our actual capital expenditures in 2017 could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount of capital we have available, we could be required to seek additional sources of capital, which may include refinancing existing debt, joint venture partnerships, production payment financings, sales of non-core property assets, offerings of debt or equity securities or other means. We may not be able to obtain debt or equity financing on terms favorable, or at all.

 

If we are unable to fund our capital requirements, we may be required to curtail our operations relating to the exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves, or may be otherwise unable to implement their development plan, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations. In addition, a delay in or the failure to complete proposed or future infrastructure projects could delay or eliminate potential efficiencies and related cost savings. The occurrence of such events may prevent us from continuing to operate our business and our common stock and preferred stock may not have any value.

 

We have substantial liquidity needs and may be required to seek additional financing to fund our 2017 capital budget.  If we are unable to obtain financing on satisfactory terms or maintain adequate liquidity, our ability to fund our capital budget, replace our proved reserves or to maintain production levels and generate revenue will be limited.

 

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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 preferred stock. 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 may face uncertainty regarding the adequacy of our liquidity and capital resources to fund our 2017 capital budget.  Our liquidity, including our ability to meet our ongoing operational obligations, is dependent upon, among other things: (i) our ability to maintain adequate cash on hand, including our ability to access additional financing, and (ii) our ability to generate cash flow from operations.  Our ability to maintain adequate liquidity depends in part upon industry conditions and general economic, financial, competitive, regulatory and other factors beyond our control.  We can provide no assurance that additional financing will be available or, if available, offered to us on acceptable terms. 

 

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

 

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

 

· the level of global exploration and production;

 

· the level of global inventories;

 

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

 

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

 

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

 

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

 

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

 

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

 

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

                  

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

 

Lower commodity prices may reduce our cash flows and borrowing ability. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our reserves as existing reserves are depleted. Lower commodity prices may also reduce the amount of oil, NGLs, and natural gas that we can produce economically, and a significant portion of our exploitation, development and exploration projects could become uneconomic. This may result in our having to make significant downward adjustments to our estimated proved reserves. As a result, if commodity prices remain depressed for a lengthy period of time or experience a further substantial or extended decline, our future business, financial condition, results of operations, liquidity, or ability to finance planned capital expenditures may be materially and adversely affected.

 

Our level of indebtedness could adversely affect our ability to raise additional capital to fund our operations, limit our ability to react to changes in the economy or our industry and prevent us from meeting our obligations under our indebtedness.

 

On September 29, 2016, we entered into the First Lien Credit Agreement, as subsequently amended on April 24, 2017, and April 26, 2017, that currently provides for an 18-month senior secured term loan with an aggregate principal amount of $15 million outstanding as of June 15, 2017. Additionally, on April 26, 2017, we entered into the Second Lien Credit Agreement, that provides for a four year second lien secured term loan with an aggregate principal amount of $80 million outstanding, and under which we may borrow up to an aggregate principal amount of $45 million. Our degree of leverage could have important consequences, including the following:

 

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

 

We may incur additional debt, including secured indebtedness, or issue preferred stock in order to maintain adequate liquidity and develop and acquire properties to the extent desired. A higher level of indebtedness and/or preferred stock increases the risk that we may default on our obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, natural gas and oil prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets, the number of shares of capital stock we have authorized, unissued and unreserved and our performance at the time we need capital.

 

Each of the 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.

 

Each of the First Lien Credit Agreement and Second Lien Credit Agreement contain restrictive covenants that limit our ability to, among other things:

 

· incur additional indebtedness;

 

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· 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.

 

We may from time to time enter into alternative or additional debt agreements that contain covenant restrictions that may prevent us from taking actions that we believe would be in the best interest of our business, may require us to sell assets or take other actions to reduce indebtedness to meet such covenants, and may make it difficult for us to successfully execute our business strategy or effectively compete with companies that are not similarly restricted.

 

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

 

Our management does not expect that our disclosure controls and procedures and internal controls will prevent all possible errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are being met. In addition, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls are evaluated relative to their costs. Because of the inherent limitations in all control systems, no evaluation of our controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected. The design of any system of controls is based in part upon the likelihood of future events, and any design may not succeed in achieving its intended goals under all potential future conditions. Over time, a control may become inadequate because of changes in conditions, or the degree of compliance with our policies or procedures may deteriorate. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur without detection.

 

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

 

Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, and the rules and regulations promulgated by the SEC to implement Section 404, our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external purposes in accordance with generally accepted accounting principles. Under the supervision and with the participation of our management, including the Chief Executive Officer and the Chief Financial Officer, we are required to conduct an evaluation of the effectiveness of our internal control over financial reporting based on the framework of internal control issued by the Committee of Sponsoring Organizations of the Treadway Commission (“2013 COSO Framework”). Because of its inherent limitations, internal controls over financial reporting may not prevent or detect misstatements. In addition, projections of any evaluation effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.

 

Through September 30, 2016, management had concluded that its internal control over financial reporting was not effective. During the fourth quarter of 2016, we completed our remediation efforts, but we may discover additional areas of our internal control over financial reporting in the future which may require improvement. If we are unable to assert that our internal control over financial reporting is effective in any future period, or if our auditors are unable to express an opinion on the effectiveness of our internal controls, we could lose investor confidence in the accuracy and completeness of our financial reports, which could have an adverse effect on our stock price.

 

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

 

We use the full cost method of accounting whereby all costs related to the acquisition and development of oil and natural gas properties are capitalized into a single cost center referred to as a full cost pool. These costs include land acquisition costs, geological and geophysical costs, carrying charges on non-producing properties, costs of drilling wells, completing productive wells, or plugging and abandoning non-productive wells, costs related to expired leases, or leases underlying producing and non-producing wells, and allocated overhead charges related to acquisition and exploration activities. Under the full cost method of accounting, capitalized oil and natural gas property that comprise the full cost pool, less accumulated depletion and net of deferred income taxes, may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves. This ceiling test is performed at least quarterly. Should the capitalized costs of the full cost pool exceed this ceiling, we would recognize an impairment expense. We recognized an impairment expense of approximately $4.7 million and $24.5 million for the years ended December 31, 2016 and 2015, respectively. At December 31, 2016, the Company’s estimates of discounted future cash flows indicated that the carrying amounts were not expected to be recovered due to a decrease in proved reserves. During 2016, commodity prices continued to trade in a low range. With low commodity prices sustained for the majority of 2016, some of our properties became uneconomic triggering impairment charge of $4.7 million at December 31, 2016. The impairment charge of $24.5 million in 2015 was due to the lower commodity prices and lack of capital to develop our undeveloped oil and gas properties. Future write-downs could occur for numerous reasons, including, but not limited to continued reductions in oil and gas prices that lower the estimate of future net revenues from proved oil and natural gas reserves, revisions to reserve estimates, or from the addition of non-productive capitalized costs that would be transferred to the amortization base subject to DD&A and the ceiling test that does not result in a corresponding increase in oil and gas reserves. Impairments of plugging and abandonment of wells in progress are other areas where costs may be capitalized into the full cost pool, without any corresponding increase in reserve values; as such, these situations could result in future additional impairment expenses.

 

If commodity prices stay at current levels or decline further, we could incur full cost ceiling impairments in future quarters. Because the ceiling calculation uses rolling 12-month average commodity prices, the effect of lower quarter-over-quarter prices in 2016 compared to 2015 is a lower ceiling value each quarter. This may result in ongoing impairments each quarter until prices stabilize or improve. Impairment charges would not affect cash flow from operating activities, but would adversely affect our net income and stockholders’ equity.

 

Our estimated reserves are based on many assumptions that may prove inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

 

No one can measure underground accumulations of oil and natural gas in an exact way. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves which could adversely affect business, results of operations, financial condition and our ability to make cash distributions to shareholders.

 

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

 

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Further, the present value of future net cash flows from proved reserves may not be the current market value of estimated oil and natural gas reserves. In accordance with SEC requirements, we based the estimated discounted future net cash flows from proved reserves on the 12-month average oil and gas index prices, calculated as the un-weighted arithmetic average for the first-day-of-the-month price for each month and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties.

 

Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we used when calculating discounted future net cash flows for reporting requirements in compliance with the FASB in Accounting Standards Codification, which is referred to as ASC 932 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

 

Oil and natural gas prices are highly volatile, and our revenue, profitability, cash flow, future growth and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent on prevailing prices of oil and natural gas.

 

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

 

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

 

Volatile oil and natural gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market for oil and natural gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects.

 

Our revenues, operating results, profitability and future rate of growth depend primarily upon the prices we receive for oil and, to a lesser extent, natural gas that we sell. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. In addition, we may need to record asset carrying value write-downs if prices fall. A significant decline in the prices of natural gas or oil could adversely affect our financial position, financial results, cash flows, access to capital and ability to grow.

 

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

 

In order to manage our exposure to price risks in the marketing of our oil and natural gas, from time to time, we may enter into derivative contracts that economically hedge our oil and gas price on a portion of our production. These contracts may limit our potential gains if oil and natural gas prices were to rise substantially over the price established by the contract. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

 

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

 

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· 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 March 31, 2017, we had no hedging agreements in place.

 

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

 

Our management has specifically identified and scheduled drilling locations as an estimation of future multi-year drilling activities on existing acreage. These scheduled drilling locations represent a significant component of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability of capital, costs, drilling results, regulatory approvals and other factors. Because of these uncertainties, we do not know if the potential drilling locations previously identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

 

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

 

Our success will depend on the success of our drilling program. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. Analogies drawn from available data from other wells, more fully explored prospects or producing fields may not be applicable to current drilling prospects.

 

The budgeted costs of planning, drilling, completing and operating wells are often exceeded and such costs can increase significantly due to various complications that may arise during the drilling and operating processes. Before a well is spud, we may incur significant geological and geophysical (seismic) costs, which are incurred whether a well eventually produces commercial quantities of hydrocarbons, or is drilled at all. Exploration wells endure a much greater risk of loss than development wells. If actual drilling and development costs are significantly more than the current estimated costs, we may not be able to continue operations as proposed and could be forced to modify drilling plans accordingly. Drilling for oil and natural gas involves numerous risks, including the risk that no commercially productive natural gas or oil reservoirs will be discovered. The cost of drilling, completing, and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors beyond our control, including:

 

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

 

If we decide to drill a certain location, there is a risk that (i) no commercially productive oil or natural gas reservoirs will be found or produced, or (ii) we may drill or participate in new wells that are not productive or drill wells that are productive, but that do not produce sufficient net revenues to return a profit after drilling, operating and other costs. A productive well may become uneconomical if water or other deleterious substances are encountered which impair or prevent the production of oil and/or natural gas from the well. Our overall drilling success rate or drilling success rate for activity within a particular project area may decline. Unsuccessful drilling activities could result in a significant decline in production and revenues and materially harm operations and financial condition by reducing available cash and resources. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production and reserves from the well or abandonment of the well.

 

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

 

We derive essentially all of our revenues from the sale of our oil and natural gas to unaffiliated third party purchasers, independent marketing companies and mid-stream companies. Any delays in payments from such purchasers caused by financial problems encountered by them will have an immediate negative effect on our results of operations and cash flows.

 

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

 

Prospects in which we decide to participate may not yield oil or natural gas in commercially viable quantities or quantities sufficient to meet our targeted rate of return.

 

A prospect is a property in which we own an interest and contains what we believe, based on available reservoir, seismic and/or geological information, to be indications of commercial oil or natural gas. Our prospects are in various stages of evaluation, ranging from a prospect that is ready to be drilled to a prospect that will require substantial additional technical assessment, data acquisition and/or seismic data processing and interpretation. There is no definitive method to predict in advance of drilling and testing and wider-scale development whether any particular prospect will yield oil or natural gas in sufficient quantities to be economically viable. The use of reservoir, geologic and seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. The analysis we perform using data from other wells, more fully explored prospects or producing fields may not be useful in predicting the characteristics and potential reserves associated with our drilling prospects.

 

Our industry is highly competitive, which may adversely affect our performance, including our ability to participate in ready to drill prospects in our core areas .

 

We operate in a highly competitive environment. In addition to capital, the principal resources necessary for the exploration and production of oil and natural gas are:

 

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

 

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

 

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

 

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

 

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

 

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

 

One of our growth strategies is to pursue selective acquisitions of undeveloped acreage potentially containing oil and natural gas reserves. If we choose to pursue an acquisition, we will perform a review of the target properties; however, these reviews are inherently incomplete as they are based on the quality, availability and interpretation of the reviewed data, the acumen and the assumptions of the evaluation personnel. Generally, it is not feasible to review in depth every individual property, well, facility and/or file involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. We may not perform an inspection on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we may not be able to obtain effective contractual protection against all or part of those problems, and we may assume environmental and other risks and liabilities in connection with the acquired properties. If we acquire properties with risks or liabilities that were unknown or not assessed correctly, financial condition, results of operations and cash flows could be adversely affected as claims are settled and cleanup costs related to these liabilities are incurred.

 

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

 

If an examination of the title history of a property that we purchased reveals an oil and natural gas lease has been purchased in error from a person who is not the owner of the mineral interest desired, our interest would be worthless. In such an instance, the amount paid for such oil and natural gas lease as well as any royalties paid pursuant to the terms of the lease prior to the discovery of the title defect would be lost.

 

Prior to the drilling of an oil and natural gas well, however, it is the normal practice in the oil and natural gas industry 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 operational risk is concentrated due to our reliance on a small number of wells, operators and oil and gas purchasers.

 

We have concentrated operational risks both in terms of producing oil and gas properties, the operators we use and in the purchasers of our oil and gas production. An operational failure by an operator, the decline of production from a property and the termination of a contractual agreement with an operator or purchaser could have a material negative impact on our company. Our properties are located in areas where we have multiple markets for our oil and gas. As such, the loss of any single purchaser will not have a material impact with our ability to sell our oil and gas.

 

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We may not be the operator on all of our drilling locations, and, therefore, we may not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated assets.

 

Currently, we are the operator of our Delaware assets. However, as we carry out our exploration and development programs, we may enter into arrangements with respect to existing or future drilling locations that result in a greater proportion of locations being operated by others. As a result, we may have limited ability to exercise influence over the operations of the drilling locations operated by our partners. Dependence on the operator could prevent us from realizing target returns for those locations. The success and timing of exploration and development activities operated by our partners will depend on a number of factors that will be largely outside of our control, including:

 

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

 

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

 

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

 

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


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

 

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

 

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

 

Producing oil and gas reservoirs generally are characterized by declining production rates and depletion that vary depending upon reservoir characteristics subsurface and surface pressures and other factors. Thus, our future oil and gas reserves and production and, therefore, our cash flow and revenue are highly dependent on our success in efficiently obtaining additional reserves. We may not be able to develop, find or acquire reserves to replace our current and future production at costs or other terms acceptable to us, or at all, in which case our business, financial condition and results of operations would be materially and adversely affected.

 

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Part of our strategy involves drilling in existing or emerging unconventional shale plays using available horizontal drilling and completion techniques. The results of our planned exploratory and development drilling in these plays are subject to drilling and completion execution risks and drilling results may not meet our economic expectations for reserves or production. As a result, we may incur material write-downs and the value of our undeveloped acreage could decline if drilling results are unsuccessful.

 

Unconventional operations involve utilizing drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling include, but are not limited to, not reaching the desired objective due to drilling problems, not landing our wellbore in the desired drilling zone or specific target, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the wellbore and being able to run tools and other equipment consistently through the horizontal wellbore. Risks that we face while completing our wells include, but are not limited to, mechanical integrity, being able to hydraulic fracture stimulate the planned number of stages, being able to run tools the entire length of the wellbore during completion operations, proper design and engineering versus reservoir parameters, and successfully cleaning out the wellbore after completion of the final fracture stimulation stage.

 

Our experience with horizontal well applications utilizing the latest drilling and completion techniques specifically in the formations where we are currently operating is limited; however, we contract with local experts in the area to design, plan and conduct our drilling and completion operations. Ultimately, the success of these drilling and completion techniques can only be developed over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and limited takeaway capacity or otherwise, and/or natural gas and oil prices decline, the return on our investment in these areas may not be as attractive as we anticipate and we could incur material write-downs of undeveloped properties and the value of our undeveloped acreage could decline in the future.

 

The unavailability or high cost of drilling rigs, equipment supplies or personnel could adversely affect our ability to execute our exploration and development plans.

 

The oil and gas industry is cyclical and, from time to time, there are shortages of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs of and demand for rigs, equipment and supplies may increase substantially and their availability may be limited. In addition, the demand for, and wage rates of, qualified personnel, including drilling rig crews, may rise as the number of rigs in service increases. The higher prices of oil and gas during the last several years have increased activity which has resulted in shortages of drilling rigs, equipment and personnel, which have resulted in increased costs and delays in the areas where we operate. If drilling rigs, equipment, supplies or qualified personnel are unavailable to us due to excessive costs or demand or otherwise, our ability to execute our exploration and development plans could be materially and adversely affected and, as a result, our financial condition and results of operations could be materially and adversely affected.

 

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

 

The continued threat of terrorism and the impact of military and other government action have led and may lead to further increased volatility in prices for oil and natural gas and could affect these commodity markets or the financial markets used by us. In addition, the U.S. government has issued warnings that energy assets may be a future target of terrorist organizations. These developments have subjected oil and natural gas operations to increased risks. Any future terrorist attack on our facilities, customer facilities, the infrastructure depended upon for transportation of products, and, in some cases, those of other energy companies, could have a material adverse effect on our business.

 

We are exposed to operating hazards and uninsured risks.

 

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

 

· fire, explosions and blowouts;
· negligence of personnel;
· inclement weather;

 

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· pipe or equipment failure;
· abnormally pressured formations; and
· environmental accidents such as oil spills, natural gas environment (including groundwater contamination).

 

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

 

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

 

We maintain insurance against some, but not all, of these risks. Our insurance may not be adequate to cover these losses or liabilities. We do not carry business interruption insurance. Losses and liabilities arising from uninsured or underinsured events may have a material adverse effect on our financial condition and operations.

 

The producing wells in which we have an interest occasionally experience reduced or terminated production. These curtailments can result from mechanical failures, contract terms, pipeline and processing plant interruptions, market conditions, operator priorities, and weather conditions. These curtailments can last from a few days to many months, any of which could have an adverse effect on our results of operations.

 

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

 

In accordance with customary industry practices, we maintain insurance coverage against some, but not all, potential losses in order to protect against the risks faced. We do not carry business interruption insurance. We may elect not to carry insurance if management believes that the cost of available insurance is excessive relative to the risks presented. In addition, we cannot insure fully against pollution and environmental risks. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial condition and results of operations. The impact of natural disasters or weather events in the areas where we operate has resulted in escalating insurance costs and less favorable coverage terms.

 

Oil and natural gas operations are subject to particular hazards incident to the drilling and production of oil and natural gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, natural gas or well fluids, fires and pollution and other environmental risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operation. We do not operate all of the properties in which we hold an interest. In the projects in which we own a non-operating interest directly, the operator for the prospect maintains insurance of various types to cover operations with policy limits and retention liability customary in the industry. We believe the coverage and types of insurance are adequate. The occurrence of a significant adverse event that is not fully covered by insurance could result in the loss of our total investment in a particular prospect which could have a material adverse effect on financial condition and results of operations.

 

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

 

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

 

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

 

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

 

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

 

As of June 15, 2017, we had twenty-four full-time employees and one part-time employee. We leverage the services of independent consultants and contractors to perform various professional services, including engineering, oil and gas well planning and supervision, and land, legal, environmental and tax services. We also pursue alliances with partners in the areas of geological and geophysical services and prospect generation, evaluation and prospect leasing. Our dependence on third-party consultants and service providers creates a number of risks, including but not limited to: 

 

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

 

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

 

Our business may suffer with the loss of key personnel.

 

We depend to a large extent on the services of certain key management personnel, including Abraham Mirman, our Chief Executive Officer and other executive officers and key employees. These individuals have extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties, marketing oil and natural gas production and developing and executing financing and hedging strategies. The loss of any of these individuals could have a material adverse effect on operations. We do not maintain key-man life insurance with respect to any of our employees. Our success will be dependent on our ability to continue to employ and retain skilled technical personnel.

 

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

 

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

 

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

 

· recoverable reserves;
· future oil and natural gas prices and their appropriate differentials;
· well and facility integrity;
· development and operating cost;

 

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· regulatory constraints and plans; and
· potential environmental and other liabilities.

 

The accuracy of these assessments is inherently uncertain.  In connection with these assessments, we perform a review of the subject properties.  Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken.  Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems.  We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.

 

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

 

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

 

The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business.  Members of our senior management and other staff may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business.   If our senior management and staff are not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

 

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

 

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

 

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

 

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

 

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

 

Our producing properties are geographically concentrated in the Delaware Basin in Reeves, Winkler and Loving Counties, West Texas and Lea County, New Mexico. Although these areas are well-established oilfield infrastructures, as a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, adverse weather conditions including natural disasters, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of oil, natural gas or natural gas liquids. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

 

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

 

Our operations and drilling activity are concentrated in the Permian Basin in West Texas, an area in which industry activity has remained relatively steady despite the recent downturn in commodity prices. As a result, demand for qualified personnel in this area, and the cost to attract and retain such personnel, has continued to be competitive, and would be expected to increase substantially in the future if commodity prices rebound. Moreover, our competitors may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer.

 

Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development activities could result in oil and gas production volumes being below our forecasted volumes. In addition, any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our results of operations, liquidity and financial condition.

 

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

 

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

 

Risks Relating to the Oil and Gas Industry

 

Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for oil and natural gas.

 

In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA, under the Clean Air Act, has begun adopting and implementing regulations to restrict emissions of greenhouse gases. 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.

 

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

 

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

 

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

 

The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil, NGLs, and natural gas we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHG in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

 

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells.

 

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production by providing and linking up induced flow paths for the oil and/or gas contained in the rocks. We routinely use hydraulic fracturing techniques in many of our drilling and completion programs. The process is typically regulated by state oil and natural gas commissions, but the EPA, under the federal Safe Drinking Water Act, has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel.

 

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

 

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

 

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

 

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

 

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

 

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

 

Hydraulic fracturing uses large amounts of water. It can require between three to five million gallons of water per horizontal well. We may face regulatory concerns in both the sourcing and the discharge of water used in hydraulic fracturing. In addition, hydraulic fracturing produces water discharges that must be treated and disposed of in accordance with applicable regulatory requirements.

 

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

 

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

 

Future legislation may result in the elimination of certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and production. Additionally, future federal or state legislation may impose new or increased taxes or fees on oil and natural gas extraction.

 

Potential legislation, if enacted into law, could make significant changes to U.S. federal and state income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any other similar changes in U.S. federal and state income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could negatively affect our financial condition and results of operations. Additionally, legislation could be enacted that increases the taxes states impose on oil and natural gas extraction.

 

Moreover, as part of the Budget of the United States Government for Fiscal Year 2017, there was a proposal to impose an “oil fee” of $10.25 on a per barrel equivalent of crude oil. This fee would be collected on domestically produced and imported petroleum products. The fee would be phased in evenly over five years, beginning October 1, 2016. The adoption of this, or similar proposals, could result in increased operating costs and/or reduced consumer demand for petroleum products, which in turn could affect the prices we receive for our oil. Any of these tax changes could have a material impact on our financial performance.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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.

 

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

 

Risks Relating to This Offering

 

If the selling stockholders sell a large number of shares all at once or in blocks, the market price of our shares would most likely decline.

 

The selling stockholders are offering up to 22,865,487 shares of our common stock through this prospectus. Should the selling stockholders decide to sell our shares at a price below the current market price at which they are quoted, such sales will cause that market price to decline. Moreover, we believe that the offer or sale of a large number of shares at any price may cause the market price to fall. A steep decline in the price of our common stock would adversely affect our ability to raise additional equity capital, and even if we were successful in raising such capital, the terms of such raise may be substantially dilutive to current stockholders.

 

If, and when, the shares of common stock underlying the Second Lien Term Loan Conversion and outstanding warrants are issued, our shareholders will experience immediate and substantial dilution in the book value of their investment.

 

As of June 15, 2017, we had 50,419,551 shares of common stock issued and outstanding, before giving effect to this offering. If, and when, the common stock being registered pursuant to this prospectus is issued upon the conversion of our Second Lien Term Loan as described in this offering and upon exercise of any outstanding warrants, the number of shares of our common stock issued and outstanding could increase by as much as 45.4%. Exercise of all or a portion of our other outstanding derivative securities could have a substantial and material dilutive effect on our existing stockholders and on our earnings per share. In addition, sale of such shares of common stock could have a materially adverse impact on the trading price of our common stock.

 

None of the proceeds from the sale of shares of common stock by the selling stockholders in this offering will be available to fund our operations or to pay dividends.

 

We will not receive any proceeds from the sale of shares of common stock by the selling stockholders in this offering. The selling stockholders will receive all proceeds from the sale of such shares. Consequently, none of the proceeds from such sale will be available to fund our operations, capital expenditures or acquisition opportunities or to pay dividends. See “Use of Proceeds” beginning on page 37.

 

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Risks Relating to Our Securities

 

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

 

On May 9, 2017, our common stock was listed on the NYSE MKT and currently trades under the symbol “LLEX.” Trading activity in our common stock generally occurs in small volumes each day. The value of our common stock could be affected by:

 

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

 

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

   

If we are not able to comply with the applicable continued listing requirements or standards of NYSE MKT, NYSE MKT could delist our common stock and our common stock may be deemed a “penny stock,” which would make it more difficult for our investors to sell their shares.

 

Prior February 11, 2016, our common stock traded on The NASDAQ Global Market under the symbol “LLEX,” and from February 11, 2016 to May 26, 2016, our common stock traded on The NASDAQ Capital Market, or the NASDAQ, under the symbol “LLEX.” However, as a result of our inability to comply with the applicable continued listing requirements of NASDAQ, our common stock was delisted. From May 27, 2016 to March 13, 2017, our common stock was quoted on the OTCQB Venture Marketplace under the symbol “LLEX.” On March 14, 2017, our common stock was again listed on the NASDAQ. On May 9, 2017, we transferred our listing from the NASDAQ to the NYSE MKT. In order to maintain that listing, we must satisfy minimum financial and other continued listing requirements and standards, including those regarding director independence and independent committee requirements, minimum stockholders’ equity, minimum share price, and certain corporate governance requirements. There can be no assurances that we will be able to comply with the applicable listing standards.

 

In the event that our common stock is delisted from the NYSE MKT and is not eligible to be listed on another national securities exchange, trading of our common stock could be conducted in the over-the-counter market or on an electronic bulletin board established for unlisted securities such as the Pink Sheets or the OTCQB. In such event, it could become more difficult to dispose of, or obtain accurate price quotations for, our common stock, and there would likely also be a reduction in our coverage by securities analysts and the news media, which could cause the price of our common stock to decline further. Also, it may be difficult for us to raise additional capital if we are not listed on a major exchange.

 

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In addition, unless our common stock is listed on a national securities exchange, such as NYSE MKT, our common stock may be subject to the “penny stock” rules adopted under Section 15(g) of the Exchange Act. Sales and purchases of “penny stock” generally require more disclosures by broker-dealers and satisfaction of other administrative requirements. As a result, broker-dealers may be less willing to execute transactions in securities subject to the “penny stock” rules. This may make it more difficult for investors to dispose of our common stock and cause a decline in the market value of our stock. If we remain subject to the penny stock rules for any significant period, it could have an adverse effect on the market, if any, for our securities, and will find it more difficult to dispose of our securities.

 

If our common stock is not listed on a national securities exchange, compliance with applicable state securities laws may be required for subsequent offers, transfers and sales of the shares of common stock offered hereby.

 

The securities offered hereby are being offered pursuant to one or more exemptions from registration and qualification under applicable state securities laws. Because our common stock is listed on the NYSE MKT, we are not required to register or qualify in any state the subsequent offer, transfer or sale of the common stock. If our common stock is delisted from the NYSE MKT and is not eligible to be listed on another national securities exchange, subsequent transfers of the shares of our common stock offered hereby by U.S. holders may not be exempt from state securities laws. In such event, it will be the responsibility of the holder of shares or warrants to register or qualify the shares for any subsequent offer, transfer or sale in the United States or to determine that any such offer, transfer or sale is exempt under applicable state securities laws.

 

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

 

Our common stock was recently listed to the NYSE MKT on May 9, 2017. Nonetheless, an active or liquid market in our common stock or securities exercisable or convertible for our common stock does not currently exist and might not develop or, if it does develop, it might not be sustainable. If an active trading market for our common stock does not develop, you may not be able to sell all of your shares of common stock on short notice, and the sale of a large number of shares at one time could temporarily depress the market price. There also may be a wide spread between the bid and ask price for our common stock. When there is a wide spread between the bid and ask price, the price at which you may be able to sell our common stock may be significantly lower than the price at which you could buy it at that time. The last reported sale price of our common stock on the NYSE MKT on June 15, 2017 was $5.00 per share. The historic bid and ask quotations for our common stock, however, should not be viewed as an indicator of the current or historical market price for our common stock nor as an indicator of the market price for our common stock if our common stock were to be listed on a national securities exchange. The offering price for our securities as issued by us from time to time is determined through discussions between us and the prospective investor(s), with reference to the most recent closing price of our common stock on the NYSE MKT, and may vary from the market price of our securities following any offering. Further, our trading volume has been generally very limited.

 

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

 

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

 

· our status as a company with a limited operating history and limited revenues to date, which may make risk-averse investors more inclined to sell their shares on the market more quickly and at greater discounts than would be the case with the shares of a seasoned issuer in the event of negative news or lack of progress;
· announcements of technological innovations or new products by us or our existing or future competitors;
· the timing and development of our products;
· general and industry-specific economic conditions;
· actual or anticipated fluctuations in our operating results;
· liquidity;

 

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· 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.

 

Prior to March 14, 2017, our common stock was quoted on the OTCQB, which is often characterized by low trading volume and by wide fluctuations in trading prices due to many factors that may have little to do with our operations or business prospects. The availability of buyers and sellers represented by this volatility historically led to a market price for our common stock that was unrelated to operating performance. While our common stock is now listed on the NYSE MKT, many of these same forces and limitations may still impact our trading volumes and market price in the near term. Additionally, the sale or attempted sale of a large amount of common stock into the market may also have a significant impact on the trading price of our common stock.

 

Many of these factors are beyond our control and may decrease the market price of our common stock, regardless of our operating performance. In the past, securities class action litigation has often been brought against companies that experience high volatility in the market price of their securities. Whether or not meritorious, litigation brought against us could result in substantial costs, divert management’s attention and resources and harm our financial condition and results of operations. 

 

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

 

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

 

Sales of a substantial number of shares of our common stock, or the perception that such sales might occur, could have an adverse effect on the price of our common stock.

 

As of June 15, 2017, 9 investors each hold more than 5% beneficial ownership of our common stock acquirable within 60 days, and together, hold beneficial ownership of approximately 79.9% of our common stock. Thus, any sales by our large investors of a substantial number of shares of our common stock into the public market, or the perception that such sales might occur, could have an adverse effect on the price of our common stock.

 

There may be future dilution of our common stock.

 

We have a significant amount of derivative securities outstanding, which upon exercise or conversion, would result in substantial dilution. For example, in addition to the shares underlying this offering upon the conversion of our Second Lien Term Loan and the exercise of the Heartland Warrant, the exercise of outstanding warrants could result in the issuance of 12,384,831 shares of common stock. To the extent outstanding restricted stock units, warrants or options to purchase our common stock under our employee and director stock option plans are exercised, the price vesting triggers under the performance shares granted to our executive officers are satisfied, or additional shares of restricted stock are issued to our employees, holders of our common stock will experience dilution. Furthermore, if we sell additional equity or convertible debt securities, such sales could result in further dilution to our existing stockholders and cause the price of our outstanding securities to decline.

 

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

 

We have never paid dividends with respect to our common stock, and we do not expect to pay any dividends, in cash or otherwise, in the foreseeable future. We intend to retain any earnings for use in our business. In addition, our Credit Agreement prohibits us from paying any dividends and the indenture governing our senior notes restricts our ability to pay dividends. In the future, we may agree to further restrictions. Any return to shareholders will therefore be limited to the appreciation of their stock.

 

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

 

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

   

The issuance and sale of common stock upon conversion of the Second Lien Term Loan and the exercise of warrants received in those transactions, may depress the market price of our common stock.

 

If the Second Lien Term Loan is converted, outstanding warrants are exercised, and sales of such securities take place, the price of our common stock may decline. In addition, the common stock issuable upon conversion of such securities may represent overhang that may also adversely affect the market price of our common stock. Overhang occurs when there is a greater supply of a company’s stock in the market than there is demand for that stock. When this happens the price of our company’s stock will decrease, and any additional shares which shareholders attempt to sell in the market will only further decrease the share price. If the share volume of our common stock cannot absorb converted shares sold by the former Series B preferred stock holders, then the value of our common stock will likely decrease.

 

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

 

Though not now, in the future we may become subject to Nevada’s control share law. A corporation is subject to Nevada’s control share law if it has more than 200 stockholders, at least 100 of whom are stockholders of record and residents of Nevada, and it does business in Nevada or through an affiliated corporation. The law focuses on the acquisition of a “controlling interest” which means the ownership of outstanding voting shares sufficient, but for the control share law, to enable the acquiring person to exercise the following proportions of the voting power of the corporation in the election of directors: (i) one-fifth or more but less than one-third, (ii) one-third or more but less than a majority, or (iii) a majority or more. The ability to exercise such voting power may be direct or indirect, as well as individual or in association with others.

 

The effect of the control share law is that the acquiring person, and those acting in association with it, obtains only such voting rights in the control shares as are conferred by a resolution of the stockholders of the corporation, approved at a special or annual meeting of stockholders. The control share law contemplates that voting rights will be considered only once by the other stockholders. Thus, there is no authority to strip voting rights from the control shares of an acquiring person once those rights have been approved. If the stockholders do not grant voting rights to the control shares acquired by an acquiring person, those shares do not become permanent non-voting shares. The acquiring person is free to sell its shares to others. If the buyers of those shares themselves do not acquire a controlling interest, their shares do not become governed by the control share law. If control shares are accorded full voting rights and the acquiring person has acquired control shares with a majority or more of the voting power, any stockholder of record, other than an acquiring person, who has not voted in favor of approval of voting rights is entitled to demand fair value for such stockholder’s shares. Nevada’s control share law may have the effect of discouraging takeovers of the corporation.

 

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In addition to the control share law, Nevada has a business combination law which prohibits certain business combinations between Nevada corporations and “interested stockholders” for three years after the “interested stockholder” first becomes an “interested stockholder,” unless the corporation’s board of directors approves the combination in advance. For purposes of Nevada law, an “interested stockholder” is any person who is (i) the beneficial owner, directly or indirectly, of ten percent or more of the voting power of the outstanding voting shares of the corporation, or (ii) an affiliate or associate of the corporation and at any time within the three previous years was the beneficial owner, directly or indirectly, of ten percent or more of the voting power of the then outstanding shares of the corporation. The definition of the term “business combination” is sufficiently broad to cover virtually any kind of transaction that would allow a potential acquirer to use the corporation’s assets to finance the acquisition or otherwise to benefit its own interests rather than the interests of the corporation and its other stockholders. The effect of Nevada’s business combination law is to potentially discourage parties interested in taking control of our company from doing so if it cannot obtain the approval of our Board of Directors. 

 

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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

 

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

 

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

 

Although we believe that the expectations reflected in any of our forward-looking statements are reasonable, actual results could differ materially from those projected or assumed in any of our forward-looking statements. Our future financial condition and results of operations, as well as any forward-looking statements, are subject inherent risks and uncertainties. The factors impacting these risks and uncertainties include, but are not limited to, the Risk Factors set forth in this prospectus beginning on page 5 and the following factors:

 

· our estimates regarding operating results, future revenues and capital requirements;
· our ability to successfully integrate our acquisition of Brushy Resources, Inc. and realize anticipated benefits from such acquisition;
· availability of capital on an economic basis, or at all, to fund our continuing capital or operating needs;
· our level of debt, which could adversely affect our ability to raise additional capital, limit our ability to react to economic changes and make it more difficult to meet our obligations under our debt;
· restrictions imposed on us under our credit agreements or other debt instruments that limit our discretion in operating our business;
· potential default under our material debt agreements;
· failure to meet requirements or covenants under our debt instruments, which could lead to foreclosure of significant core assets;
· failure to fund our authorization for expenditures from other operators for key projects which will reduce or eliminate our interest in the wells/asset;
· the inability of management to effectively implement our strategies and business plans;
· estimated quantities and quality of oil and natural gas reserves;
· exploration, exploitation and development results;
· fluctuations in the price of oil and natural gas, including further reductions in prices that would adversely affect our revenue, cash flow, liquidity and access to capital;
· availability of, or delays related to, drilling, completion and production, personnel, supplies (including water) and equipment;
· the timing and amount of future production of oil and natural gas;
· the timing and success of our drilling and completion activity;
· lower oil and natural gas prices negatively affecting our ability to borrow or raise capital, or enter into joint venture arrangements;
· declines in the values of our natural gas and oil properties resulting in further write-down or impairments;
· inability to hire or retain sufficient qualified operating field personnel;
· our ability to successfully identify and consummate acquisition transactions;
· our ability to successfully integrate acquired assets or dispose of non-core assets;
· the occurrence of natural disasters, unforeseen weather conditions, or other events or circumstances that could impact our operations or could impact the operations of companies or contractors we depend upon in our operations;
· inability to successfully develop our large inventory of undeveloped acreage we currently hold on a timely basis;

 

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· constraints, interruptions or other issues affecting the Delaware Basin, including with respect to transportation, marketing, processing, curtailment of production, natural disasters, and adverse weather conditions;
· deterioration in general or regional economic conditions;
· inability to acquire or maintain mineral leases at a favorable economic value that will allow us to expand our development efforts;
· technical risks inherent in drilling in existing or emerging unconventional shale plays using horizontal drilling and complex completion techniques;
· delays, denials or other problems relating to our receipt of operational consents, approvals and permits from governmental entities and other parties;
· unanticipated recovery or production problems, including cratering, explosions, blow-outs, fires and uncontrollable flows of oil, natural gas or well fluids;
· loss of senior management or technical personnel;
· litigation and the outcome of other contingencies, including legal proceedings;
· adverse state or federal legislation or regulation that increases the costs of compliance, or adverse findings by a regulator with respect to existing operations, including those related to climate change and hydraulic fracturing;
· anticipated trends in our business;
· effectiveness of our disclosure controls and procedures and internal controls over financial reporting; and
· changes in generally accepted accounting principles in the United States or in the legal, regulatory and legislative environments in the markets in which we operate.

 

We caution you that the forward-looking statements highlighted above do not encompass all of the forward-looking statements made in this prospectus.

 

You should read this prospectus and the documents that we reference elsewhere in this prospectus and have filed as exhibits to the registration statement, of which this prospectus is a part, completely and with the understanding that our actual results may differ materially from what we expect as expressed or implied by our forward-looking statements. In light of the significant risks and uncertainties to which our forward-looking statements are subject, you should not place undue reliance on or regard these statements as a representation or warranty by us or any other person that we will achieve our objectives and plans in any specified timeframe, or at all. We discuss many of these risks and uncertainties in greater detail under the section entitled “Risk Factors” and elsewhere in this prospectus. These forward-looking statements represent our estimates and assumptions only as of the date of this prospectus regardless of the time of delivery of this prospectus or any sale of our securities. Except as required by law, we undertake no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise after the date of this prospectus. 

 

  36  

 

 

USE OF PROCEEDS

 

The proceeds from the sale of the shares offered pursuant to this prospectus are solely for the accounts of the selling stockholders. Accordingly, we will not receive any of the proceeds from the sale of shares offered by this prospectus. See “Selling Stockholders” and “Plan of Distribution” below, beginning on pages 38 and 39, respectively.

 

We will however, receive proceeds upon the exercise of the Heartland Warrant, which shares of common stock underlying such warrant are being registered in the registration statement of which this prospectus forms a part, provided that such securities are exercised for cash. If exercised, we plan to use the proceeds from the exercise of such warrant for working capital and general corporate purposes. If the Heartland Warrant is exercised in full, and assuming it is not exercised using a cashless exercise procedure (which is not available once the warrant is registered pursuant to an effective registration statement under the Securities Act), this would result in an aggregate of approximately $485,000 in possible funding. However, the timing and manner of use of the net proceeds may vary, depending on the amount of actual proceeds received from the exercise of the Heartland Warrant, if any, the timing of the receipt of such proceeds, our rate of growth and other factors. The foregoing represents our best estimate of our use of the net proceeds of the offering based on current planning and business conditions. We reserve the right to change our use of proceeds when and if market conditions or unexpected changes in operating conditions or results occur, or in our management’s discretion. Pending the use of the net proceeds from the cash exercise of the Heartland Warrant as described above, we intend to invest the proceeds in investment grade, interest-bearing instruments. Additionally, we can provide no assurances that the Heartland Warrant, or any portion thereof, will be exercised in the future, or that such exercise, subject to the terms of the warrant, will be in cash. To the extent that any shares of common stock issuable upon exercise of the Heartland Warrant are not registered under an effective registration statement under the Securities Act, such unregistered warrant or portion thereof are exercisable on a cashless basis pursuant to the terms of the warrant.

 

The selling stockholders will pay any underwriting discounts and commissions and expenses incurred by the selling stockholders for brokerage, accounting, tax or legal services or any other expenses incurred by the selling stockholders in disposing of the shares. We will bear all other costs, fees, and expenses incurred in effecting the registration of the shares covered by this prospectus, including, without limitation, all registration and filing fees, exchange listing fees (if any), and fees and expenses of our counsel and our accountants.

 

  37  

 

 

SELLING STOCKHOLDERS

 

The shares of common stock being offered by the selling stockholders are those issuable to the selling stockholders upon conversion of the Second Lien Term Loan and exercise of the Heartland Warrant. For additional information regarding the convertible term debt, the Heartland Warrant, and certain rights of the selling stockholders with respect thereto, see “Recent Sales of Unregistered Securities” and “Description of Capital Stock” below. We are registering the shares of common stock in order to permit the selling stockholders to offer the shares for resale from time to time. Except as disclosed in this prospectus and except for certain ownership of the Company’s securities, the selling stockholders have not had any material relationship with us within the past three years.

 

The table below lists the selling stockholders and other information regarding the beneficial ownership of the shares of common stock by the selling stockholders. The second column lists the number of shares of common stock beneficially owned by the selling stockholders prior to this offering. The third column lists the shares of common stock being offered by this prospectus by the selling stockholders, which is comprised of the shares of common stock issuable upon conversion of the convertible term debt held by the selling stockholder. The fourth and fifth column list the number and percentage, respectively, of shares of common stock beneficially owned by the selling stockholders after the completion of the offering, based on their respective ownership as of June 15, 2017, based on 73,285,038 shares of common stock outstanding as of June 15, 2017, and assuming the sale of all of the shares offered by the selling stockholders pursuant to this prospectus.

 

Name of Selling Stockholder   Number of
Shares
Beneficially
Owned Prior
to Offering(1)
    Maximum
Number of
Shares to be
Sold
Pursuant to
this
Prospectus(2)
    Number of
Shares
Beneficially
Owned
After
Offering(3)
    Percentage of
Shares
Beneficially
Owned After
Offering(3)
 

The Vӓrde Fund XI (Master), L.P. (4)

901 Marquette Avenue South

Minneapolis, MN 55402

    9,454,545       9,454,545       -       -  
The Värde Fund XII (Master), L.P. (4)                                
901 Marquette Avenue South                                
Minneapolis, MN 55402     6,727,272       6,727,272       -       -  
The Värde Skyway Master Fund, L.P. (4)                                
901 Marquette Avenue South                                
Minneapolis, MN 55402     2,954,545       2,954,545       -       -  
The Värde Fund VI-A, L.P. (4)                                
901 Marquette Avenue South                                
Minneapolis, MN 55402     681,818       681,818       -       -  
Värde Investment Partners, L.P. (4)                                
901 Marquette Avenue South                                
Minneapolis, MN 55402     1,545,454       1,545,454       -       -  
Värde Investment Partners (Offshore) Master, L.P. (4)                                
901 Marquette Avenue South                                
Minneapolis, MN 55402     1,363,636       1,363,636       -       -  
Heartland Bank (5)                                  
One Information Way,                                  

Suite 300

Little Rock, AR 72202

    160,714       138,214       22,500       -    

 

(1) The number of shares of common stock owned are those “beneficially owned” as determined under the rules of the SEC, including any shares of common stock as to which the selling stockholder has sole or shared voting or investment power and any shares of common stock that the selling stockholder has the right to acquire within 60 days of June 15, 2017 through the exercise of any option, warrant, or right, without giving effect to any prohibitions on such conversion or exercise subject to the receipt of stockholder approval or any beneficial ownership limitations.

 

(2) With respect to the shares that may be deemed to be beneficially owned by the named selling stockholders ultimately controlled by Värde Partners, Inc., this represents each selling stockholder’s pro rata portion of 22,727,273 shares of common stock which may be issued upon the conversion of the Second Lien Term Loan being registered in the registration statement of which this prospectus forms a part. This includes shares which may be issued in excess of the beneficial ownership limitation of 19.9% of the Company’s outstanding shares of Common Stock (which limitation will no longer apply after the receipt of requisite stockholder approval),as well as an estimate of the maximum number of shares which may be issued pursuant to the make-whole premium and accrued and unpaid interest. The actual amount of shares issuable upon conversion of the Second Lien Term Loan will vary depending upon the date of conversion. With respect to Heartland Bank, this represents 138,214 shares of common stock issuable upon the exercise of warrants. Such warrants do not have any beneficial ownership limitation and are exercisable.

 

(3) The “Number of Shares Beneficially Owned After Offering” assumes the sale of all of the shares offered by the selling stockholders pursuant to this prospectus. The “Percentage of Shares Beneficially Owned After Offering” are based on 73,285,038 shares of common stock outstanding assuming all shares registered herein are issued to the selling stockholder and sold and assuming all the stockholders convert their loans, or the exercise of their warrants, as applicable.

 

(4)

 

Värde Partners, Inc. is the ultimate owner of the general partners (the “General Partners”) of each of the selling stockholders named above, 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 selling stockholders. Each of Värde Partners, Inc. and Mr. Hicks disclaims beneficial ownership of the securities held indirectly through the selling stockholders named herein 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 Registration Statement or for any other purpose.

  

(5) This represents 138,214 shares of common stock underlying warrants. The natural person with ultimate voting or investment control over the shares of common stock held is Judy Lawton.

  

  38  

 

  

PLAN OF DISTRIBUTION

 

We are registering for resale by the selling stockholders from time to time after the date of this prospectus a total of 22,865,487 shares of common stock underlying the Second Lien Term Loan and exercise of the Heartland Warrant. We will not receive any of the proceeds from the sale by the selling stockholders of the shares of common stock. We may, however, receive proceeds from certain warrants exercised by selling stockholders in the event that such warrants are exercised for cash. See “Use of Proceeds” beginning on page 37 of this prospectus. We will bear all fees and expenses incident to our obligation to register the shares of common stock.

 

The selling stockholders and any of their pledgees, assignees and successors-in-interest may, from time to time, sell any or all of their shares of common stock registered hereby in the over-the-counter market or other national securities exchange or automated interdealer quotation system on which our common stock is then listed or quoted, or through one or more underwriters, broker-dealers or agents. If the shares of common stock are sold through underwriters or broker-dealers, the selling stockholders will be responsible for underwriting discounts or commissions or agent’s commissions. The shares of common stock may be sold in one or more transactions at fixed prices, at prevailing market prices at the time of the sale, at varying prices determined at the time of sale, or at negotiated prices. The selling stockholders may use any one or more of the following methods when selling their shares of common stock:

 

· ordinary brokerage transactions and transactions in which the broker-dealer solicits purchasers;

 

· block trades in which the broker-dealer will attempt to sell the shares of common stock as agent but may position and resell a portion of the block as principal to facilitate the transaction;

 

· purchases by a broker-dealer as principal and resale by the broker-dealer for its account;

 

· an exchange distribution in accordance with the rules of the applicable exchange;

 

· privately negotiated transactions;

 

· settlement of short sales;

 

· in transactions through broker-dealers that agree with the selling stockholders to sell a specified number of such shares of common stock at a stipulated price per share;

 

· through the writing or settlement of options or other hedging transactions, whether through an options exchange or otherwise;

 

· a combination of any such methods of sale; or

 

· any other method permitted pursuant to applicable law.

 

The selling stockholders may also sell the shares of common stock under Rule 144 under the Securities Act, if available, rather than under this prospectus.

 

Broker-dealers engaged by the selling stockholders may arrange for other brokers-dealers to participate in sales. Broker-dealers may receive commissions or discounts from the selling stockholders (or, if any broker-dealer acts as agent for the purchaser of the shares of common stock, from the purchaser) in amounts to be negotiated, but, except as set forth in a supplement to this prospectus, in the case of an agency transaction not in excess of a customary brokerage commission in compliance with FINRA Rule 2121; and in the case of a principal transaction a markup or markdown in compliance with FINRA Rule 2121.

 

  39  

 

  

In connection with the sale of the shares of common stock or interests therein, the selling stockholders may enter into hedging transactions with broker-dealers or other financial institutions, which may in turn engage in short sales of the shares of common stock in the course of hedging the positions they assume. The selling stockholders may also sell the shares of common stock short and deliver these shares of common stock to close out its short positions, or loan or pledge the shares of common stock to broker-dealers that in turn may sell these shares of common stock. The selling stockholders may also enter into option or other transactions with broker-dealers or other financial institutions or create one or more derivative securities which require the delivery to such broker-dealer or other financial institution of the shares of common stock offered by this prospectus, which shares such broker-dealer or other financial institution may resell pursuant to this prospectus (as supplemented or amended to reflect such transaction).

 

The selling stockholders and any broker-dealers or agents that are involved in selling the shares of common stock may be deemed to be “underwriters” within the meaning of the Securities Act in connection with such sales. In such event, any commissions received by such broker-dealers or agents and any profit on the resale of the shares of common stock purchased by them may be deemed to be underwriting commissions or discounts under the Securities Act. The selling stockholders has informed us that it does not have any written or oral agreement or understanding, directly or indirectly, with any person to distribute the shares of common stock.

 

We are required to pay certain fees and expenses incurred by us incident to the registration of the shares of common stock. We have agreed to indemnify the selling stockholders against certain losses, claims, damages and liabilities, including liabilities under the Securities Act.

 

We agreed to keep this prospectus effective until the earlier of (i) the date on which the shares of common stock may be resold by the selling stockholders without registration and without regard to any volume or manner-of-sale limitations by reason of Rule 144, without the requirement for us to be in compliance with the current public information under Rule 144 under the Securities Act or any other rule of similar effect or (ii) all of the shares of common stock have been sold pursuant to this prospectus or Rule 144 under the Securities Act or any other rule of similar effect. The shares of common stock will be sold only through registered or licensed brokers or dealers if required under applicable state securities laws. In addition, in certain states, the shares of common stock covered hereby may not be sold unless they have been registered or qualified for sale in the applicable state or an exemption from the registration or qualification requirement is available and is complied with.

 

Under applicable rules and regulations under the Exchange Act, any person engaged in the distribution of the resale securities may not simultaneously engage in market making activities with respect to the common stock for the applicable restricted period, as defined in Regulation M, prior to the commencement of the distribution. In addition, the selling stockholders will be subject to applicable provisions of the Exchange Act and the rules and regulations thereunder, including Regulation M, which may limit the timing of purchases and sales of the common stock by the selling stockholders or any other person. We will make copies of this prospectus available to the selling stockholders and have informed the selling stockholders of the need to deliver a copy of this prospectus to each purchaser at or prior to the time of the sale (including by compliance with Rule 172 under the Securities Act).

 

  40  

 

 

DIVIDEND POLICY

 

We have never paid any cash dividends on our common stock and do not anticipate paying any dividends in the foreseeable future. Our current business plan is to retain any future earnings to finance the expansion and development of our business. Any future determination to pay cash dividends will be at the discretion of our Board of Directors, and will be dependent upon our financial condition, results of operations, capital requirements and other factors as our board may deem relevant at that time. In addition, we are currently restricted from declaring any dividends pursuant to the terms of our preferred stock and our instruments evidencing indebtedness.

 

  41  

 

 

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

The following discussion and analysis of our results of operations and financial condition should be read in conjunction with our financial statements and the notes to those financial statements that are included elsewhere in this prospectus. This discussion contains forward-looking statements, such as our plans, objectives, expectations and intentions, that are based upon current expectations that involve risks and uncertainties. Actual results and the timing of events could differ materially from those anticipated in these forward-looking statements as a result of a number of factors, including those set forth under the “Prospectus Summary,” “Risk Factors” and “Business” sections and elsewhere in this prospectus.

 

General 

 

We are an upstream independent oil and gas company engaged in the acquisition, drilling and production of oil and natural gas properties and prospects. Our primary focus is drilling horizontal wells in the Delaware Basin of West Texas, which we believe will provide attractive returns on a majority of our acreage positions. Our goal is to earn economic returns to our shareholders through cash flow from new production of oil, natural gas and NGLs, as well as through derisking the development profile of our portfolio of properties in order to add overall value. Our drilling program utilizes the development of new horizontal wells across several potentially productive formations in the Delaware Basin but initially targeting the Wolfcamp formation. We drilled our first horizontal well in late 2016 and completed it in January 2017.

 

On June 23, 2016, we completed a merger transaction with Brushy. The merger resulted in the acquisition of our properties in the Delaware Basin as well as the majority of our current operating activity. This contiguous acreage position is offset by RSP Permian, Inc., Matador Resources Company, Devon Energy Corporation, Royal Dutch Shell PLC, Anadarko Petroleum Corp., and XTO Energy Inc., among other operators. Since entering the Delaware Basin in June 2016, we have grown our acreage position 186% from approximately 3,500 net acres to over 10,000 net acres primarily in our Delaware Basin-Core area.

 

On March 31, 2017, we completed the divestiture of all of our oil and gas properties located in the DJ Basin, for a gross purchase price of $2 million, which completed our transformation to a pure play Permian Basin company.

 

Overview of Our Business and Strategy

 

We are an oil and natural gas company, engaged in the acquisition, development and production of unconventional oil and natural gas properties. We have accumulated over 10,000 net acres in what we believe to be the core of the Delaware Basin in Reeves, Winkler and Loving Counties, Texas and Lea County, New Mexico. Our leasehold position is largely contiguous, allowing us to maximize development efficiency, manage full cycle finding costs and potentially enabling us to generate higher returns for our shareholders. In addition, 48% of our acreage position is held by production, and we are the named operator on 100% of our producing acreage. These two characteristics give us control over the pace of development and the ability to design a more efficient and profitable drilling program that maximizes recovery of hydrocarbons. We expect that substantially all of our estimated 2017 capital expenditure budget will be focused on the development and expansion of our Delaware Basin acreage and operations. We also plan to continue to selectively and opportunistically pursue strategic bolt-on acreage acquisitions in the Delaware Basin.

 

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

 

  42  

 

  

Our Board has approved a drilling program of up to 11 gross Delaware Basin wells (9 net) that is contingent upon our access to sufficient capital to fully execute. During the first quarter of 2017, we completed two wells. We completed a third well in April of 2017, and we expect to complete a fourth well in June of 2017. Additionally, drilling operations have begun on a fifth well.  We expect our 2017 horizontal drilling program will be focused almost exclusively on the Wolfcamp zone of the Delaware Basin, with lateral lengths ranging from approximately 4,000’ laterals to 7,000’ laterals. 

 

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

 

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

 

Liquidity

 

We have reported a net operating loss during the quarter ended March 31, 2017 and for the past five years. As a result, we funded our operations in 2016 and the merger with Brushy Resources, Inc. through additional debt and equity financing. On September 29, 2016, we entered into a new First Lien Credit Agreement that provided for a three-year, senior, secured term loan with initial aggregate principal commitments of $31 million and a maximum facility size of $50 million. The initial commitment on the term loan was funded with $25 million collected as of September 30, 2016 and the additional $6 million collected as of November 11, 2016. Additionally, we funded our operations during the quarter ended March 31, 2017 through additional debt and equity financing. On February 7, 2017, we completed a drawdown of an incremental $7.1 million under our First Lien Credit Agreement , and on March 1, 2017, we completed a private placement of approximately 5.6 million shares of common stock and approximately 2.6 million warrants that raised gross and net proceeds of $20 million and approximately $18.7 million, respectively. Net proceeds of $17.9 million were received in March 2017 and $0.6 million in subscription receivable  were received in May 2017. The warrants carry a strike price of $4.50 per share and expire on March 6, 2022.

 

As of March 31, 2017, we had a working capital balance and a cash balance of approximately $15.2 million and $20.4 million, respectively. As of December 31, 2016, the Company had a working capital balance and a cash balance of approximately $5.7 million and $11.5 million, respectively. Subsequent to March 31, 2017, we closed on a new Second Lien Credit Facility, including a delayed-draw Second Lien Term Loan providing for an additional $45 million in capacity on a discretionary basis for leasing and acquisition activity. We also refinanced our $38.1 million in principal under our existing First Lien Term Loan, paid accrued and unpaid interest thereon, redeemed and converted preferred stock and enhanced our cash position. As of June 15, 2017, we had (i) $15 million in aggregate principal amount outstanding on our First Lien Term Loan, (ii) $80 million in aggregate principal amount outstanding on our Second Lien Term Loan with an additional $45 million available on a discretionary basis, and (iii) a cash balance of approximately $46 million. We believe that we will have sufficient capital to operate over the next 12 months. However, it is possible that we could seek to raise additional debt and equity capital depending on the pace of our drilling and leasing activity.

 

Amendments to First Lien Credit Facility and Second Lien Credit Facility

 

On April 24, 2017, and subsequently on April 26, 2017, we entered into two amendments to our existing credit agreement and into a new four-year, convertible, second lien term loan credit facility. Under the amendments to our existing credit facility, among other things, we received approximately $14.6 million in net proceeds from a new, $15 million, 18-month, first lien term loan (“Bridge Loan”). On April 26, 2017, we entered into a new, $125 million, convertible, second lien term loan facility earning paid-in-kind interest (“Second Lien Credit Facility”). The Second Lien Credit Facility was structured as an $80 million, four-year term loan that funded at closing, and a $45 million, delayed-draw term loan that may be used to fund acreage leasing activity and acquisitions under certain conditions. We received approximately $56.6 million in combined net proceeds from Bridge Loan and the Second Lien Credit Facility, following repayment of $38.3 million outstanding including accrued interest under the existing first lien term loan, which was subsequently cancelled.

 

The structure of the delayed-draw term loan, which may be drawn in multiple draws, is otherwise identical to the $80 million term loan that funded at closing. The conversion price under both second lien term loans is set at $5.50 per share, subject to adjustment under a conversion formula and customary anti-dilution provisions. At conversion, 70% of the total conversion amount, including a make whole payment, will convert to equity, and 30% will convert into a three-year term loan earning cash interest.

 

  43  

 

 

The First and Second Lien Credit Facilities contain certain customary representations and warranties and affirmative and negative covenants, including covenants relating to: the maintenance of books and records, financial reporting and notification, compliance with laws, maintenance of properties and insurance, limitations on incurrence of indebtedness, investments, dividends and other restricted payments, lease obligations, hedging and capital expenditures; and maintenance of a specified asset coverage ratio, as applicable. Each of the First and Second Lien Credit Facility also provides for events of default, including failure to pay any principal or interest when due, failure to perform or observe covenants, cross-default on certain outstanding debt obligations, the failure of a Guarantor to comply with the provisions of its Guaranty, and bankruptcy or insolvency events, subject to certain specified cure periods. The amounts under each of the First and Second Lien Credit Agreement could be accelerated and become due and payable upon an event of default.

 

The terms and conditions of each of the First and Second Lien Credit Facilities are more fully described in Note 13—Subsequent Events   in the notes to the unaudited consolidated financial statements of Lilis Energy. Inc. for the quarter ended March 31, 2017.

  

Redemption of Conditionally Redeemable 6% Preferred Stock

 

Effective as of April 24, 2017, we redeemed, in full, our 6% Redeemable Preferred Stock for cash consideration of $2.0 million, including accumulated dividends of $0.3 million. In accordance therewith, and Hexagon, the only holder of the 6% Redeemable Preferred Stock, entered into a Settlement and Release Agreement, dated April 24, 2017 (the “Settlement Agreement”), which sets forth the terms of the redemption. In addition, the Settlement Agreement resolves certain other issues related to liability reimbursements on certain oil and gas properties that had previously been alleged by Hexagon. Accordingly, all prior issues with Hexagon have been resolved and the 6% Redeemable Preferred Stock has been redeemed in full.

 

Series B 6% Convertible Preferred Stock Conversion

 

On April 25, 2017, we and all of the holders of our Series B 6% Preferred Stock (the “Series B Holders”) agreed to adopt the A&R COD in order to remove certain restrictions contained therein with respect to beneficial ownership limitations. On the same date, we entered into a Series B 6.0% Convertible Preferred Stock Conversion Agreement (the “Conversion Agreement”), of our outstanding Series B 6% Convertible Preferred Stock.

 

Pursuant to the terms of the Conversion Agreement, we and the Series B Holders have mutually agreed that, immediately upon the effectiveness of the A&R COD, the Series B Holders will be deemed to have automatically converted all remaining shares of Series B Preferred Stock held by them into approximately 14.3 million shares of common stock, pursuant to the terms of the A&R COD, such amount representing the number of shares of Common Stock into which the outstanding shares of Series B Preferred Stock held by the Series B Holders would be convertible pursuant to the terms of the A&R COD, with such Conversion including an increase in the stated value of the Series B Preferred Stock to reflect dividends that would have accrued through December 31, 2017.

 

The Conversion Agreement contains customary representations and warranties by the Series B Holders and other agreements and obligations of the parties.

 

Drilling Program

 

Our Board has approved a drilling program of up to 11 gross Delaware Basin wells (9 net) that is contingent upon our access to sufficient capital to fully execute. During the first quarter of 2017, we completed two wells. We completed a third well in April of 2017. and we expect to complete a fourth well in June of 2017. Additionally, drilling operations have begun on a fifth well.  We expect our 2017 horizontal drilling program will be focused almost exclusively on the Wolfcamp zone of the Delaware Basin, with lateral lengths ranging from approximately 4,000’ laterals to 7,000’ laterals.

 

Results of Operations

 

Results of operations for the three months ended March 31, 2017 compared to the three months ended March 31, 2016

 

The following table compares revenues for the three months ended March 31, 2017 and 2016 (in thousands):

 

    Three Months Ended March 31,        
    2017   2016   Variance   %
    (In Thousands)        
Revenue:                                
Oil   $ 2,496     $ 36     $ 2,460       6,833 %
Natural gas     587       3       584       19,467 %
Other     150       3       147       4,900 %
    $ 3,233     $ 42     $ 3,191       7,598 %

 

  44  

 

 

Total Revenue

 

Total revenue was approximately $3.2 million for the three months ended March 31, 2017 as compared to approximately $0.04 million for the three months ended March 31, 2016, representing an increase of approximately $3.2 million or 7,598%. The changes were associated primarily with increase in production from the Delaware Basin wells. These producing properties were acquired from the merger with Brushy Resources, Inc. in June 2016.

 

The following table compares production volumes and average prices for the three months ended March 31, 2017 and 2016:

 

    Three Months Ended March 31,              
    2017     2016     Variance     %  
Product                        
Oil (Bbl.) net production     51,491       1,371       50,120       3,656 %
Oil (Bbls)-average realized price   $ 48.47     $ 26.43     $ 22.04       83 %
                                 
Natural Gas (Mcf)-net production     197,057       2,432       194,625       8,003 %
Natural Gas (MCFE)-average realized price   $ 2.98     $ 1.27     $ 1.71       135 %
                                 
Barrels of oil equivalent (BOE)     84,334       1,776       82,558       4,649 %
Average daily net production (BOE/D)     937       20       917       4,585 %
Average Price per BOE   $ 36.56     $ 22.14     $ 14.42       65 %

 

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

 

The following table shows a comparison of production volumes and average prices:

 

    Three Months Ended March 31,  
    2017     2016  
Production costs per BOE   $ 11.02     $ 20.96  
Production taxes per BOE     1.68       1.08  
Depreciation, depletion, and amortization per BOE     13.33       12.89  
Total operating costs per BOE   $ 26.03     $ 34.93  
Gross margin per BOE   $ 10.53     $ (12.79 )
Gross margin percentage     29 %     -58 %

 

    Three Months Ended March 31,              
    2017     2016     Variance     %  
    (In Thousands)              
Costs and expenses:                                
Production costs   $ 929     $ 37     $ 892       2,411 %
Production taxes     142       2       140       7,000 %
General and administrative     9,311       1,664       7,647       460 %
Depreciation, depletion and amortization     1,124       20       1,104       5,520 %
Accretion of asset retirement obligations     22       3       19       633 %
Total operating expenses   $ 11,528     $ 1,726     $ 9,802       568 %
                                 
Loss from operation   $ (8,295 )   $ (1,684 )   $ (6,611 )     393 %

  

Production Costs

 

Production costs were approximately $0.9 million for the three months ended March 31, 2017, compared to approximately $0.04 million for the three months ended March 31, 2016, an increase of approximately $0.9 million, or 2,411%. Production costs per BOE decreased to $11.02 for the three months ended March 31, 2017 from $20.96 for the three months ended March 31, 2016, a decrease of $9.94 per BOE, or 47%. Despite the increase in production volumes for the three months ended March 31, 2017, the decrease in production costs per BOE was primarily due to costs associated with the producing wells in the Delaware basin which have significantly lower per unit operating costs than the DJ Basin.

 

Production Taxes

 

Production taxes were approximately $0.1 million for the three months ended March 31, 2017, compared to approximately $0.002 million for the three months ended March 31, 2016, an increase of approximately $0.1 million, or 7,000%.  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 $1.68 per BOE during the three months ended March 31, 2017 from $1.08 during the three months ended March 31, 2016.

 

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General and Administrative Expenses

 

General and administrative expenses were approximately $9.3 million during the three months ended March 31, 2017, compared to approximately $1.7 million during the three months ended March 31, 2016, an increase of approximately $7.6 million, or 460%.  The increase of $7.6 million is primarily attributed to the increase in payroll of approximately $4.5 million, approximately $2.4 million increase in stock compensation and approximately $0.7 million increase in other general and administrative expenses during the three months ended March 31, 2017. For the three months ended March 31, 2017, the Company had a total of twenty-two fulltime employees compared to only four fulltime employees for the three months ended March 31, 2016. The increase in employees contributed significantly to the change in payroll during the three months ended March 31, 2017. The increase in payroll of $4.5 million included approximately $1.1 million of recurring quarterly base payroll, approximately $2.0 million in bonus payments, approximately $0.8 million in severance pay to former executives and approximately $0.6 million in payroll taxes and other benefits.

 

Depreciation, Depletion, and Amortization

 

Depreciation, depletion, and amortization (DD&A) was approximately $1.1 million during the three months ended March 31, 2017, compared to $0.02 million during the three months ended March 31, 2016, an increase of $1.1 million, or 5,520%. The increase in DD&A was the result of the increase in production associated with the acquisition of the oil and gas properties in the Delaware Basin, New Mexico and Winkler County, Texas after the merger with Brushy in June 2016. As a result of the merger, our DD&A rate increased to $13.33 per BOE during the three months ended March 31, 2017 from $12.89 per BOE during the three months ended March 31, 2016. The DD&A expense increased primarily due to an increase in volumes produced of 82,558 barrels or 4,649% from 1,776 barrels during the three months ended March 31, 2016.

 

    Three Months Ended
March 31,
             
    2017     2016     Variance     %  
    (In Thousands)              
Other income (expense):                                
Other income (expense)   $ 8     $ (1 )   $ 9       900 %
Gain (loss) in fair value of derivative instruments     346       (68 )     414       609 %
Loss in fair value of conditionally redeemable 6% preferred stock     (41 )     (324 )     283       87 %
Interest expense     (774 )     (1,334 )     560       42 %
Total other income (expense)   $ (461 )   $ (1,727 )   $ 1,266       73 %

 

Interest Expense

 

Interest expense for the three months ended March 31, 2017 was approximately $0.8 million compared to $1.3 million, for the three months ended March 31, 2016. The decrease in interest expense of $0.5 million is due to the Company paying interest at the rate of 6% per annum on both the term loan and the SOS note during the three months ended March 31, 2017 compared to the Company paying interest at the rates of 8% and 12% on the convertible notes and convertible debentures, respectively, during the three months ended March 31, 2016. The non-cash interest expense consisting of amortization deferred financing costs and accretion of debt discounts during the three months ended March 31, 2017 and 2016 was approximately $0.2 million and $0.8 million, respectively.

 

Change in Fair Value of Derivative Instruments

 

The change in fair values of derivative instruments comprised a gain of approximately $0.3 million   during the three months ended March 31, 2017, as compared to a loss of approximately $0.07 million during the three months ended March 31, 2016, is as follows:

 

  · Heartland Warrant Liability. On January 8, 2015, we entered into the Heartland Credit Agreement. In connection with the Heartland Credit Agreement, we issued a warrant to purchase up to 22,500 shares of our common stock at an exercise price of $25.00. The warrant contains a price protection feature that will automatically reduce the exercise price if we enter into another agreement pursuant to which warrants are issued with a lower exercise price and would also trigger in an adjustment to the warrant share. The change in fair value on the Heartland warrants was approximately $0.3 million and approximately $0.004 million for the three months ended March 31, 2017 and 2016, respectively.

 

  · SOSV Investments LLC Warrant Liability. On June 23, 2016, in conjunction with the merger with Brushy in June 2016, we issued to SOSV Investments LLC (“SOS”) a warrant to purchase up to 200,000 shares of our common stock at an exercise price of $25.00. The warrant contains a price protection feature that will automatically reduce the exercise price if we enter into another agreement pursuant to which warrants are issued with a lower exercise price. For the three months ended March 31, 2017, we incurred a change in the fair value of the derivative liability related to the warrant of approximately $0.2 million.

 

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· Bristol Capital, LLC Warrant Liability . On September 2, 2014, we entered into a Consulting Agreement with Bristol Capital, LLC (“Bristol”), pursuant to which we issued to Bristol a warrant to purchase up to 100,000 shares of our common stock at an exercise price of $20.00 per share (or, in the alternative, 100,000 options, but in no case, both). The agreement has a price protection feature that will automatically reduce the exercise price if we enter into another consulting agreement pursuant to which warrants are issued with a lower exercise price, which triggered in year 2016.  On March 14, 2017, we issued 77,131 shares of common stock to Bristol Capital, LLC (“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 change in fair value of $0.8 million for the three months ended March 31, 2017 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.

 

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

 

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

 

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

 

Total Revenue

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

Production Costs

 

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

 

Production Taxes

 

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

 

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General and Administrative Expenses

 

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

 

Depreciation, Depletion, and Amortization

 

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

 

Impairment of Evaluated Oil and Gas Properties

 

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

 

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

 

Inducement Expense

 

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

 

Gain on Extinguishment of Debt

 

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

 

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Change in Fair Value in Derivative Instruments

 

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

 

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

 

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

 

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

 

Interest Expense

 

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

 

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

 

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 derivative securities and asset dispositions. Our primary uses of capital have been for the acquisition, development, exploration and exploitation of oil and natural gas properties, in addition to refinancing of debt instruments. In 2016, we entered into the First Lien Credit Agreement and completed the Series B 6% preferred stock offering to raise additional capital. We regularly evaluate alternative sources of capital to complement our cash flow from operations and other sources of capital as we pursue our long-term growth plans in the Delaware Basin.

 

We regularly evaluate alternative sources of capital to complement our cash flows from operations and other sources of capital as we pursue our long-term growth plans in the Delaware Basin. In order to fully fund our 2017 capital budget, we may be required to access new capital through one or more offerings of equity.

 

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

 

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Cash Flows

 

Information about our cash flows for the three months ended March 31, 2017 and 2016 are presented in the following table (in thousands):

 

    Three Months Ended March 31,  
    2017     2016  
Cash provided by (used in):                
Operating activities   $ (5,254)     $ (782 )
Investing activities     (10,923)       (599 )
Financing activities     24,855       1,300  
Net change in cash   $ 8,678     $ (81 )

 

Operating activities. For the three months ended March 31, 2017, net cash used in operating activities was $5.3 million, compared to $0.8 million for the same period in 2016. The increase of $4.5 million cash used in operating activities was primarily attributable to the increase in operating costs which correspond with higher producing activities and supporting general and administrative costs.

 

Investing activities . For the three months ended March 31, 2017, net cash used in investing activities was $10.9 million compared to $0.6 million for the same period in 2016. The $10.3 million increase in cash used in investing activities was primarily attributable to the following:

 

  · A $7.1 million increase in drilling and completion costs on the three wells in the Delaware Basin during the three months ended March 31, 2017. There were minimal drilling activities in the DJ Basin during the three months ended March 31, 2016.

 

  · A $3.7 million increase in acquisition of additional working interests on leases in Winkler County, Texas.

 

  · A $0.6 million increase in funds placed in escrow for the Trinidad drilling rig.

 

  · Offset by proceeds of $1.1 million received on the divestiture of the DJ Basin properties.

 

Financing activities. For the three months ended March 31, 2017, net cash provided by financing activities was $24.9 million compared to cash provided by financing activities of $1.3 million during the same period in 2016. The increase of $23.6 million in net cash provided by financing activities during the three months ended March 31, 2017 was primarily attributable to the following:

 

  · A $6.7 million increase in net proceeds from the upsize of the term loan facility.

 

  · A $17.9 million increase in net proceeds from the private placement financing transactions.

 

  · $0.3 million of proceeds from the exercise of warrants and stock options.

 

  · Offset by $1.3 million of proceeds raised from the issuance of convertible notes during the three months ended March 31, 2016.

 

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

 

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

 

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

 

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

 

  · a $7.5 million increase in drilling and completion costs on the Grizzly and Bison wells;

 

  · a $4.2 million increase in oil and gas lease extension fees;

 

  · a $2.3 million cash consideration for the Merger, net of cash acquired; and

 

  · a $3.4 million increase on other capital expenditures relating to the DJ Basin and the Delaware Basin properties.

 

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

 

  · an $18.2 million increase in net proceeds from the issuance of the Series B preferred stock;

 

  · a $30.0 million increase in net proceeds from the term loan facility executed during the third quarter of 2016;

 

  · a $0.3 million increase in proceeds received from the exercise of stock warrants;

 

  · offset by a $3.1 million decrease in net proceeds from the Bridge Loans; and

 

  · offset by an increase of $13.6 million in repayment of principal balances due to the Heartland Bank and Independent Bank.

 

Off-Balance Sheet Arrangements

 

We do not have any off-balance sheet arrangements.

 

Critical Accounting Policies and Estimates

 

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

 

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

 

Use of Estimates

 

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

 

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

 

Oil and Natural Gas Reserves

 

We follow the full cost method of accounting. All of our oil and gas properties are located within the United States, and therefore all costs related to the acquisition and development of oil and gas properties are capitalized into a single cost center referred to as a full cost pool. Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves. Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves less the future cash outflows associated with the asset retirement obligations that have been accrued on the balance sheet plus the cost, or estimated fair value if lower, of unproved properties. Should capitalized costs exceed this ceiling, impairment would be recognized. Under the SEC rules, we prepared our oil and gas reserve estimates as of December 31, 2016, using the average, first-day-of-the-month price during the 12-month period ended December 31, 2016.

 

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

 

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

 

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Oil and Natural Gas Properties-Full Cost Method of Accounting

 

We use the full cost method of accounting whereby all costs related to the acquisition and development of oil and natural gas properties are capitalized into a single cost center referred to as a full cost pool. These costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition and exploration activities.

 

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

 

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

 

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

 

Under the full cost method of accounting, capitalized oil and natural gas property costs, less accumulated depletion and net of deferred income taxes, may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves, plus the cost, or estimated fair value if lower, of unproved properties. Should capitalized costs exceed this ceiling, we would recognize impairment.

 

Revenue Recognition

 

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

 

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

  

Recently Issued Accounting Pronouncements

 

For a discussion of recently adopted accounting standards and recent accounting standards not yet adopted, see “Note 3—Summary of Significant Accounting Policies” to our consolidated financial statements that are included elsewhere in this prospectus.

 

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CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

 

On April 14, 2017, the Company filed a Form 8-K whereby it disclosed its notification to Marcum LLP, or Marcum, of Marcum’s dismissal as the Company’s independent registered public accounting firm, effective immediately. The dismissal of Marcum was approved by the Audit Committee of the Board of Directors of the Company.

 

The audit reports of Marcum on the Company’s consolidated financial statements for each of the fiscal years ended December 31, 2016 and 2015 did not contain an adverse opinion or a disclaimer of opinion and were not qualified or modified as to uncertainty, audit scope or accounting principles, except that the report for fiscal year ended December 31, 2015 contained an explanatory paragraph stating that there was substantial doubt about the Company’s ability to continue as a going concern.

 

During the fiscal years ended December 31, 2016 and 2015, and the subsequent interim period through April 13, 2017, there were no disagreements (as such term is used in Item 304(a)(1)(iv) of Regulation S-K and the related instructions to that Item) with Marcum on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which disagreements, if not resolved to the satisfaction of Marcum, would have caused Marcum to make reference to the subject matter of the disagreement in its reports.

 

During the fiscal years ended December 31, 2016 and 2015, and the subsequent interim period through April 13, 2017, there was no “reportable event” (as that term is defined in 304(a)(1)(v) of Regulation S-K), except as follows.

 

As described in more detail in Item 9A in the Company’s Annual Report on Form 10-K for fiscal year ended December 31, 2015 filed with the Securities and Exchange Commission (the “Commission”) on April 14, 2016, management concluded that the Company did not design and maintain effective internal controls over financial reporting. Specifically, the Company determined that (1) while it has implemented written policies and procedures for accounting and financial reporting with respect to the requirements and application of GAAP and SEC disclosure requirements, due to limited resources, it has not conducted a formal assessment of whether its policies that have been implemented address the specific risks of misstatement and (2) it does not have a fully effective mechanism for monitoring the system of internal controls. This control deficiency did not result in any adjustments to the Company’s financial statements. As reported in Item 9A in the Company’s Annual Report on Form 10-K for fiscal year ended December 31, 2016 filed with the Commission on March 3, 2017, management concluded that the Company’s internal control over financial reporting was effective and the control deficiency mentioned above had been fully remediated. The Company provided Marcum with a copy of the Form 8-K prior to its filing with the Commission and requested Marcum to furnish the Company with a letter addressed to the Commission stating whether Marcum agrees with the statements contained herein and, if not, stating the respects in which it does not agree. A copy of Marcum’s letter dated April 14, 2017 was attached as Exhibit 16.1 to the Form 8-K.

 

The Form 8-K also announced that on April 13, 2017, the Audit Committee engaged BDO USA, LLP, or BDO, as the Company’s independent registered public accounting firm for the fiscal year ending December 31, 2017, effective immediately. The engagement of BDO was approved by the Audit Committee and ratified by the Board of Directors.

 

During the fiscal years ended December 31, 2016 and 2015, and the subsequent interim period through April 13, 2017, neither the Company nor anyone on its behalf consulted BDO regarding (i) the application of accounting principles to a specified transaction, either completed or proposed, (ii) the type of audit opinion that might be rendered on the Company’s financial statements, and neither a written report nor oral advice was provided to the Company that BDO concluded was an important factor considered by the Company in reaching a decision as to any accounting, auditing, or financial reporting issue, (ii) any matter that was either the subject of a “disagreement” as such term is defined in Item 304(a)(1)(iv) of Regulation S-K or a “reportable event” as such term is defined in Item 304(a)(1)(v) of Regulation S-K (there being none).

 

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BUSINESS

 

We are an upstream independent oil and gas company engaged in the acquisition, drilling and production of oil and natural gas properties and prospects. Our primary focus is drilling horizontal wells in the Delaware Basin of West Texas, which we believe will provide attractive returns on a majority of our acreage positions. Our goal is to earn economic returns to our shareholders through cash flow from new production of oil, natural gas and NGLs, as well as through derisking the development profile of our portfolio of properties in order to add overall value. Our drilling program utilizes the development of new horizontal wells across several potentially productive formations in the Delaware Basin but initially targeting the Wolfcamp formation. We drilled our first horizontal well in late 2016 and completed it in January 2017.

 

On June 23, 2016, we completed a merger transaction with Brushy. The merger resulted in the acquisition of our properties in the Delaware Basin as well as the majority of our current operating activity. This contiguous acreage position is offset by RSP Permian, Inc., Matador Resources Company, Devon Energy Corporation, Royal Dutch Shell PLC, Anadarko Petroleum Corp., and XTO Energy Inc., among other operators. Since entering the Delaware Basin in June 2016, we have grown our acreage position 186% from approximately 3,500 net acres to over 10,000 net acres primarily in our Delaware Basin-Core area.

 

On March 31, 2017, we completed the divestiture of all of our oil and gas properties located in the DJ Basin, for a gross purchase price of $2 million, which completed our transformation to a pure play Permian Basin company.

 

Our Properties

 

Delaware Basin - We have accumulated over 10,000 net acres in the Delaware Basin, comprised of large contiguous blocks in Reeves, Winkler and Loving Counties, Texas and Lea County, New Mexico. Currently, 48% of our acreage position is held by production, and we are the named operator on 100% of our producing acreage. These characteristics give us control over the pace of development and the ability to design a more efficient and profitable drilling program that maximizes recovery of hydrocarbons. We expect that substantially all of our estimated 2017 capital expenditure budget will be focused on the development and expansion of our Delaware Basin acreage and operations. The aerial extent of the Delaware Basin stretches across Ward, Reeves, Loving, Winkler, Pecos, and Culberson Counties in Texas and also runs north into Lea and Eddy Counties in New Mexico. The Delaware Basin is comprised of multiple stacked petroleum systems. Drilling and completion technology has evolved with more modern vintage wells utilizing longer laterals, more numerous fracture stimulation stages, and higher volumes of proppant. Our 2017 drilling and completion program currently calls for the drilling of up to 11 gross or 9 net wells (consisting of vertical re-entries and new drills) initially targeting the Wolfcamp formation.  

 

Recent Developments

 

Operations

 

Recent Well Results - In late 2016, we commenced our horizontal drilling program in the Delaware Basin with one rig targeting the Wolfcamp. As of June 15, 2017, we have three horizontal wells on production (Bison #1H, Grizzly #1H and Hippo #1H).

 

The Bison #1H had a 24-hour peak rate of 2,375 Boe/d (75% liquids) and a peak 30-day rate of 2,144 Boe/d (74% liquids) and is currently producing. The Grizzly #1H had a 24-hour peak rate of 1,666 Boe/d (65% liquids) and a peak 30-day rate of 1,323 Boe/d (63% liquids) and is currently producing. Both the Bison #1H and Grizzly #1H are performing above the 923 MBoe and 738 MBoe type curves, respectively, and are located in the northwestern corner of Winkler County.

 

The Bison #1H targeted the Wolfcamp B and was completed utilizing 35 frac stages over a 6,897-ft stimulated interval. The Grizzly #1H also targeted the Wolfcamp B and was completed utilizing 20 frac stages over a 4,103-ft stimulated interval and is currently producing.

 

We also finished completing one additional horizontal well, the Hippo #1H, in April 2017. The Hippo #1H had a 24-hour peak rate of 1,917 Boe/d (74% liquids) and has not yet reached a peak 30-day initial production rate. The Hippo #1H also targeted the Wolfcamp B and was completed utilizing 20 frac stages over a 4,105-ft stimulated interval, it is currently being tested.

 

 

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In addition to the Hippo #1H, we also finished the drilling of the Lion #1H with a projected treatable lateral length of 4,105-ft. Completion of the Lion #1H is scheduled for June 2017 and is anticipated to utilize the same sand loading as the Hippo #1H with 150 ft plug to plug spacing.

 

Acreage Acquisitions - Since entering the Delaware Basin in June 2016, we have grown our acreage position 186% from approximately 3,500 net acres to over 10,000 net acres primarily in our Delaware Basin-Core area.

 

Financing Activities

 

For a complete description of our recent financing activities see Management’s Discussion and Analysis—Recent Developments.

 

 Our Business Strategies

 

Our primary business objective is to increase shareholder value through the execution of the following strategies:

 

· Grow production, cash flow and reserves by developing our extensive Delaware Basin drilling inventory. We intend to selectively develop our acreage base in an effort to maximize its value and resource potential. We will pursue drilling opportunities that offer competitive returns that we consider to be low risk based on production history and industry activity in the area and repeatable as a result of well-defined geological properties over a large area. Through the conversion of our resource base to developed reserves, we will seek to increase our reserves, production and cash flow while generating favorable returns on invested capital. We will continue to closely monitor operators with active leases on adjoining properties, or offset operators, as they delineate adjoining acreage and zones, providing us further data to optimize our development plan over time. We believe this strategy will allow us to significantly grow our production, cash flow and reserves while efficiently allocating capital to maximize the value of our resource base.

 

· Pursue additional leasing and strategic acquisitions. We intend to focus primarily on increasing our acreage position through leasing in the immediate vicinity our existing Delaware Basin acreage, while selectively pursuing other acquisition opportunities that meet our strategic and financial objectives. Our acreage position extends through what we believe are multiple oil and natural gas producing stratigraphic horizons in the Delaware Basin, which we refer to as the stacked pay core, and we believe we can economically and efficiently add and integrate additional acreage into our current operations. Since entering the Delaware Basin in June 2016, we have grown our acreage position 186% from approximately 3,500 net acres to over 10,000 net acres as of June 15, 2017.

  

· Maximize returns by optimizing drilling and completion techniques and improving operating efficiency . We believe completion design combined with cost reductions are the biggest drivers within our control affecting field-level economics. We seek to maintain operational control of our properties in order to better execute on our strategy of enhancing returns through operating improvements and cost efficiencies Through a methodical and continuous focus on drilling efficiency, wellbore accuracy, completion design and execution, we plan to selectively re-enter vertical wells to drill horizontal laterals, reducing drilling cost and improving landing accuracy. We believe that through review of the drilling and mud logs of the vertical wells in our field we can optimize our horizontal wellbore economics and consequently increase production, cash flows, and net asset value. Additionally, our contiguous acreage position is offset by RSP Permian, Inc., Matador Resources Company, Devon Energy Corporation, Royal Dutch Shell PLC, Anadarko Petroleum Corp., and XTO Energy Inc., among other operators, and we will continue to observe and monitor their drilling activity and well results in the area to integrate best practices as we execute on our development plan.

 

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Our Competitive Strengths

 

·

Attractively positioned in the oil-rich Delaware Basin. We have accumulated a leasehold position of over 10,000 net acres in the Delaware Basin as of June 15, 2017. We believe the Delaware Basin has one of the highest rates of return among such formations in North America based on results of offset operators. In addition to leveraging our technical expertise in this core area, our geographically-concentrated acreage position allows us to capitalize on economies of scale with respect to drilling and production costs. Based on our drilling and production results to date and well-established offset operator activity in and around our project areas, we believe there are relatively low geologic risks and ample repeatable drilling opportunities across our core Delaware Basin operating area. We plan on allocating substantially all of our increased 2017 capital budget to our Delaware Basin activities.

   

· High degree of operational control . Our significant operational control allows us to execute our development program, with a focus on the timing and allocation of capital expenditures and application of the optimal drilling and completion techniques to efficiently develop our resource base. We believe this flexibility allows us to efficiently develop our current acreage and adjust drilling and completion activity opportunistically for the prevailing commodity price environment. In addition, we believe communication and data exchange with offset operators will reduce the risks associated with drilling the multiple horizontal zones of our acreage. We also believe our significant level of operational control will enable us to implement drilling and completion optimization strategies, such as pad drilling, continued reduction of spud- to- rig release days and tailored completion designs.

 

·

Experienced and incentivized management team . Our senior management team has a proven track record of building and running successful businesses focused on the development and acquisition of oil and natural gas properties. We believe our team's experience and expertise in horizontal drilling and completions in unconventional formations across multiple resource plays provides us with a distinct competitive advantage. Additionally, our management team and board of directors currently hold in aggregate approximately 15% of our outstanding common stock, which provides a meaningful incentive to increase the value of our business for the benefit of all stockholders. 

 

· Conservatively capitalized balance sheet and strong liquidity profile . As of June 15, 2017, we have approximately $46 million of cash on the balance sheet, and have discretionary access to an additional $45 million under our delayed-draw Second Lien Term Loan to fund leasing activity and acquisitions. We believe that through the availability of cash on hand, term loan draw availability, and cash flow from operations, we will have sufficient liquidity to execute on our updated planned 2017 capital program.

 

Principal Oil and Gas Interests

 

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

 

As of March 31, 2017, we owned interests in approximately 7,722 net acres, of which 3,152 net acres are classified as undeveloped acreage and all of which are located in west Texas and New Mexico within the Delaware Basin. Our primary targets within the Delaware Basin are the Wolfcamp formation as well as the Bone Springs and Avalon Formations. On March 31, 2017, we completed the divestiture of all of our oil and gas properties located in the DJ Basin.

 

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As of December 31, 2016 and June 15, 2017, we had 2 gross (1.2 net) and 2 gross (1.2 net) wells in the process of being drilled, respectively, all in the Delaware Basin.

  

Reserves

 

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

 

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

 

Estimated Total Proved Reserves

 

    December 31,  
    2016     2015  
    Delaware
Basin
    DJ
Basin
    Total     Delaware
Basin
    DJ
Basin
    Total  
Oil (MMBBL)     0.455       0.096       0.551       -       0.033       0.033  
Natural Gas (BCF)     3.507       0.365       3.872       -       0.141       0.141  
Total (MMBOE)     1.04       0.156       1.196       -       0.057       0.057  
% Oil     44 %     61 %             -       59 %        
% Developed     100 %     100 %             -       100 %        
Avg. Net Production (BOE/D)     317       87       404       -       215       215  

 

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

 

Internal Controls over Reserves Estimate

 

Our policy regarding internal controls over the recording of reserves is structured to objectively and accurately estimate our oil and gas reserve quantities and values in compliance with the regulations of the Securities Exchange Commission (the “SEC”). Responsibility for compliance in reserve bookings is delegated to our Chief Financial Officer with assistance from our senior geologist consultant and a senior reserve engineering consultant. In 2016, we established a Reserves Committee to provide additional oversight of our reserves estimation and certification process . The members of the Reserves Committee consist of Brennan Short, our Chief Operating Officer, Ron Ormand, our Executive Chairman and Glenn Dawson, a member of our Board of Directors.

 

Technical reviews are performed throughout the year by our senior reserve engineering consultant and our geologist and other consultants who evaluate all available geological and engineering data, under the guidance of the Chief Financial Officer. This data, in conjunction with economic data and ownership information, is used in making a determination of estimated proved reserve quantities. The 2016 reserve process was overseen by Chris Cantrell, our senior reserve engineering consultant. Mr. Cantrell holds a Bachelor of Science degree in Petroleum Engineering conferred by Texas A&M University in 1995. He is a registered professional engineer licensed in the State of Texas, license number 90521. He has been continuously involved in evaluating oil and gas properties since 1997, and is a member of the Society of Petroleum Engineers and the American Petroleum Institute.

 

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Third-party Reserves Study

 

An independent third-party reserve study as of December 31, 2016, was performed by CG&A using its own engineering assumptions and other economic data provided by us. All of our total calculated proved reserve PV-10 value was audited by CG&A. CG&A is an independent petroleum engineering consulting firm that has been providing petroleum engineering consulting services for over 20 years. The individual at CG&A primarily responsible for overseeing our reserve audit is Todd Brooker, Senior Vice President of CG&A, who received a Bachelor of Science degree in Petroleum Engineering from the University of Texas and is a registered Professional Engineer in the States of Texas. He is also a member of the Society of Petroleum Engineers.

 

The CG&A report dated January 12, 2017, is filed as Exhibit 99.1 to this prospectus.

 

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

 

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

 

Production

 

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

 

    Three Months Ended March 31,              
    2017     2016     Variance     %  
Product                        
Oil (Bbl.) net production     51,491       1,371       50,120       3,656 %
Oil (Bbls)-average realized price   $ 48.47     $ 26.43     $ 22.04       83 %
                                 
Natural Gas (Mcf)-net production     197,057       2,432       194,625       8,003 %
Natural Gas (MCFE)-average realized price   $ 2.98     $ 1.27     $ 1.71       135 %
                                 
Barrels of oil equivalent (BOE)     84,334       1,776       82,558       4,649 %
Average daily net production (BOE/D)     937       20       917       4,585 %
Average Price per BOE   $ 36.56     $ 22.14     $ 14.42       65 %

 

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

 

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

 

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The following table shows a comparison of production volumes and average prices during the periods indicated:

 

    Three Months Ended March 31,  
    2017     2016  
Production costs per BOE   $ 11.02     $ 20.96  
Production taxes per BOE     1.68       1.08  
Depreciation, depletion, and amortization per BOE     13.33       12.89  
Total operating costs per BOE   $ 26.03     $ 34.93  
Gross margin per BOE   $ 10.53     $ (12.79 )
Gross margin percentage     29 %     -58 %

 

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

 

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

 

Drilling Activity

 

As of December 31, 2016 and June 15, 2017, we had 2 gross (1.2 net) and 2 gross (1.2 net) wells in the process of being drilled, respectively.

 

As of December 31, 2016 and 2015, we had working interests in 35 gross (21 net) wells and 6 gross (1.27 net) wells, respectively. Productive wells are either wells producing in commercial quantities or wells capable of commercial production, but are currently shut-in. Multiple completions in the same wellbore are counted as one well. A well is categorized under state reporting regulations as an oil well or a gas well based on the ratio of gas to oil produced when it first commenced production, and such designation may not be indicative of current production.

 

Acreage

 

As of December 31, 2016, we owned 36 producing wells within the Delaware Basin in Texas and New Mexico and in the DJ Basin in Colorado, as well as approximately 34,858 gross (19,968 net) acres, of which 25,752 gross (14,994 net) acres were classified as undeveloped acreage. Our primary assets included acreage located in Winkler and Loving Counties in Texas, Lea County in New Mexico; Laramie and Goshen Counties in Wyoming; Banner, Kimball, and Scotts Bluff Counties in Nebraska; and Weld, Arapahoe and Elbert Counties in Colorado.

 

As of December 31, 2015, we owned 8 producing wells in Wyoming, Nebraska and Colorado within the DJ Basin, as well as approximately 18,000 gross (16,000 net) acres, of which 10,000 gross (8,000 net) acres were classified as undeveloped acreage. Our primary assets included acreage located in Laramie and Goshen Counties in Wyoming; Banner, Kimball, and Scotts Bluff Counties in Nebraska; and Weld, Arapahoe and Elbert Counties in Colorado.

 

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

 

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

 

As of June 15, 2017, our inventory of developed and undeveloped acreage includes approximately 26,000 gross (10,000 net) acres, of which approximately 7,200 gross (5,000 net) acres that are held by production. We will continue to pursue additional properties, acquire other properties primarily targeted in the Delaware Basin, but potentially throughout North America, or drill wells on our core properties to hold the property by production if financing is available to us and the properties are economic. On March 31, 2017, we completed the divestiture of all of our oil and gas properties located in the DJ Basin

 

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Title to Properties

 

Approximately 48% of our leasehold interests are held by production, with substantially all of our Delaware Basin leasehold position subject to mortgages securing indebtedness under our First and Second Lien Term Loans. We believe the security interests granted in our properties do not materially interfere with the use of, or affect the value of, such properties.

 

Marketing and Pricing

 

We derive revenue and cash flow principally from the sale of oil and natural gas. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil and natural gas. We sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts. The market price for oil and natural gas is dictated by supply and demand, and we cannot accurately predict or control the price we may receive for our oil and natural gas.

 

Our revenues, cash flows, profitability and future rate of growth will depend substantially upon prevailing prices for oil and natural gas. Prices may also affect the amount of cash flow available for capital expenditures and other cash requirements and our ability to borrow money or raise additional capital. Lower prices may also adversely affect the value of our reserves and make it uneconomical for us to commence or continue production levels of natural gas and crude oil. Historically, the prices received for oil and natural gas have fluctuated widely. Among the factors that can cause these fluctuations are:

 

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

 

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

 

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

 

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

 

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

 

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Major Customers

 

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

 

Seasonality

 

Generally, but not always, the demand and price levels for natural gas increase during colder winter months and decrease during warmer summer months. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies, and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity has placed increased demand on storage volumes. Demand for crude oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are much more driven by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. The impact of seasonality on crude oil has been somewhat magnified by overall supply and demand economics attributable to the narrow margin of production capacity in excess of existing worldwide demand for crude oil.

 

Competition

 

The oil and gas industry is intensely competitive, particularly with respect to acquiring prospective oil and natural gas properties. We believe our leasehold position provides a solid foundation for an economically robust exploration program and our future growth. Our success and growth also depends on our geological, geophysical, and engineering expertise, design and planning, and our financial resources. We believe the location of our acreage, our technical expertise, available technologies, our financial resources and expertise, and the experience and knowledge of our management enables us to compete effectively in our core operating areas. However, we face intense competition from a substantial number of major and independent oil and gas companies, which have larger technical staffs and greater financial and operational resources than we do.

 

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

 

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

 

Regulation of the Oil and Natural Gas Industry

 

General. Our operations covering the exploration, production and sale of oil and natural gas are subject to various types of federal, state and local laws and regulations. The failure to comply with these laws and regulations can result in substantial penalties. These laws and regulations materially impact our operations and can affect our profitability. However, we do not believe that these laws and regulations affect us in a manner significantly different than our competitors. Matters regulated include, but are not limited to, permits for drilling operations, drilling and abandonment bonds, reports concerning operations, the spacing of wells and unitization and pooling of properties, restoration of surface areas, plugging and abandonment of wells, requirements for the operation of wells, production and processing facilities, land use, subsurface injection, air emissions, the disposal of fluids used or other wastes obtained in connection with operations, the valuation and payment of royalties and taxation of production. At various times, regulatory agencies have imposed price controls and limitations on production. In order to conserve supplies of oil and natural gas, these agencies have restricted the rates of flow of oil and natural gas wells below actual production capacity, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding production. Federal, state and local laws regulate production, handling, storage, transportation and disposal of oil and natural gas, by-products from oil and natural gas and other substances and materials produced or used in connection with oil and natural gas operations. While we believe that we will be able to substantially comply with all applicable laws and regulations through our strict attention to regulatory compliance, the requirements of such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the FERC and the courts. We cannot predict when or whether any such proposals may become effective. We do not believe that we would be affected by any such action materially differently than similarly situated competitors.

 

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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 gas and may prevent or delay the commencement or continuation of certain projects. In addition, these laws and regulations may impose substantial clean-up, remediation, and other obligations in the event of any discharges or emissions in violation of these laws and regulations. Further, legislative and regulatory initiatives related to global warming or climate change could have an adverse effect on our operations and the demand for oil and natural gas. See “Risk Factors-Risks Relating to the Oil and Gas Industry-Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for oil and natural gas.” The following is a summary of the more significant existing and proposed environmental and occupational health and safety laws and regulations to which our business operations are or may be subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position. During the years ended December 31, 2016 and 2015, we incurred $182,000 and $130,000, respectively, related to compliance with environmental laws for our DJ Basin.

 

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The Resource Conservation and Recovery Act

 

The Resource Conservation and Recovery Act of 1976, as amended (“RCRA”), and the comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. The RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility. At present, the RCRA includes an exemption that allows certain oil and natural gas exploration and production waste to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. As a result, we are not required to comply with a substantial portion of RCRA’s hazardous waste requirements. At various times in the past, proposals have been made to amend the RCRA to rescind the exemption that excludes oil and natural gas exploration and production wastes from regulation as hazardous waste. For example, in 2010, a petition was filed by the Natural Resources Defense Council (“NRDC”) with the Environmental Protection Agency (“EPA”) requesting that the agency reassess its prior determination that certain exploration and production wastes are not subject to the RCRA hazardous waste requirements. The EPA has not yet acted on the petition. On May 5, 2016, moreover, the NRDC, along with other environmental organizations, commenced a lawsuit against the EPA, asking the U.S. District Court for the District of Columbia to order the agency to “revise” its RCRA regulations as they pertain to oil and gas wastes. On December 28, 2016, the court signed a consent decree, resolving the lawsuit, under which the EPA agreed that, by March 15, 2019, it will either sign a notice of proposed rulemaking for a revision of its RCRA regulations as they pertain to oil and gas wastes (in which case it will take a final action on the proposed rulemaking by July 15, 2021) or sign a determination that no such revision is necessary. Repeal or modification of the RCRA oil and gas exemption by administrative, legislative or judicial process, or modification of similar exemptions in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us to incur, perhaps significantly, increased operating expenses.

 

Water Discharges

 

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

 

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

 

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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 RRC regulates the disposal of produced water by injection well. The RRC requires operators to obtain a permit from the agency for the operation of saltwater disposal wells and establishes minimum standards for injection well operations. In response to recent seismic events near underground injection wells used for the disposal of oil and gas-related wastewaters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or imposed moratoria on the use of such injection wells. In response to these concerns, regulators in some states are considering additional requirements related to seismic safety. For example, the RRC has adopted new permit rules for injection wells to address these seismic activity concerns within the state. Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells, and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. These new rules could impact the availability of injection wells for disposal of wastewater from our operations. Increased costs associated with the transportation and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may reduce our profitability; however, these costs are commonly incurred by all oil and gas producers and we do not believe that the costs associated with the disposal of produced water will have a material adverse effect on our operations.

 

Air Pollutant Emissions

 

The federal Clean Air Act (the “Clean Air Act”) and comparable state and local air pollution laws adopted to fulfill its mandate provide a framework for national, state and local efforts to protect air quality. Our operations utilize equipment that emits air pollutants which may be subject to federal and state air pollution control laws. These laws generally require utilization of air emissions control equipment to achieve prescribed emissions limitations and ambient air quality standards, as well as operating permits for existing equipment and construction permits for new and modified equipment. We believe that we are in compliance in all material respects with the requirements of applicable federal and state air pollution control laws. Over the next several years, we may be required to incur capital expenditures for air pollution control equipment or other air emissions-related issues. The EPA promulgated significant New Source Performance Standards (“NSPS OOOO”) in 2012, as amended in 2013 and 2014, which have added administrative and operational costs. On May 12, 2016, the EPA issued regulations (effective August 2, 2016) that build on the NSPS OOOO standards by directly regulating methane and volatile organic compound (“VOC”) emissions from various types of new and modified oil and gas sources. Some of those sources are already regulated under NSPS OOOO, while others, like hydraulically fractured oil wells, pneumatic pumps, and certain equipment and components at compressor stations, are covered for the first time. On March 10, 2016, moreover, the EPA announced that it is moving towards issuing performance standards for methane emissions from existing oil and gas sources. The agency said that it will “begin with a formal process ( i.e. , an Information Collection Request) to require companies operating existing oil and gas sources to provide information to assist in the development of comprehensive regulations to reduce methane emissions.” On November 10, 2016, the EPA issued the Information Collection Request (“ICR”) and explained that “[r]ecipients of the operator survey (also referred to as Part 1) will have 60 days after receiving the ICR to complete the survey and submit it to EPA….Recipients of the more detailed facility survey (also referred to as Part 2) will have 180 days after receiving the ICR to complete that survey and submit it to the agency.” 

 

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On October 1, 2015, under the Clean Air Act, the EPA lowered the national ambient air quality standard for ozone from 75 ppb to 70 ppb. This change could result in an expansion of ozone nonattainment areas across the United States, including areas in which we operate. Oil and natural gas operations in ozone nonattainment areas would likely be subject to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements, and increased permitting delays and costs.

 

Along these lines, on October 20, 2016, the EPA finalized Control Techniques Guidelines to reduce emissions from a number of existing oil and gas sources that are located in certain ozone nonattainment areas and states in the Ozone Transport Region (which is comprised of Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Pennsylvania, Rhode Island, Vermont, the District of Columbia, and Northern Virginia). These guidelines will lead to direct regulation of VOC emissions and have the incidental effect of reducing methane emissions. The regulations will take the form of reasonably available control technology requirements.

 

Regulation of “Greenhouse Gas” Emissions

 

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA, under the Clean Air Act, has adopted regulations that, among other things, establish Prevention of Significant Deterioration (“PSD”), construction, and Title V operating permit requirements for certain new and modified large stationary sources. Facilities required to comply with PSD requirements for their GHG emissions will be required to meet “best available control technology” standards for those emissions, which will be established on a case-by-case basis. EPA rulemakings related to GHG emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations. In October 2015, the EPA finalized rules (effective January 1, 2016) that added new sources to the scope of the greenhouse gases monitoring and reporting rule. These new sources include gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells. The revisions also include the addition of well identification reporting requirements for certain facilities. In addition, as noted above, the EPA has finalized new source performance standards related to methane emissions from the oil and natural gas industry.

 

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional cap and trade programs have emerged that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our exploration and production operations.

 

Hydraulic Fracturing Activities

 

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight unconventional formations. For additional information about hydraulic fracturing and related regulatory matters, see “Risk Factors-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.

 

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Federal and state occupational safety and health laws require us to organize and maintain information about hazardous materials used, released, or produced in our operations. Some of this information must be provided to our employees, state and local governmental authorities, and local citizens. We are also subject to the requirements and reporting framework set forth in the federal workplace standards.

 

The discharge of oil, gas or other pollutants into the air, soil or water may give rise to liabilities to the government and third parties and may require us to incur costs to remedy discharges. Natural gas, oil or other pollutants, including salt water brine, may be discharged in many ways, including from a well or drilling equipment at a drill site, leakage from pipelines or other gathering and transportation facilities, leakage from storage tanks and sudden discharges from damage or explosion at natural gas facilities of oil and gas wells. Discharged hydrocarbons may migrate through soil to fresh water aquifers or adjoining property, giving rise to additional liabilities.

 

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

 

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

 

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

 

A variety of federal and state laws and regulations govern the environmental aspects of natural gas and oil production, transportation and processing. These laws and regulations may impose liability in the event of discharges, including for accidental discharges, failure to notify the proper authorities of a discharge, and other noncompliance. Compliance with such laws and regulations may increase the cost of oil and gas exploration, development and production; although we do not anticipate that compliance will have a material adverse effect on our capital expenditures or earnings. Failure to comply with the requirements of the applicable laws and regulations could subject us to substantial civil and/or criminal penalties and to the temporary or permanent curtailment or cessation of all or a portion of our operations.

 

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Comprehensive Environmental Response, Compensation and Liability Act

 

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “superfund law,” imposes joint and several liabilities, regardless of fault or the legality of the original conduct, on some classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of a disposal site or sites where the release occurred and companies that transport, dispose, or arrange for disposal of the hazardous substance(s) released. Persons who are or were responsible for releases of hazardous substances under CERCLA may be jointly and severally liable for the costs of cleaning up the hazardous substances and for damages to natural resources. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We could be subject to liability under CERCLA, including for jointly-owned drilling and production activities that generate relatively small amounts of liquid and solid waste that may be subject to classification as hazardous substances under CERCLA.

 

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

  

Endangered Species Act and Migratory Birds

 

The Endangered Species Act (“ESA”) restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. We may conduct operations under oil and natural gas leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species that potentially could be listed as threatened or endangered under the ESA may exist. The U.S. Fish and Wildlife Service (“FWS”) may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. As a result of a pair of 2011 settlement agreements, the FWS is required to make determinations on whether more than 250 species should be listed as endangered or threatened under the FSA. It must make the determinations by no later than completion of the agency’s 2017 fiscal year. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The federal government has issued indictments under the Migratory Bird Treaty Act to several oil and gas companies after dead migratory birds were found near reserve pits associated with drilling activities. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.

 

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NEPA

 

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

 

OSHA

 

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

 

State Laws

 

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

 

In General

 

We do not believe that our environmental risks will be materially different from those of comparable companies in the oil and gas industry. We believe our present activities substantially comply, in all material respects, with existing environmental laws and regulations. Nevertheless, environmental laws may result in a curtailment of production or material increase in the cost of production, development or exploration and may otherwise adversely affect our financial condition and results of operations. Although we maintain liability insurance coverage for liabilities from pollution, environmental risks, generally are not fully insurable.

 

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

  

Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and release of our natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.

 

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

 

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

 

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

 

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

 

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

 

Federal Leases. For those operations on federal oil and gas leases, such operations must comply with numerous regulatory restrictions, including various non-discrimination statutes, and certain of such operations must be conducted pursuant to certain on-site security regulations and other permits issued by various federal agencies. In addition, on federal lands in the United States, the Office of Natural Resources Revenue (“ONRR”) prescribes or severely limits the types of costs that are deductible transportation costs for purposes of royalty valuation of production sold off the lease. In particular, ONRR prohibits deduction of costs associated with marketer fees, cash out and other pipeline imbalance penalties, or long-term storage fees. Further, the ONRR has been engaged in a process of promulgating new rules and procedures for determining the value of crude oil produced from federal lands for purposes of calculating royalties owed to the government. The natural gas and crude oil industry as a whole has resisted the proposed rules under an assumption that royalty burdens will substantially increase. We cannot predict what, if any, effect any new rule will have on our operations.

 

Some of our operations are conducted on federal lands pursuant to oil and gas leases administered by the 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.

 

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In May 2010, the BLM adopted changes to its oil and gas leasing program that require, among other things, a more detailed environmental review prior to leasing oil and natural gas resources, increased public engagement in the development of master leasing and development plans prior to leasing areas where intensive new oil and gas development is anticipated, and a comprehensive parcel review process. These changes have increased the amount of time and regulatory costs necessary to obtain oil and gas leases administered by the BLM. In addition, the BLM, on March 20, 2015, issued its final regulations for hydraulic fracturing on federal and tribal lands. The new regulations require, among other things, disclosure of chemicals, annulus pressure monitoring, flow back and produced water management and storage, and more stringent well integrity measures associated with hydraulic fracturing operations on public land. The new regulations become effective on June 24, 2015. BLM has also announced its intention to conduct a separate rulemaking to address venting and flaring of natural gas from oil and gas operations on public land. These hydraulic fracturing-related rulemakings may adversely affect our operations conducted on federal lands.

 

Other Laws and Regulations . Various laws and regulations require permits for drilling wells and also cover spacing of wells, the prevention of waste of natural gas and oil including maintenance of certain gas/oil ratios, rates of production and other matters. The effect of these laws and regulations, as well as other regulations that could be promulgated by the jurisdictions, in which we have production, could be to limit the number of wells that could be drilled on our properties and to limit the allowable production from the successful wells completed on our properties, thereby limiting our revenues.

 

To date we have not experienced any material adverse effect on our operations from obligations under environmental, health, and safety laws and regulations. We believe that we are in substantial compliance with currently applicable environmental, health, and safety laws and regulations, and that continued compliance with existing requirements will not have a materially adverse impact on us.

 

Employees

 

As of June 15, 2017, we had twenty-four full-time employees and one part-time employees, and intend to continue to add additional personnel as our operational requirements grow. We plan to continue to leverage the use of independent consultants and contractors to provide various professional services, including additional land, legal, engineering, geology, environmental and tax services.

 

Available Information

 

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

 

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.

   

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MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

 

Recent Market Prices

 

Our common stock is currently listed on the NYSE MKT under the symbol “LLEX.” From March 13, 2017 to May 9, 2017, our common stock was quoted on The NASDAQ Capital Market. From May 27, 2016 to March 13, 2017, our common stock was quoted 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 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  
    2017  
Second Quarter (through June 15, 2017)   $ 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  
                 
    2015  
Fourth Quarter   $ 7.00     $ 0.70  
Third Quarter   $ 31.50     $ 4.80  
Second Quarter   $ 19.00     $ 7.40  
First Quarter   $ 12.60     $ 6.00  

  

On June 15, 2017, the last reported sale price of shares of our common stock on the NYSE MKT was $5.00. As of June 15, 2017, there were 112 owners of record of our common stock. We estimate that there are approximately 2,865 beneficial holders of our common stock.

 

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DIRECTORS AND EXECUTIVE OFFICERS

 

The following table sets forth the names, ages and positions of the persons who are our directors and executive officers as of April 14, 2017:

 

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

 

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

 

Director Qualifications:

 

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

 

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

 

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Director Qualifications:

 

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

 

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

 

Director Qualifications :

 

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

 

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

 

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Director Qualifications:

 

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

 

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

 

Director Qualifications:

 

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

 

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

 

Director Qualifications:

 

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

 

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

 

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

 

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

 

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

 

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

 

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EXECUTIVE AND DIRECTOR COMPENSATION

 

Executive Compensation for Fiscal Year 2016

 

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

 

Summary Compensation Table

 

The table below sets forth compensation paid to our chief executive officer, and our two other most highly compensated executive officers during the fiscal year ended December 31, 2016, which we refer to as our named executive officers for the years ending December 31, 2016 and 2015.

 

Name and Principal
Position
  Year   Salary
($)
    Bonus
($)
    Stock
Awards
($)(1)
    Option
Awards
($)(2)
    All Other
Compensation
($)(3)
    Total
($)
 
Abraham “Avi” Mirman   2016     350,000       175,000 (4)           4,295,894       27,734       4,843,378  
(Chief Executive Officer)   2015     325,466       100,000 (5)     90,000       1,397,721       39,856       1,944,691  
                                                     
Ronald D. Ormand(6)   2016     150,000             1,875,000       533,092       69,502       2,627,594  
(Chairman of the Board of Directors)                                                    
                                                     
Ariella Fuchs   2016     240,000       112,500 (4)           1,288,768       10,717       1,649,685  
(General Counsel and Secretary)   2015     182,083             48,000       234,887       15,138       475,508  

 

(1) Represents restricted stock awards. The grant date fair values for restricted stock awards were computed in accordance with FASB ASC Topic 718. The amounts reported in this column reflect the accounting cost for the stock awards and do not necessarily correspond to the actual economic value that may be received for the stock awards.
(2)

Awards in this column are reported at grant date fair value, if awarded in the period, and any incremental fair value, if modified in the period, in each case in accordance with FASB ASC Topic 718. Mr. Mirman was granted 1,250,000 options on June 24, 2016 and 500,000 options on December 15, 2016; Mr. Ormand was granted 250,000 options on December 15, 2016; and Ms. Fuchs was granted 375,000 options on each of June 24, 2016 and December 15, 2016. The grant date fair values for options granted on June 24, 2016 and December 15, 2016 were $1.30 (rounded) and $2.13 (rounded), respectively. For both Mr. Mirman and Ms. Fuchs, their options granted June 24, 2016 were modified December 15, 2016 to provide for accelerated exercisability upon an involuntary employment termination and upon a change in control, and for extension of the post-termination exercise period upon an employment termination other than for cause. However, there was no incremental fair value for those modified options. The amounts reported in this column reflect the accounting cost for the options and do not correspond to the actual economic value that may be received for the options. The assumptions used to calculate the fair value of options are set forth in the notes to our consolidated financial statements included elsewhere in this prospectus. As noted below under the heading “Equity Grants for Fiscal Year 2016,” in June 2017 the compensation committee approved the rescission of all 500,000 options granted to Mr. Mirman on December 15, 2016, and 250,000 of the options granted to Mr. Mirman on June 24, 2016. The rescission of these options occurred after December 31, 2016 and, therefore, is not reflected in this table.

(3)

For 2016, this amount includes $22,484, $14,502 and $8,417 paid for reimbursement of health insurance premiums to Mr. Mirman, Mr. Ormand and Ms. Fuchs, respectively. Also includes $55,000 paid to Mr. Ormand for director fees paid to him for his Board service in 2016 prior to the time he became and officer and $5,250 and $2,300 paid to Mr. Mirman and Ms. Fuchs, respectively, for matching contributions to our 401(k) plan.

(4) Reflects a bonus payable under the officer’s employment agreement for the successful completion of the Brushy merger.
(5) Reflects a sign-on bonus.
(6) Effective July 11, 2016, Mr. Ormand began to serve as Executive Chairman of the Board, which is an officer position. Prior to July 11, 2016, Mr. Ormand was a nonemployee director of the Board and his compensation from January 1 to July 10, 2016 is reflected under All Other Compensation.

 

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Outstanding Equity Awards at Fiscal Year-End

 

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

 

(1) Options vest in equal installments on each of December 15, 2017 and 2018, subject to acceleration provisions and continued service. As noted below under the heading “Equity Grants for Fiscal Year 2016,” in June 2017 the compensation committee approved the rescission of all 500,000 options granted to Mr. Mirman on December 15, 2016. The rescission of these options occurred after December 31, 2016 and, therefore, is not reflected in this table.

(2) Options vest in equal installments on each of June 24, 2017 and 2018, subject to acceleration provisions and continued service. As noted below under the heading “Equity Grants for Fiscal Year 2016,” in June 2017 the compensation committee approved the rescission of 250,000 of the options granted to Mr. Mirman on June 24, 2016. The rescission of these options occurred after December 31, 2016 and, therefore, is not reflected in this table.

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

 

Employment Agreements and Other Compensation Arrangements

 

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

 

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

 

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

 

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

 

2016 Omnibus Incentive Plan (“2016 Plan”)

 

Background

 

Our 2016 Plan was approved by our Board effective April 20, 2016 and approved by our stockholders at 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.

   

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Eligibility

 

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

 

Administration

 

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

 

Number of Authorized Shares

 

When initially approved by our stockholders, 50,000,000 shares of our common stock were made available for issuance under our 2016 Plan. As a result of our 1-for-10 reverse stock split, which took effect on June 23, 2016, the number of shares available for issuance under our 2016 Plan was automatically reduced to 5,000,000. On August 25, 2016, our Board approved an amendment to our 2016 Plan to increase the maximum number of shares that may be issued from 5,000,000 to 10,000,000, and our stockholders approved that amendment at a special meeting on November 3, 2016. On May 15, 2017, our Board approved a second amendment to the 2016 Plan to increase the maximum number of shares of our common stock that may be issued under the 2016 Plan from 10,000,000 to 13,000,000, subject to stockholder approval, and directed that the amendment be submitted to the stockholders for approval at the 2017 Annual Meeting.

 

In addition, as of May 23, 2016, any awards then outstanding under our 2012 EIP remain subject to and will be paid under the 2012 EIP and any shares then subject to outstanding awards under the 2012 EIP that subsequently expire, terminate or are surrendered or forfeited for any reason without issuance of shares will automatically become available for issuance under our 2016 Plan. Up to 5,000,000 shares may be granted as tax-qualified incentive stock options under our 2016 Plan (10,000,000 shares if our stockholders approve the second amendment to the 2016 Plan). The shares issuable under our 2016 Plan will consist of authorized and unissued shares, treasury shares or shares purchased on the open market or otherwise.

 

If any award is canceled, terminates, expires or lapses for any reason prior to the issuance of shares or if shares are issued under our 2016 Plan and thereafter are forfeited to 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 fiscal year, may not exceed $500,000 in total value (calculating the value of any such awards based on the grant date fair value of such awards for financial reporting purposes).

 

Types of Awards

 

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

 

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No Repricing

 

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

 

Clawback

 

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

 

Transferability

 

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

 

Effect of Change in Control

 

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

 

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

 

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

 

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

 

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

 

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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 stockholders. Our Board may amend, suspend or terminate our 2016 Plan at any time, except that, if required by applicable law, regulation or stock exchange rule, stockholder approval will be required for any amendment. The amendment, suspension or termination of our 2016 Plan or the amendment of an outstanding award generally may not, without a participant’s consent, materially impair the participant’s rights under an outstanding award.

 

Equity Grants for Fiscal Year 2016

 

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

 

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 Section 162(m) of the Code, the 2016 Plan included an annual limit on grants of stock options and stock appreciation rights 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, the 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. The compensation committee believed these awards otherwise represented appropriate compensation opportunities for Mr. Mirman and in June 2017, the compensation committee approved options and restricted stock awards to replace the value of the rescinded option awards.

 

Employment Agreements

 

Mr. Mirman

 

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

 

On July 5, 2016, we entered into a new employment agreement with Mr. Mirman under which he will serve as our CEO. This agreement became effective June 24, 2016 upon the closing of our merger with Brushy. As previously disclosed, we amended his employment agreement on May 5, 2017 to eliminate his eligibility to receive certain “cash incentive bonuses” under the agreement 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 Mr. Mirman’s agreement is scheduled to end on December 31, 2017, and the agreement will renew automatically for additional one-year periods beginning on December 31, 2017, unless either party gives notice of non-renewal at least 180 days before the end of the then-current term. The agreement replaced in its entirety Mr. Mirman’s prior employment agreement with us.

 

Mr. Mirman’s base salary under his agreement (which will be reviewed by the Board for adjustments) is $350,000 for the first year of the agreement, $375,000 for the second year of the agreement, and $425,000 for the third year of the agreement. Mr. Mirman was entitled to a bonus under the agreement equal to $175,000, payable in cash on the first regular payroll date following June 24, 2016 (the closing date of the merger with Brushy). Mr. Mirman will also be eligible to receive awards of equity and non-equity compensation and to participate in our annual and long-term incentive plans, in each case as determined by our Board in its discretion.

 

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

 

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

 

Mr. Ormand

 

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

 

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

 

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

 

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

 

Ms. Fuchs

 

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

 

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

 

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

 

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

 

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

 

Potential Payments Upon Termination or Change-In-Control

 

Mr. Mirman

 

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

 

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Mr. Ormand

 

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

 

Ms. Fuchs

 

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

 

Stock Options

 

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

 

Retirement and Other Benefits

 

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

 

Compensation of Nonemployee Directors For the Year Ended December 31, 2016

 

Name   Fees Earned
or Paid in
Cash
Compensation
($)
    Stock Awards
($)(1)
    Option
Awards
($)(2)
    All Other
Compensation
($)
    Total
($)
 
                               
G. Tyler Runnels(3)                              
Nuno Brandolini(4)     72,500       135,000                   207,500  
General Merrill McPeak(5)     85,000       135,000                   220,000  
R. Glenn Dawson(6)     70,522       255,750       81,000             407,272  
Peter Benz(7)     43,901       135,000       67,500             246,401  

 

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

Mr. Brandolini was appointed to the Board on February 13, 2014.

(5)

General McPeak was appointed to the Board on January 29, 2015.

(6) Mr. Dawson was appointed to the Board on January 13, 2016.
(7) Mr. Benz was appointed to the Board on June 23, 2016.

 

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

 

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

 

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

 

Indemnification of Directors and Officers

 

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

 

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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

 

Related Party Transactions

 

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

 

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

 

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

 

Series B Preferred Stock Private Placement and Conversion

 

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

 

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

 

On April 25, 2017, we entered into the Conversion Agreement with the Purchasers, pursuant to which as consideration for the automatic conversion of outstanding shares of Series B Preferred Stock, we agreed to pay dividends as if they accrued through December 31, 2017 by increasing the stated value prior to conversion in a total amount of approximately $1.3 million. Certain Purchasers in the Series B Stock Offering who are currently 5% holders as a result of this transaction include Rosseau Asset Management Ltd ($3 million), LOGiQ Capital 2016 ($3 million), and Investor Company 5J5505D ($5 million).

 

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

  

First Lien Credit Agreement and Warrant Reprice

 

On September 29, 2016, we entered into the First Lien Credit Agreement, as amended on April 24, 2017. For more information about the First Lien Credit Agreement see Management’s Discussion and Analysis—First Lien Credit Agreement and Warrant Repricing and — Management’s Discussion and Analysis —Recent Developments— First Lien Credit Agreement Drawdown, Repayment and Amendment.

 

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First Lien Credit Agreement Drawdown, Repayment and Amendment.

 

Certain parties to the First Lien Credit Agreement included certain of our related parties such as TRW, acting as collateral agent, and Bryan Ezralow, Marc Ezralow and Marshall Ezralow through certain of their investment entities ($2.8 million), J. Steven Emerson through certain of his investment entities ($6 million), Rosseau Asset Management Ltd ($2 million), LOGiQ Capital 2016 ($1 million), and Investor Company 5J5505D ($20 million).

 

Second Lien Credit Agreement

 

On April 26, 2017, we entered into the Second Lien Credit Agreement with the lenders party thereto, collectively a beneficial owner of securities over 5% that are acquirable within 60 days. For more information about the Second Lien Credit Agreement see Management’s Discussion and Analysis—Recent Developments—Second Lien Credit Agreement.

 

Debenture Conversion Agreement

 

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

 

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

 

Series A Preferred Stock

 

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

 

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

 

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

 

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Convertible Notes

 

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

 

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

 

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

 

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

 

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

 

SOS

 

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

 

March 2017 Private Placement

 

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

 

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

 

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G. Tyler Runnels and T.R. Winston

 

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

 

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

 

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

 

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

 

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

 

On February 28, 2017, we entered into a Subscription Agreement in connection with the March 2017 Private Placement, for which TRW acted as placement agent and received a fee of $484,171. Additionally, TRW was a participant in the offering for an aggregate amount of $795,000.

 

Ronald D. Ormand

 

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

 

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

 

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.

 

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Agreements with Former Executive Officers

 

Kevin Nanke, Former Executive Vice President and Chief Financial Officer

 

On February 13, 2017, we entered into a Separation and Release of Claims Agreement (the “Separation Agreement”) with Mr. Nanke, providing for his separation as an officer of our company, effective January 23, 2017. Pursuant to the Separation Agreement and the terms of his employment agreement, Mr. Nanke will receive (1) a lump sum severance payment in an amount equal to 24 months of base salary in effect immediately prior to the date of termination, (2) a lump sum payment equal to 24 months of COBRA premiums based on the terms of our group health plan and Mr. Nanke’s coverage under such plan as of the date of termination, and (3) a lump sum bonus payment of $175,000. For consideration of the separation benefits listed above, Mr. Nanke (1) provided a general release of claims against us, our affiliates, and related parties, (2) to the extent reasonable, shall continue to provide full and continued cooperation in good faith with our company, our subsidiaries, and affiliates for 24 months following the date of termination in connection with certain matters relating to our company, and (3) agreed to be bound by confidentiality commitments to our company. Further to the terms of the Separation Agreement, the Board approved the acceleration of Mr. Nanke’s 416,667 stock options, which represented the unvested portion of Mr. Nanke’s equity awards.

 

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

 

On March 31, 2017, the Company sold all of its oil and gas properties located in the DJ Basin to Nanke Energy, LLC, an entity owned by Mr. Nanke for a total gross purchase price of $2 million, subject to customary post-closing purchase price adjustments.

 

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

 

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

 

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

 

Compensation of Directors

 

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

 

Conflict of Interest Policy

 

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

 

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Director Independence

 

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

 

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

 

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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 June 15, 2017 by each of our executive officers and directors and each person known to be the beneficial owner of 5% or more of the outstanding common stock.

 

This table is based upon the total number of shares outstanding as of June 15, 2017 of 50,419,551. 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 June 15, 2017 are deemed outstanding by such person or group, but are not deemed outstanding for the purpose of computing the percentage ownership of any other person. All share amounts that appear in this report have been adjusted to reflect a 1-for-10 reverse stock split of Lilis Energy, Inc.’s 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., Suite No. 1220, San Antonio, TX 78258.

 

Name and Address of Beneficial Owner   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                                
Abraham Mirman, Chief Executive Officer and Director     2,158,326 (2)     1,060,001 (3)     3,218,327       6.3 %(4)
Ronald D. Ormand, Executive Chairman of the Board     3,678,086 (5)     115,001 (6)     3,793,087       7.5 %(7)
Joseph Daches, Chief Financial Officer     215,728       250,000 (8)     465,728       *  
Ariella Fuchs, General Counsel and Secretary     88,455       375,000 (9)     463,455       *  
Peter Benz, Director     75,000       25,000 (10)     100,000       *  
Nuno Brandolini, Director     442,060       119,574 (11)     561,634       1.1 %
R. Glenn Dawson, Director     589,861       176,668 (12)     766,529       1.5 %
General Merrill McPeak, Director     406,207       143,521 (13)     549,728       1.1 %
                                 
Directors and Officers as a Group (8 persons)     7,653,723       2,264,765 (14)     9,918,488       18.8 %(15)
                                 
5% Stockholders                                
Bryan Ezralow,
23622 Calabasas Road, Suite 200,
Calabasas, CA 913012
    3,486,676 (16)     272,731 (17)     3,759,407       7.4 %
Marc Ezralow,
23622 Calabasas Road, Suite 200,
Calabasas, CA 913012
    2,783,559 (18)     220,783 (19)     3,004,342       5.9 %
J. Steven Emerson,
1522 Ensley Avenue,
Los Angeles, CA 90024
    4,064,074 (20)     324,678 (21)     4,388,752       8.2 %
Rosseau Asset Management Ltd.
181 Bay Street, Suite 2920, Box 736
Toronto, Ontario M5J 2T3
    2,848,334 (22)     (23)     2,848,334       5.6 %
LOGiQ Capital 2016.
77 King Street West, Suite 2110
TD North Tower, TD Centre
Toronto, Ontario M5K 1G8
    2,644,627 (24)     (25)      2,644,627       5.2 %
Investor Company 5J5505D
Vertex One Asset Management
1021 West Hastings Street, Suite 3200
Vancouver, BC V6E 0C3
    7,029,243 (26)           7,029,243       13.9 %
Vӓrde Partners, Inc.
901 Marquette Avenue South
Suite 330, Minneapolis, MN 55402
          12,526,206 (27)     12,526,206       19.9 %

 

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* 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 June 15, 2017, without giving effect to limitation.