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
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.
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.
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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.
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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.
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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”).
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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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| 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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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.
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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 |
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 |
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 |
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.
| 45 |
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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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. |
| (2) | Consists of: (i) 1,203,087 shares of common stock held by The Bralina Group, LLC; and (ii) 955,239 shares of common stock held directly by Mr. Mirman. Mr. Mirman has shared voting and dispositive power over the securities held by The Bralina Group, LLC with Susan Mirman. |
| (3) | Represents shares of common stock subject to options exercisable within 60 days. |
In addition, Mr. Mirman beneficially owns an aggregate of 861,728 additional shares of common stock acquirable within 60 days, each of which is subject to a Blocker Limitation. However, Mr. Mirman’s percentage ownership is currently in excess of such Blocker Limitations, and as a result, such Blocker Securities have been excluded from the table. These Blocker Securities consist of the following: (i) 556,541 shares of common stock issuable upon exercise of warrants held by the Bralina Group and (ii) 305,187 shares of common stock issuable upon exercise of warrants held directly by Mr. Mirman.
As noted above in this registration statement under the heading “Equity Grants for Fiscal Year 2016,” in June 2017 the compensation committee approved the rescission of 500,000 options granted to Mr. Mirman in December 2016 and 250,000 options granted to Mr. Mirman in June 2016. The rescission of these options occurred after the determination date for this beneficial ownership table and, therefore, is not reflected in the table.
| (4) | Including the Blocker Securities, and ignoring the Blocker Limitation, Mr. Mirman beneficially owns a total 4,080,055 shares of common stock, which represents 7.8% of our currently issued and outstanding common stock. |
| (5) | Consists of: (i) 1,259,388 shares of common stock held directly by Mr. Ormand; (ii) 1,242,334 shares of common stock held by Perugia Investments L.P. (“Perugia”); and (iii) 1,176,364 shares of common stock held by The Bruin Trust, an irrevocable trust managed by Jerry Ormand, Mr. Ormand’s brother, as trustee and whose beneficiaries include the adult children of Mr. Ormand. Mr. Ormand is the manager of Perugia and has sole voting and dispositive power over the securities held by Perugia. |
| (6) | Represents shares of common stock subject to options exercisable within 60 days. |
In addition, Mr. Ormand beneficially owns an aggregate of 993,102 additional shares of common stock acquirable within 60 days, each of which is subject to a Blocker Limitation. However, Mr. Ormand’s percentage ownership is currently in excess of such Blocker Limitations, and as a result, such Blocker Securities have been excluded from the table. These Blocker Securities consist of the following: (i) 533,102 shares of common stock issuable upon exercise of warrants held by Perugia; and (ii) 460,000 shares of common stock issuable upon exercise of warrants held by The Bruin Trust.
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| (7) | Including the Blocker Securities, and ignoring the Blocker Limitation, Mr. Ormand beneficially owns a total 4,786,189 shares of common stock, which represents 9.3% of our currently issued and outstanding common stock. |
| (8) | Represents shares of common stock subject to options exercisable within 60 days. |
| (9) | Represents shares of common stock subject to options exercisable within 60 days. |
| (10) | Represents shares of common stock subject to options exercisable within 60 days. |
| (11) | Consists of: (i) 45,000 shares of common stock subject to options exercisable within 60 days; and (ii) 74,575 shares of common stock issuable upon exercise of warrants. The effect of any Blocker Limitation with respect to the securities described here has been excluded, as Mr. Brandolini is below the threshold of any such limitation. |
| (12) | Consists of: (i) 31,667 shares of common stock subject to options exercisable within 60 days; and (ii) 125,001 shares of common stock issuable upon exercise of warrants. The effect of any Blocker Limitation with respect to the securities described here has been excluded, as Mr. Dawson is below the threshold of any such limitation. |
| (13) | Consists of: (i) 38,333 shares of common stock subject to options exercisable within 60 days; (ii) 105,188 shares of common stock issuable upon exercise of warrants. The effect of any Blocker Limitation with respect to the securities described here has been excluded, as General McPeak is below the threshold of any such limitation. |
| (14) | As indicated in the above footnotes, this amount excludes an aggregate of 1,854,830 additional shares of common stock acquirable within 60 days, which are subject to Blocker Limitations. |
| (15) | Including the Blocker Securities, and ignoring the Blocker Limitation, the directors and officers as a group beneficially own a total of 11,684,863 shares of common stock, which represents 21.4% of our currently issued and outstanding common stock. |
| (16) | Collectively, the shares of Common Stock reported herein in which Bryan Ezralow has shared voting and dispositive power over such shares is an aggregate of 2,092,723 shares. Such shares are held directly by (a) the Ezralow Family Trust u/t/d 12/9/1980 (the “Family Trust”) in the amount of 94,106 shares, where Bryan Ezralow as a co-trustee of the Family Trust shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; (b) the Ezralow Marital Trust u/t/d 1/12/2002 (the “Marital Trust”) in the amount of 101,571 shares, where Bryan Ezralow as a co-trustee of the Marital Trust shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; (c) Elevado Investment Company, LLC, a Delaware limited liability company (“Elevado Investment”), in the amount of 416,252 shares, where Bryan Ezralow as a co-trustee and manager, respectively, of the two trusts and limited liability company that comprise the managing members of Elevado Investment, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; (d) EMSE LLC (“EMSE”), a Delaware limited liability company, in the amount of 495,674 shares, where Bryan Ezralow, as a manager of EMSE, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; (e) EZ Colony Partners, LLC, a Delaware limited liability company (“EZ Colony”), in the amount of 985,117 shares, where Bryan Ezralow as the sole trustee of one of the trusts that is a manager of EZ Colony, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; and (f) EZ MM&B Holdings, LLC, a Delaware limited liability company (“EZ MM&B”), in the amount of 3 shares, where Bryan Ezralow as the sole trustee of one of the trusts that is a manager of EZ MM&B, and as a co-trustee and manager, respectively, of the two trusts and limited liability company that comprise the managing members of one of the other managers of EZ MM&B, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares. |
Collectively, the shares of Common Stock reported herein in which Bryan Ezralow has sole voting and dispositive power over such shares are 1,393,953 shares. Such shares are held directly by (a) the Bryan Ezralow 1994 Trust u/t/d/12/22/1994, Bryan Ezralow, Trustee (the “Bryan Trust”) in the amount of 1,258,098 shares, where Bryan Ezralow as sole trustee of the Bryan Trust has sole voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; and (b) the Marc Ezralow Irrevocable Trust u/t/d 6/1/2004 (the “Irrevocable Trust”) in the amount of 135,855 shares, where Bryan Ezralow as sole trustee of the Irrevocable Trust has sole voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares.
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| (17) | Represents shares of common stock subject to warrants exercisable within 60 days. |
In addition, Bryan Ezralow beneficially owns an aggregate of 836,712 additional shares of common stock acquirable within 60 days, each of which is subject to a Blocker Limitation. However, the percentage ownership by Bryan Ezralow is currently in excess of such Blocker Limitations, and as a result, such Blocker Securities have been excluded from the table. These Blocker Securities consist of the following: (i) 295,455 shares of common stock issuable upon the exercise of warrants, held by the Bryan Trust; (ii) 43,182 shares of common stock issuable upon the exercise of warrants, held by the Irrevocable Trust; (iii) 125,889 shares of common stock issuable upon the exercise of warrants, held by Elevado; (iv) 266,088 shares of common stock issuable upon the exercise of warrants, held by EZ Colony; (v) 43,912 shares of common stock issuable upon the exercise of warrants, held by the Marital Trust; (vi) 41,285 shares of common stock issuable upon the exercise of warrants, held by the Family Trust; and (vii) 20,899 shares of common stock issuable upon the exercise of warrants, held by EMSE.
| (18) | Collectively, the shares of Common Stock reported herein in which Marc Ezralow has shared voting and dispositive power over such shares are an aggregate of 2,092,723 shares. Such shares are held directly by (a) the Ezralow Family Trust u/t/d 12/9/1980 (the “Family Trust”) in the amount of 94,106 shares, where Marc Ezralow, as a co-trustee of the Family Trust, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; (b) the Ezralow Marital Trust u/t/d 1/12/2002 (the “Marital Trust”) in the amount of 101,571 shares, where Marc Ezralow, as a co-trustee of the Marital Trust, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; (c) Elevado Investment Company, LLC, a Delaware limited liability company (“Elevado Investment”), in the amount of 416,252 shares, where Marc Ezralow as a co-trustee and manager, respectively, of the two trusts and limited liability company that comprise the managing members of Elevado Investment, shares voting and dispositive power over such shares, and thus, be deemed to beneficially own such shares; (d) EMSE LLC (“EMSE”), a Delaware limited liability company, in the amount of 495,674 shares, where Marc Ezralow, as a manager of EMSE shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; (e) EZ Colony Partners, LLC, a Delaware limited liability company (“EZ Colony”), in the amount of 985,117 shares, where Marc Ezralow as the sole trustee of one of the trusts that is a manager of EZ Colony, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; and (f) EZ MM&B Holdings, LLC, a Delaware limited liability company (“EZ MM&B”) in the amount of 3 shares, where Marc Ezralow as the sole trustee of one of the trusts that is a manager of EZ MM&B, and as a co-trustee and manager, respectively, of the two trusts and limited liability company that comprise the managing members of one of the other managers of EZ MM&B, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares. |
Collectively, the shares of Common Stock reported herein in which Marc Ezralow has sole voting and dispositive power over said Common Stock are 690,836 shares. Such shares are held directly by (a) the Marc Ezralow 1997 Trust u/t/d/11/26/1997, Marc Ezralow, Trustee (the “Marc Trust”) in the amount of 554,981 shares, where Marc Ezralow as sole trustee of the Marc Trust has sole voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; and (b) the SPA Trust u/t/d 9/13/2004 (the “SPA Trust”), in the amount of 135,855 shares, where Marc Ezralow as sole trustee of the SPA Trust has sole voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares.
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| (19) | Represents shares of common stock subject to warrants exercisable within 60 days. |
In addition, Marc Ezralow beneficially owns an aggregate of 711,710 additional shares of common stock acquirable within 60 days, each of which is subject to a Blocker Limitation. However, the percentage ownership by Marc Ezralow is currently in excess of such Blocker Limitations, and as a result, such Blocker Securities have been excluded from the table. These Blocker Securities consist of the following: (i) 43,182 shares of common stock issuable upon exercise of warrants, held the SPA Trust; (ii) 170,455 shares of common stock issuable upon exercise of warrants, held by the 1997 Trust; (iii) 125,889 shares of common stock issuable upon the exercise of warrants, held by Elevado; (iv) 266,088 shares of common stock issuable upon the exercise of warrants, held by EZ Colony; (v) 43,912 shares of common stock issuable upon the exercise of warrants, held by the Marital Trust; (vi) 41,285 shares of common stock issuable upon the exercise of warrants, held by the Family Trust; and (vii) 20,899 shares of common stock issuable upon the exercise of warrants, held by EMSE..
| (20) | Based on the Schedule 13D filed on May 19, 2017, this consists of: (i) 1,630,652 shares of common stock held by J. Steven Emerson Roth IRA Pershing LLC as Custodian (“Roth IRA Pershing”); (ii) 1,371,067 shares of common stock held by J. Steven Emerson IRA Rollover II Pershing LLC as Custodian (“IRA Rollover II Pershing”); (iii) 430,945 shares of common stock held by Emerson Partners (“Emerson”); (iv) 583,237 shares of common stock held directly by J. Steven Emerson; (v) 48,173 shares of common stock held by the Emerson Family Foundation. J. Steven Emerson is the natural person with ultimate voting or investment control over the shares of common stock held by each of Roth IRA Pershing, IRA Rollover II Pershing, Emerson and the Emerson Family Foundation. |
| (21) | Represents shares of common stock subject to warrants exercisable within 60 days. |
| (22) | Based on the Schedule 13G filed on May 30, 2017. The natural person with ultimate voting or investment control over the shares of common stock held is Warren Irwin. |
| (23) | Rosseau Asset Management (“Rosseau”) beneficially owns an aggregate of 1,136,364 additional shares of common stock acquirable within 60 days, each of which is subject to a Blocker Limitation. However, Rosseau’s percentage ownership is currently in excess of such Blocker Limitations, and as a result, such Blocker Securities have been excluded from the table. These Blocker Securities consist of 1,136,364 shares of common stock issuable upon exercise of warrants. |
| (24) | The natural person with ultimate voting or investment control over the shares of common stock held is Chris Hercus. |
| (25) | LOGiQ Capital 2016 (“LOGiQ”) beneficially owns an aggregate of 1,250,001 additional shares of common stock acquirable within 60 days, each of which is subject to a Blocker Limitation. However, LOGiQ’s percentage ownership is currently in excess of such Blocker Limitations, and as a result, such Blocker Securities have been excluded from the table. These Blocker Securities consist of 1,250,001 shares of common stock issuable upon exercise of warrants. |
| (26) | Based on the Schedule 13G filed on May 5, 2017. The natural person with ultimate voting or investment control over the shares of common stock held is John Thiessen. |
| (27) | Represents shares of common stock which may be issued pursuant to the conversion of the initial term loans within 60 days. |
In addition, Värde Partners, Inc. may be deemed to own an aggregate of 10,201,067 additional shares of common stock acquirable when requisite stockholder approval is received. Värde Partners, Inc. is the ultimate owner of the general partners (the “General Partners”), of each of The Värde Fund XI (Master), L.P., The Värde Fund XII (Master), L.P.; The Värde Master Skyway Fund, L.P., The Värde Fund VI-A, L.P., Värde Investment Partners, L.P., and Värde Investment Partners (Offshore) Master, L.P. (the “Värde Entities”), or of the General Partners’ managing members. Mr. George Hicks is the chief executive officer of Värde Partners, Inc. As such each of Värde Partners, Inc. and Mr. Hicks may be deemed to have beneficial ownership of the shares owned by each of the Värde Entities. Each of Värde Partners, Inc. and Mr. Hicks disclaims beneficial ownership of the securities held indirectly through the Värde Entities except to the extent of their pecuniary interest therein, and this disclosure shall not be deemed an admission that any such reporting person is the beneficial owner for purposes of this registration statement or for any other purpose.
To Lilis’s knowledge, except as noted above, no person or entity is the beneficial owner of 5% or more of Lilis’s common stock.
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The following description of Lilis’s capital stock is derived from its articles of incorporation and bylaws as well as relevant provisions of applicable law. Lilis’s authorized capital stock consists of 100,000,000 shares of common stock, par value $0.0001 per share, and 10,000,000 shares of preferred stock, par value $0.0001 per share.
Common Stock
Except as otherwise required by law or provided in any designation of rights of preferred stock, the holders of Lilis’s common stock are entitled to one vote per share on all matters submitted to a vote of the stockholders, including the election of directors. Generally, all matters to be voted on by stockholders must be approved by a majority (or, in the case of election of directors, by a plurality) of the votes entitled to be cast by all shares of common stock that are present in person or represented by proxy, subject to any voting rights granted to holders of preferred stock. Except as otherwise provided by law, and subject to any voting rights granted holders of preferred stock, amendments to Lilis’s articles of incorporation generally must be approved by a majority of the votes entitled to be cast by all outstanding shares of common stock. Lilis’s articles of incorporation and bylaws do not provide for cumulative voting in the election of directors. Except as otherwise required by law or provided in any designation of rights of preferred stock, the holders of Lilis’s common stock are entitled to receive dividends, if any, as may be declared from time to time by Lilis’s board of directors. In the event that Lilis liquidates, dissolves or winds-up, the holders of Lilis’s common stock are entitled to share ratably in all of the assets that remain after Lilis pays its liabilities. This right is subject, however, to the prior distribution rights of any outstanding preferred stock. The terms of Lilis’s common stock do not include any preemptive, conversion or subscription rights, nor any redemption or sinking fund provisions.
Preferred Stock
Our Board is authorized by our articles of incorporation to establish classes or series of preferred stock and fix the designation, powers, preferences and rights of the shares of each such class or series and the qualifications, limitations or restrictions thereof without any further vote or action by our stockholders. Any shares of preferred stock so issued could have priority over our common stock with respect to dividend or liquidation rights. Any future issuance of preferred stock may have the effect of delaying, deferring or preventing a change in our control without further action by our stockholders and may adversely affect the voting and other rights of the holders of our common stock.
The issuance of shares of preferred stock, or the issuance of rights to purchase such shares, could be used to discourage an unsolicited acquisition proposal. For instance, the issuance of a series of preferred stock might impede a business combination by including class voting rights that would enable a holder to block such a transaction. In addition, under certain circumstances, the issuance of preferred stock could adversely affect the voting power of holders of our common stock. Although our Board is required to make any determination to issue preferred stock based on its judgment as to the best interests of our stockholders, our Board could act in a manner that would discourage an acquisition attempt or other transaction that some, or a majority, of our stockholders might believe to be in their best interests or in which such stockholders might receive a premium for their stock over the then market price of such stock.
Authorized but Unissued Shares
The authorized but unissued shares of common stock are available for future issuance without stockholder approval, unless otherwise required by law or applicable stock exchange rules. Additional authorized but unissued shares may be used for a variety of corporate purposes, including future public offerings to raise additional capital, corporate acquisitions and employee benefit plans. The existence of authorized but unissued shares could hinder or discourage an attempt to obtain control of us by means of a proxy contest, tender offer, merger or otherwise.
Anti-Takeover Provisions Under The Nevada Revised Statutes
Business Combinations
Sections 78.411 to 78.444 of the Nevada revised statues (the “NRS”) prohibit a Nevada corporation from engaging in a “combination” with an “interested stockholder” for three years following the date that such person becomes an interested shareholder and place certain restrictions on such combinations even after the expiration of the three-year period. With certain exceptions, an interested stockholder is a person or group that owns 10% or more of the corporation’s outstanding voting power (including stock with respect to which the person has voting rights and any rights to acquire stock pursuant to an option, warrant, agreement, arrangement, or understanding or upon the exercise of conversion or exchange rights) or is an affiliate or associate of the corporation and was the owner of 10% or more of such voting stock at any time within the previous three years.
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A Nevada corporation may elect not to be governed by Sections 78.411 to 78.444 by a provision in its articles of incorporation. We have such a provision in our articles of incorporation, as amended, pursuant to which we have elected to opt out of Sections 78.411 to 78.444; therefore, these sections do not apply to us.
Control Shares
Nevada law also seeks to impede “unfriendly” corporate takeovers by providing in Sections 78.378 to 78.3793 of the NRS that an “acquiring person” shall only obtain voting rights in the “control shares” purchased by such person to the extent approved by the other shareholders at a meeting. With certain exceptions, an acquiring person is one who acquires or offers to acquire a “controlling interest” in the corporation, defined as one-fifth or more of the voting power. Control shares include not only shares acquired or offered to be acquired in connection with the acquisition of a controlling interest, but also all shares acquired by the acquiring person within the preceding 90 days. The statute covers not only the acquiring person but also any persons acting in association with the acquiring person.
A Nevada corporation may elect to opt out of the provisions of Sections 78.378 to 78.3793 of the NRS. We have no provision in our articles of incorporation pursuant to which we have elected to opt out of Sections 78.378 to 78.3793; therefore, these sections do apply to us.
Removal of Directors
Section 78.335 of the NRS provides that 2/3rds of the voting power of the issued and outstanding shares of the Company are required to remove a Director from office. As such, it may be more difficult for shareholders to remove Directors due to the fact the NRS requires greater than majority approval of the shareholders for such removal.
Listing
Our shares of common stock are currently listed on the NYSE MKT under the symbol “LLEX.”
Transfer Agent and Registrar
The transfer agent and registrar of Lilis’s common stock is Corporate Stock Transfer, Inc., located at 3200 E. Cherry Creek Drive South, #430, Denver, CO 80209, telephone: 210-999-5400.
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The validity of the common stock offered by this prospectus will be passed upon for us by Fennemore Craig, P.C., Reno, Nevada.
The consolidated financial statements of Lilis Energy, Inc. as of December 31, 2016 and 2015 and for the years then ended have been included in this prospectus herein in reliance upon the report of Marcum LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as an expert in accounting and auditing.
The consolidated financial statements of Brushy Resources, Inc. (formerly known as Starboard Resources, Inc.) as of December 31, 2015 and for the year then ended have been included in this prospectus herein in reliance upon the report of Marcum LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.
The consolidated financial statements of Brushy Resources, Inc. (formerly known as Starboard Resources, Inc.) as of and for the year ended December 31, 2014, have been included herein in reliance upon the report of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.
Information with respect to the estimates of our proved oil and gas reserves for the years ended December 31, 2016 that are included in this prospectus was prepared by Cawley, Gillespie & Associates, Inc., an independent reserve engineering firm, and is included herein in reliance upon their authority as experts in reserves.
WHERE YOU CAN FIND MORE INFORMATION
We have filed with the SEC a registration statement on Form S-1 under the Securities Act with respect to the common stock offered in this prospectus. This prospectus, filed as part of the registration statement, does not contain all of the information set forth in the registration statement and its exhibits and schedules, portions of which have been omitted as permitted by the rules and regulations of the SEC. For further information about us and our securities, we refer you to the registration statement and to its exhibits and schedules. Statements in this prospectus about the contents of any contract, agreement or other document are not necessarily complete and, in each instance, we refer you to the copy of such contract, agreement or document filed as an exhibit to the registration statement, with each such statement being qualified in all respects by reference to the document to which it refers. Anyone may inspect and copy the registration statement and its exhibits and schedules at the Public Reference Room the SEC maintains at 100 F Street, NE, Washington, D.C. 20549. You may obtain further information about the operation of the SEC’s Public Reference Room by calling the SEC at 1-800-SEC-0330. You may also inspect the registration statement and its exhibits and schedules and other information without charge at the website maintained by the SEC. The address of this site is www.sec.gov.
We also file periodic reports, proxy statements and other information with the SEC. These reports, proxy statements and other information will be available for inspection and copying at the public reference room and website of the SEC referred to above. We also maintain a website at www.lilisenergy.com, by which you may access these materials free of charge as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. The information that is contained on, or that may be accessed through, our website is not a part of this prospectus. We have included our website in this prospectus solely as an inactive textual reference.
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In this prospectus, the following abbreviation and terms are used:
Bbl. Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude, condensate or natural gas liquids.
Bcf. Billion cubic feet of natural gas.
Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one barrel of crude oil or condensate.
BLM. The Bureau of Land Management of the United States Department of the Interior.
BOE. One barrel of crude oil equivalent, determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.
BOE/d. Barrels of oil equivalent per day.
BO/d. Barrel of oil per day.
BTU or British Thermal Unit. The quantity of heat required to raise the temperature of one pound mass of water by 28.5 to 59.5 degrees Fahrenheit.
Completion. Installation of permanent equipment for production of oil or natural gas.
Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure but that, when produced, is in the liquid phase at surface pressure and temperature.
Development well. A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.
Drilling locations. Total gross locations specifically quantified by management to be included in our multi-year drilling activities on existing acreage. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors.
Dry well or dry hole. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
Exploratory well. A well drilled to find a new field or to find a new reservoir. Generally an exploratory well in any well that is not a development well, an extension well, a service well or a stratigraphic well.
FERC. The Federal Energy Regulatory Commission.
Field. An area consisting of either a single reservoir or multiple reservoirs all grouped on or related to the same geological structural feature and/or stratigraphic condition.
Formation. An identifiable layer of subsurface rocks named after its geographical location and dominant rock type.
Gross acres, gross wells, or gross reserves. A well, acre or reserve in which we own a working interest, reported at the 100% or 8/8ths level. For example, the number of gross wells is the total number of wells in which we own a working interest.
Lease. A legal contract that specifies the terms of the business relationship between an energy company and a landowner or mineral rights holder on a particular tract of land.
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Leasehold. Mineral rights leased in a certain area to form a project area.
Mbbls. One thousand barrels of crude oil or other liquid hydrocarbons.
Mboe. One thousand barrels of crude oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Mcf. One thousand cubic feet of natural gas.
Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
MMbtu. One million British Thermal Units.
MMcf. One million cubic feet of natural gas.
Net acres or net wells. The sum of fractional ownership working interests in gross acres or gross wells. The number of net acres or wells is the sum of the fractional working interests owned in gross acres or wells expressed as whole numbers and fractions of whole numbers.
NGL. Natural gas liquids, or liquid hydrocarbons found as a by-product of natural gas.
Overriding royalty interest. Is similar to a basic royalty interest except that it is created out of the working interest. For example, an operator possesses a standard lease providing for a basic royalty to the lessor or mineral rights owner of 1/8 of 8/8. This then entitles the operator to retain 7/8 of the total oil and natural gas produced. The 7/8 in this case is the 100% working interest the operator owns. This operator may assign his working interest to another operator subject to a retained 1/8 overriding royalty. This would then result in a basic royalty of 1/8, an overriding royalty of 1/8 and a working interest of 3/4. Overriding royalty interest owners have no financial or other obligation or responsibility for developing and operating the property. The only expenses borne by the overriding royalty owner are a share of the production or severance taxes and sometimes costs incurred to make the oil or gas salable.
Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.
Production. Natural resources, such as oil or gas, flowed or pumped out of the ground.
Productive well. A producing well or a well that is mechanically capable of production.
Proved developed oil and gas reserves. Proved developed oil and gas reserves are proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Proved reserves. Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
Proved undeveloped reserves. Proved undeveloped oil and gas reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
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Project. A targeted development area where it is probable that commercial oil and/or gas can be produced from new wells.
Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
PV-10 (Present value of future net cash flow). The present value of estimated future revenues to be generated from the production of estimated proved reserves, net of capital expenditures and operating expenses, using the simple 12 month arithmetic average of first of the month prices and current costs (unless such prices or costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expenses, depreciation, depletion and amortization or impairment, discounted using an annual discount rate of 10%. While this non-GAAP measure does not include the effect of income taxes as would the use of the standardized measure calculation, we believe it provides an indicative representation of the relative value of our company on a comparative basis to other companies and from period to period.
Recompletion. The process of re-entering an existing well bore that is either producing or not producing and modifying the existing completion and/or completing new reservoirs in an attempt to establish new production or increase or re-activate existing production.
Reserves. Estimated remaining quantities of oil, natural gas and gas liquids anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
Reservoir. A subsurface formation containing a natural accumulation of producible natural gas and/or oil that is naturally trapped by impermeable rock or other geologic structures or water barriers and is individual and separate from other reservoirs.
Secondary Recovery. A recovery process that uses mechanisms other than the natural pressure or fluid drive of the reservoir, such as gas injection or water flooding, to produce residual oil and natural gas remaining after the primary recovery phase.
Shut-in. A well suspended from production or injection but not abandoned.
Standardized measure. The present value of estimated future cash flows from proved oil and natural gas reserves, less future development, abandonment, production and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.
Successful. A well is determined to be successful if it is producing oil or natural gas in paying quantities.
Undeveloped acreage. Leased acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas regardless of whether such acreage contains proved reserves.
Water-flood. A method of secondary recovery in which water is injected into the reservoir formation to maintain or increase reservoir pressure and displace residual oil and enhance hydrocarbon recovery.
Working interest. The operating interest that gives the lessees/owners the right to drill, produce and conduct operating activities on the property, and to receive a share of the production revenue, subject to all royalties, overriding royalties and other burdens, all development costs, and all risks in connection therewith.
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Lilis Energy, Inc. and Subsidiaries
| F-1 |
LILIS ENERGY, INC.
(In thousands, except share and per share data)
| March 31, | December 31, | |||||||
| 2017 | 2016 | |||||||
| (Unaudited) | ||||||||
| ASSETS | ||||||||
| Current assets: | ||||||||
| Cash and cash equivalents | $ | 20,416 | $ | 11,738 | ||||
| Accounts receivables, net of allowance of $78 and $106, respectively | 5,917 | 2,247 | ||||||
| Prepaid expenses and other current assets | 1,520 | 767 | ||||||
| Total current assets | 27,853 | 14,752 | ||||||
| Oil and gas properties, full cost method of accounting | ||||||||
| Unproved | 27,176 | 24,461 | ||||||
| Proved | 27,280 | 69,809 | ||||||
| Less: accumulated depreciation, depletion, amortization and impairment | (6,575 | ) | (55,771 | ) | ||||
| Total oil and gas properties, net | 47,881 | 38,499 | ||||||
| Other property and equipment, net | 55 | 52 | ||||||
| Other assets | 325 | 216 | ||||||
| Total other assets | 380 | 268 | ||||||
| Total assets | $ | 76,114 | $ | 53,519 | ||||
The accompanying notes are an integral part of these financial statements.
| F-2 |
LILIS ENERGY, INC.
Consolidated Balance Sheets
(In thousands, except share and per share data)
| March 31, | December 31, | |||||||
| 2017 | 2016 | |||||||
| (Unaudited) | ||||||||
| LIABILITIES, REDEEMABLE PREFERRED STOCK AND STOCKHOLDERS' EQUITY | ||||||||
| Current liabilities: | ||||||||
| Accounts payable | $ | 4,390 | $ | 5,166 | ||||
| Accrued liabilities | 7,005 | 2,706 | ||||||
| Dividends payable | 948 | 808 | ||||||
| Asset retirement obligations | 331 | 338 | ||||||
| Current portion of long-term debt | 17 | 17 | ||||||
| Total current liabilities | 12,691 | 9,035 | ||||||
| Asset retirement obligations | 938 | 919 | ||||||
| Long-term debt, net of current portion | 36,137 | 30,226 | ||||||
| Long-term derivative liabilities | 683 | 1,400 | ||||||
| Total liabilities | 50,449 | 41,580 | ||||||
| Commitments and contingencies (Note 12) | ||||||||
| Conditionally redeemable 6% preferred stock, $0.0001 par value, 7,000 shares authorized, 2,000 shares issued and outstanding with a liquidation preference of $2,270 and $2,240 at March 31, 2017 and December 31, 2016, respectively | 1,915 | 1,874 | ||||||
| Stockholders’ Equity: | ||||||||
| Series B Convertible Preferred stock, $0.0001 par value; stated rate $1,000; 20,000 shares authorized; 14,379 and 16,828 shares issued and outstanding at March 31, 2017 and December 31, 2016, respectively, with a liquidation preference of $20,686 and $20,627 at March 31, 2017 and December 31, 2016, respectively. | 10,983 | 13,432 | ||||||
| Common stock, $0.0001 par value; 100,000,000 shares authorized, 30,233,397 and 20,918,901 shares issued and outstanding as of March 31, 2017 and December 31, 2016, respectively. | 3 | 2 | ||||||
| Additional paid-in capital | 244,969 | 219,837 | ||||||
| Accumulated deficit | (232,205 | ) | (223,206 | ) | ||||
| Total stockholders’ equity | 23,750 | 10,065 | ||||||
| Total liabilities, redeemable preferred stock and stockholders’ equity | $ | 76,114 | $ | 53,519 | ||||
The accompanying notes are an integral part of these financial statements.
| F-3 |
LILIS ENERGY, INC.
Consolidated Statements of Operations
(In thousands, except share and per share data)
(Unaudited)
| Three Months Ended March 31, | ||||||||
| 2017 | 2016 | |||||||
| Oil, natural gas and natural gas liquid sales | $ | 3,233 | $ | 42 | ||||
| Costs and expenses: | ||||||||
| Production costs | 929 | 37 | ||||||
| Production taxes | 142 | 2 | ||||||
| General and administrative | 9,311 | 1,664 | ||||||
| Depreciation, depletion and amortization | 1,124 | 20 | ||||||
| Accretion of asset retirement obligations | 22 | 3 | ||||||
| Total operating expenses | 11,528 | 1,726 | ||||||
| Loss from operations | (8,295 | ) | (1,684 | ) | ||||
| Other income (expense): | ||||||||
| Other income | 8 | (1 | ) | |||||
| Gain (loss) in fair value of derivative instruments | 346 | (68 | ) | |||||
| Loss in fair value of conditionally redeemable 6% preferred stock | (41 | ) | (324 | ) | ||||
| Interest expense | (774 | ) | (1,334 | ) | ||||
| Total other income (expense) | (461 | ) | (1,727 | ) | ||||
| Net loss before income tax | (8,756 | ) | (3,411 | ) | ||||
| Income tax expense | - | - | ||||||
| Net loss | (8,756 | ) | (3,411 | ) | ||||
| Dividends on redeemable preferred stock | (30 | ) | (30 | ) | ||||
| Dividend on Series B Convertible Preferred stock | (213 | ) | (150 | ) | ||||
| Net loss attributable to common stockholders | $ | (8,999 | ) | $ | (3,591 | ) | ||
| Net loss per common share basic and diluted | $ | (0.32 | ) | $ | (0.12 | ) | ||
| Weighted average common shares outstanding: | ||||||||
| Basic and diluted | 27,847,651 | 29,152,369 | ||||||
The accompanying notes are an integral part of these financial statements.
| F-4 |
LILIS ENERGY, INC.
Consolidated Statements of Cash Flows
(In thousands)
(Unaudited)
| Three Months Ended March 31, | ||||||||
| 2017 | 2016 | |||||||
| Cash flows from operating activities: | ||||||||
| Net loss | $ | (8,756 | ) | $ | (3,411 | ) | ||
| Adjustments to reconcile net loss to net cash used in operating activities: | ||||||||
| Equity instruments issued for services and compensation | 2,779 | 369 | ||||||
| Amortization of deferred financing cost | 127 | 27 | ||||||
| Accretion of debt discount | 115 | 794 | ||||||
| Loss in fair value of derivative instruments | (346 | ) | 68 | |||||
| Loss in fair value of conditionally redeemable 6% preferred stock | 41 | 324 | ||||||
| Depreciation, depletion, amortization | 1,124 | 20 | ||||||
| Accretion of asset retirement obligation | 22 | 3 | ||||||
| Changes in operating assets and liabilities: | ||||||||
| Accounts receivable | (3,671 | ) | (34 | ) | ||||
| Prepaid and other assets | (216 | ) | (312 | ) | ||||
| Accounts payable, accrued expenses and other liabilities | 3,527 | 1,370 | ||||||
| Net cash used in operating activities | (5,254 | ) | (782 | ) | ||||
| Cash flows from investing activities: | ||||||||
| Cash advance to Brushy Resources, Inc. | - | (608 | ) | |||||
| Proceeds from sale of DJ Basin properties | 1,082 | - | ||||||
| Restricted cash | (645 | ) | 9 | |||||
| Capital expenditures | (11,360 | ) | - | |||||
| Net cash used in investing activities | (10,923 | ) | (599 | ) | ||||
| Cash flows from financing activities: | ||||||||
| Proceeds from term loan, net of financing costs | 6,706 | - | ||||||
| Proceeds from issuance of convertible notes | - | 1,300 | ||||||
| Proceeds from warrant exercise | 71 | - | ||||||
| Proceeds from exercise of stock options | 228 | - | ||||||
| Proceeds from private placement, net of financing costs and subscription receivable | 17,854 | - | ||||||
| Repayment of notes payable | (4 | ) | - | |||||
| Net cash provided by financing activities | 24,855 | 1,300 | ||||||
| Increase (decrease) in cash | 8,678 | (81 | ) | |||||
| Cash at beginning of period | 11,738 | 110 | ||||||
| Cash at end of period | $ | 20,416 | $ | 29 | ||||
| Supplemental disclosure: | ||||||||
| Cash paid for interest | $ | 926 | $ | 87 | ||||
The accompanying notes are an integral part of these financial statements.
| F-5 |
LILIS ENERGY, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
AS OF MARCH 31, 2017
(UNAUDITED)
NOTE 1 - ORGANIZATION
Lilis Energy, Inc. (“Lilis”, “Lilis Energy” and the “Company”) is an independent oil and gas exploration and production company focused on the Delaware Basin in Reeves, Winkler and Loving Counties, Texas and Lea County, New Mexico.
On June 23, 2016, the Company completed a merger transaction with Brushy Resources, Inc. (“Brushy”) and effected a 1-for-10 reverse stock split of its Common Stock (the “Reverse Split”). The accompanying consolidated financial statements give retroactive effect to the Reverse Split for all periods presented.
All references to production, sales volumes and reserves quantities are net to the Company’s interest unless otherwise indicated.
NOTE 2 - MANAGEMENT PLANS AND LIQUIDITY
The Company has reported net operating losses during the three months ended March 31, 2017 and for the past five years. As a result, in 2016 and 2017 the Company funded its operations and the merger with Brushy through additional debt and equity financing. On September 29, 2016, the Company entered into a First Lien Credit Agreement (defined below) that provides for a three-year, senior, secured term loan with initial aggregate principal commitments of $31.0 million and a maximum facility size of $50 million (the “First Lien Term Loan”). On February 7, 2017, pursuant to the terms of the First Lien Credit Agreement, the Company exercised the accordion advance feature increasing the aggregate principal amount outstanding under the term loan from $31.0 million to $38.1 million.
As of March 31, 2017, the Company had a working capital balance and a cash balance of approximately $15.2 million and $20.4 million, respectively. Since that date, the Company has bolstered its cash balance through the funding of $15 million under a first and second amendment to the First Lien Credit Agreement which closed on April 24, 2017, that was structured as a new tranche under the First Lien Term Loan, and the funding through a new, four-year, $125 million, convertible, Second Lien Term Loan (defined below), with $80 million drawn immediately and additional availability of $45 million that provides discretionary funding for leasing activity and acreage acquisitions under certain conditions, which closed on April 26, 2017. The Company 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. Due in part to these transactions, the Company believes that it will have sufficient capital to operate over the next 12 months from the date of the filing of this quarterly report.
NOTE 3 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND ESTIMATES
Principles of Consolidation
The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. As of March 31, 2017, the Company’s wholly owned subsidiaries include Brushy Resources, Inc (“Brushy”), ImPetro Operating, LLC (“ImPetro Operating”), ImPetro Resources, LLC (“Resources”), and Lilis Operating Company, LLC (“Lilis Operating”). All significant intercompany accounts and transactions have been eliminated in consolidation.
| F-6 |
Interim Financial Statements
The accompanying unaudited consolidated financial statements should be read in conjunction with the financial statements and related notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016. The Company’s accounting policies are described in the Notes to Financial Statements in its Annual Report on Form 10-K for the year ended December 31, 2016, and updated, as necessary, in this Quarterly Report on Form 10-Q.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”) requires the Company 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. Although actual results may differ from these estimates under different assumptions or conditions, the Company believes that its estimates are reasonable.
The most significant financial estimates are associated with the Company’s estimated volumes of proved oil and natural gas reserves, asset retirement obligations, assessments of impairment on oil and gas properties, fair value of financial instruments, including derivative liabilities and conditionally redeemable preferred stock, depreciation and accretion, income taxes and contingencies.
Reclassifications
Certain reclassifications have been made to the prior period financial statements to conform to the current period presentation. These reclassifications have no effect on the Company’s previously reported results of operations. For the three months ended March 31, 2016, change in fair value on executive bonus of approximately $222,000 was originally presented in the adjustments to reconcile net loss to net cash used in operating activities in the Consolidated Statement of Cash Flows. The executive bonus liabilities were written off during the three months ended March 31, 2016. As a result, this amount is reclassified to accrued liabilities under changes in operating assets and liabilities. This change in classification does not have any effect on the previously reported Consolidated Statement of Cash Flows for the three months ended March 31, 2016.
Oil and Gas Producing Activities
The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration, non-production related development and acquisition of oil and natural gas reserves are capitalized. Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling, developing and completing productive wells and/or plugging and abandoning non-productive wells, and any other costs directly related to acquisition and exploration activities. Proceeds from property sales are generally applied as a credit against capitalized exploration and development costs, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of proved reserves.
Depletion of exploration and development costs and depreciation of wells and tangible production assets is computed using the units-of-production method based upon estimated proved oil and gas reserves. Costs included in the depletion base to be amortized include (a) all proved capitalized costs including capitalized asset retirement costs net of estimated salvage values, less accumulated depletion, (b) estimated future development costs to be incurred in developing proved reserves; and (c) estimated decommissioning and abandonment/restoration costs, net of estimated salvage values, that are not otherwise included in capitalized costs.
The costs of undeveloped acreage are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties. When proved reserves are assigned to such properties or one or more specific properties are deemed to be impaired, the cost of such properties or the amount of the impairment is added to the full cost pool which is subject to depletion calculations.
Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the sum of the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves and the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are not subject to amortization. Should capitalized costs exceed this ceiling, an impairment expense is recognized. During the three months ended March 31, 2017 and 2016, no impairment was recorded.
| F-7 |
The present value of estimated future net cash flows was computed by applying a flat oil price to forecast revenues from estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves (assuming the continuation of existing economic conditions), less any applicable future taxes.
The flat oil price is the first-day-of-the-month price as defined by the SEC in Rule 4-10 of Regulation S-X which includes the 12-month average of first-day-of-the-month prices from various indices. The flat oil price is adjusted to match up with accounting data through the use of a differential.
Accrued Liabilities
As of March 31, 2017 and December 31, 2016, the Company’s accrued liabilities consisted of the following:
| March
31, 2017 | December 31,
2016 | |||||||
| Accrued bonus | $ | 894 | $ | - | ||||
| Accrued financing costs | 659 | - | ||||||
| Accrued drilling costs | 1,763 | 1,331 | ||||||
| Accrued revenue | 2,433 | 1,313 | ||||||
| Accrued costs related to divestiture of DJ Basin properties | 584 | - | ||||||
| Accrued payroll tax withholding | 237 | - | ||||||
| Other accrued liabilities | 435 | 62 | ||||||
| $ | 7,005 | $ | 2,706 | |||||
Asset Retirement Obligations
The Company incurs retirement obligations for certain assets at the time they are placed in service. The fair values of these obligations are recorded as liabilities on a discounted basis. The costs associated with these liabilities are capitalized as part of the related assets and depreciated. Over time, the liabilities are accreted for the change in their present value. For purposes of depletion calculations, the Company includes estimated dismantlement and abandonment cost, net of salvage values, associated with future development activities that have not yet been capitalized as asset retirement obligations. Asset retirement obligations incurred are classified as Level 3 (unobservable inputs) fair value measurements. The asset retirement liability is allocated to operating expense using a systematic and rational method. The Company has accreted approximately $22,000 and $3,000 for the three months ended March 31, 2017 and 2016, respectively.
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, natural gas and natural gas liquid (NGL) revenues. Should sales proceeds be in excess of the Company's entitlement, these amounts will be included in accrued liabilities and the Company's share of sales taken by others will be included in other assets in the accompanying consolidated balance sheets. The Company had no material oil, natural gas or NGL entitlement assets or liabilities as of March 31, 2017 and December 31, 2016.
All revenue proceeds relating to third-party royalty owners not remitted by the end of a reporting period are accounted for in accrued revenue. As of March 31, 2017 and December 31, 2016, the Company had approximately $2.4 million and $1.3 million, respectively, of such revenue proceeds recorded in accrued liabilities.
| F-8 |
Major Customers
During the three months ended March 31, 2017 and 2016, the Company’s major customers consisted as a percentage of the following:
| Three Months Ended March 31, | ||||||||
| 2017 | 2016 | |||||||
| Texican Natural Gas Company | 77 | % | - | % | ||||
| Energy Transfer Partners, L.P. | 16 | % | - | % | ||||
| Shell Trading (US) Company | 2 | % | 32 | % | ||||
| Peterson Energy Operating | - | % | 30 | % | ||||
| PDC Energy, Inc. | - | % | 38 | % | ||||
| Others below 10% | 5 | % | - | % | ||||
| 100 | % | 100 | % | |||||
Impairment of Long-lived Assets
The Company accounts for long-lived assets (other than oil and gas properties) at cost. Other long-lived assets consist principally of property and equipment and identifiable intangible assets with finite useful lives (subject to amortization, depletion, and depreciation). The Company may impair these assets whenever events or changes in circumstances indicate that the carrying amount of such assets may not be fully recoverable. Recoverability is measured by comparing the carrying amount of an asset to the expected undiscounted future net cash flows generated by the asset. If it is determined that the asset may not be recoverable, and if the carrying amount of an asset exceeds its estimated fair value, an impairment charge is recognized to the extent of the difference.
Loss Per Share
Basic loss per share was calculated by dividing loss applicable to common shares by the weighted average number of common shares outstanding during the periods presented. The weighted average common shares outstanding include issued and outstanding shares of common stock and shares issuable for little or no consideration. The Company has included 3,738,639 and 3,522,735 relating to warrants, with an exercise price of $.01, in its basic earnings per share calculation for the three months ended March 31, 2017 and for the year ended December 31, 2016, respectively. The calculation of diluted loss per share includes the weighted average common shares outstanding plus potential dilutive impact of shares issuable upon the conversion of debt or preferred stock, vested restricted stock and exercise of warrants and options during the period, unless their effect is anti-dilutive. At March 31, 2017 and December 31, 2016, shares underlying restricted stock units, restricted stock, options, warrants (excluding warrants exercisable at $0.01), preferred stock have been excluded from the diluted share calculations as they were anti-dilutive as a result of net losses incurred.
The Company had the following shares of Common Stock equivalents at March 31, 2017 and December 31, 2016:
| March 31, | December 31, | |||||||
| 2017 | 2016 | |||||||
| Stock Options | 6,318,500 | 5,956,833 | ||||||
| Restricted Stock Units | 9,999 | 149,584 | ||||||
| Restricted Stock | 1,116,669 | 1,068,305 | ||||||
| Series B Preferred Stock | 13,071,818 | 15,454,545 | ||||||
| Stock Purchase Warrants, excluding warrants exercisable for $0.01 per share | 12,946,986 | 12,392,776 | ||||||
| 33,463,972 | 35,022,043 | |||||||
| F-9 |
Recently Issued Accounting Pronouncements
The Company considers the applicability and impact of all Accounting Standards Updates (“ASUs”). The ASUs not listed below were assessed and determined to be either not applicable or are expected to have minimal impact on its consolidated financial position and/or results of operations.
On February 22, 2017, the Financial Accounting Standards Board (“FASB”) issued ASU 2017-05, “Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets”, to clarify the scope of asset derecognition guidance and provide new guidance on the accounting for partial sales of nonfinancial assets. This guidance provides greater detail on what types of transactions should be accounted for within the scope of FASB Accounting Standards Codification (“ASC”) subtopic 610-20. The effective date for this update for public entities is for annual reporting periods beginning after December 15, 2017. The Company is evaluating the impact of the adoption of this ASU on its consolidated financial statements.
In January 2017, the FASB issued ASU 2017-01 “Business Combinations (Topic 805): Clarifying the Definition of a Business”, which clarifies the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. The standard introduces a screen for determining when assets acquired are not a business and clarifies that a business must include, at a minimum, an input and a substantive process that contribute to an output to be considered a business. This standard is effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period. The Company adopted this ASU on January 1, 2017, and expects that the adoption of this ASU could have a material impact on future consolidated financial statements as acquisitions that may no longer be considered to be businesses.
The FASB issued ASU 2016-18, “Restricted Cash (Topic 230),” to clarify the presentation of restricted cash in the statement of cash flows. The amendments require that a statement of cash flows explain the change during the period in restricted cash or restricted cash equivalents. In addition, changes in cash and cash equivalents, restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. As a result, transfers between cash and restricted cash will not be presented as a separate line item in the operating, investing or financing section of the cash flow statement. The amendments are effective for public entities for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted. The Company will adopt this ASU at effective date and expects the adoption of this ASU to affect only the consolidated statement of cash flows.
In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842),” which requires companies to recognize the assets and liabilities for the rights and obligations created by long-term leases of assets on the balance sheet. The guidance requires adoption by application of a modified retrospective transition approach for existing long-term leases and is effective for fiscal years beginning after December 15, 2018, including interim periods within those years. Oil and gas leases are scoped out of the new ASU. The effect of this guidance relating to the Company’s existing long-term leases will not have material impact on the Company’s consolidated financial statements. As of March 31, 2017, the Company currently has only one operating lease that expires in less than 2 years.
The FASB issued ASU 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. This ASU will simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This ASU is effective for annual and interim periods beginning in 2017 with early adoption permitted. The Company adopted this ASU on January 1, 2017. The Company grants primarily qualified incentive stock options which do not require the Company to withhold any income taxes when these options are exercised. As of March 31, 2017, none of the four employees who have non-qualified stock options have exercised their vested options. During the three months ended March 31, 2017, the Company withheld income taxes for vested restricted shares but these tax withholdings were processed by a third-party payroll service company. The tax withholding payments were received from the employees within a week following the Company’s payment to the third-party payroll service company. As a result, these funds flowed through the operating section of the Company’s consolidated statement of cash flows and had no impact on its consolidated statement of operations.
| F-10 |
In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). This ASU amends the principal versus agent guidance in ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which was issued in May 2014. Further, in April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing. This ASU also amends ASU 2014-09 and is related to the identification of performance obligations and accounting for licenses. The effective date and transition requirements for both of these amendments to ASU 2014-09 are the same as those of ASU 2014-09, which was deferred for one year by ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date.” That is, the guidance under these standards is to be applied using a full retrospective method or a modified retrospective method, as outlined in the guidance, and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted only for annual periods, and interim period within those annual periods, beginning after December 15, 2016. The Company is in the process of evaluating the impact of the ASU on its revenue recognition policies on existing customer contracts.
In March 2016, the FASB issued ASU No. 2016-06, “Derivatives and Hedging (Topic 815): Contingent Put and Call Options in Debt Instruments” (“ASU 2016-06”). This new standard simplifies the embedded derivative analysis for debt instruments containing contingent call or put options by removing the requirement to assess whether a contingent event is related to interest rates or credit risks. This new standard will be effective for the Company on January 1, 2017. As of January 1, 2017, the date of adoption and as of March 31, 2017, the Company did not have any debt instruments with embedded derivatives.
On August 26, 2016, the FASB issued ASU No. 2016-15, “Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force)”, (“ASU 2016-15”). The amendments in ASU 2016-15 address eight specific cash flow issues and apply to all entities, including both business entities and not-for-profit entities that are required to present a statement of cash flows under ASC 230, Statement of Cash Flows. The amendments in ASU 2016-15 are effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The Company will adopt this ASU at effective date. The Company expects the adoption of this ASU to affect only the consolidated statement of cash flows.
NOTE 4 - OIL AND GAS PROPERTIES & OIL AND GAS PROPERTY ACQUISITIONS AND DIVESTITURES
Divestiture of DJ Basin Properties
On March 31, 2017, the Company completed the divestiture of all of our oil and gas properties located in the Denver-Julesburg Basin (the “DJ Basin”) for a consideration of $2 million, subject to customary post-closing purchase price adjustments. The sale of its DJ Basin assets did not significantly alter the relationship between capitalized costs and proved reserves, and as such, all proceeds were recorded as adjustments to our full cost pool with no gain or loss recognized. The DJ Basin assets were sold to a company owned by a former chief financial officer of the Company and therefore the divestiture is considered a related party transaction – see disclosure in Note 8 Related Party Transactions. The net proceeds of $1.08 million received on March 31, 2017 included an offset against $0.7 million of severance pay and $0.22 million of net sales adjustments due to the purchaser.
The following table sets forth a summary of oil and gas property costs (net of divestitures) not being amortized at March 31, 2017 and December 31, 2016:
| March 31, | December 31, | |||||||
| 2017 | 2016 | |||||||
| (In thousands) | ||||||||
| Unproved unevaluated acreage: | ||||||||
| Beginning Balance | $ | 24,461 | $ | - | ||||
| Lease purchases | 2,715 | 546 | ||||||
| Assets acquired | - | 23,915 | ||||||
| Total unproved acreage | $ | 27,176 | $ | 24,461 | ||||
| Wells in progress: | ||||||||
| Beginning Balance | $ | 7,453 | $ | - | ||||
| Additions | 2,834 | 7,453 | ||||||
| Reclassification to evaluated properties | (7,410 | ) | - | |||||
| Total wells in progress and not subject to DD&A | $ | 2,877 | $ | 7,453 | ||||
| F-11 |
During the three months ended March 31, 2017 and 2016, no impairment was recorded on the Company’s oil and gas properties.
Depreciation, depletion and amortization expense related to proved properties was approximately $1.0 million and $0.02 million for three months ended March 31, 2017 and 2016, respectively.
NOTE 5 - MERGER WITH BRUSHY RESOURCES, INC. AND RELATED TRANSACTIONS
On June 23, 2016, the Company completed the merger transaction contemplated by the Agreement and Plan of Merger dated as of December 29, 2015, as amended to date (the “Merger Agreement”) by and among the Company, Brushy and Lilis Merger Sub, Inc., a Delaware corporation, a wholly-owned subsidiary of the Company (“Merger Sub”). Pursuant to the terms of the Merger Agreement, at the effective time (the “Effective Time”), Merger Sub merged with and into Brushy (the “Merger”), with Brushy continuing as the surviving corporation and becoming a wholly-owned subsidiary of Brushy. The Merger resulted in the acquisition of Brushy’s properties in the Delaware Basin as well as the majority of its current operating activity. The results of Brushy, since the closing date of the Merger are included in the Company’s consolidated statement of operations. The Merger was effected through the issuance of approximately 5.785 million shares of Common Stock in exchange for all outstanding shares of Brushy common stock using a ratio of 0.4550916 shares of Lilis Common Stock for each share of Brushy common stock and the assumption of Brushy's liabilities, including approximately $11.4 million of outstanding debt with Independent Bank, Brushy’s former senior lender, and approximately $6.2 million of accounts payable, accrued expenses and asset retirement obligations. In connection with the closing of the Merger, Lilis paid-down $6.0 million of the principal amount outstanding on Brushy’s term loan with Independent Bank, made a cash payment of $500,000 to SOSV Investments, LLC (“SOS”), Brushy's former subordinated lender and issued a $1 million promissory note to SOS (the “SOS Note”), along with a warrant to purchase 200,000 shares of Common Stock (the “SOS Warrant”).
In connection with the Merger, Lilis incurred costs of approximately $3.22 million, including (i) $3.05 million of consulting, investment, advisory, legal and other Merger-related fees, and (ii) $170,000 of value in conjunction with the warrants issued to SOS recorded additional Merger consideration.
Allocation of Purchase Price - The Merger was accounted for as a business combination, using the acquisition method. The following table represents the allocation of the total purchase price of Brushy to the assets and liabilities assumed based on the fair value on the closing date of the Merger.
The following table sets forth the Company’s purchase price allocation (in thousands, except share data and stock price):
| Shares of Lilis Common Stock issued to Brushy shareholders | 5,785,119 | |||||||
| Lilis Common Stock closing price on June 23, 2016 | $ | 1.20 | ||||||
| Fair value of Common Stock issued | $ | 6,942 | ||||||
| Cash consideration paid to SOS | 500 | |||||||
| SOS Note | 1,000 | |||||||
| Fair value of SOS warrant | 170 | |||||||
| Warrant liability - repricing derivative | 164 | |||||||
| Advance to Brushy pre-merger | 2,508 | |||||||
| Total purchase price | 11,284 | |||||||
| Plus: liabilities assumed by Lilis | ||||||||
| Current Liabilities | ||||||||
| Account payable and accrued expenses | $ | 5,447 | ||||||
| Term loan - Independent Bank | 11,379 | 16,826 | ||||||
| Long-Term Debt | 19 | |||||||
| Asset Retirement Obligation | 777 | |||||||
| Amount attributable to liabilities assumed | 17,622 | |||||||
| $ | 28,906 | |||||||
| Fair Value of Brushy Assets | ||||||||
| Current Assets: | ||||||||
| Cash | $ | 706 | ||||||
| Other current assets | 624 | |||||||
| $ | 1,330 | |||||||
| Oil and Gas Properties: | ||||||||
| Proved properties | 7,512 | |||||||
| Unproved properties | 19,662 | |||||||
| 27,174 | ||||||||
| Other assets | ||||||||
| Other Property Plant & Equipment | 42 | |||||||
| Other assets | 360 | 402 | ||||||
| Total Asset Value | $ | 28,906 |
| F-12 |
Pro forma Financial Information - The following pro forma combined financial information was derived from the historical financial statements of Lilis and Brushy and gives effect to the Merger as if it had occurred on January 1, 2016 for the three months ended March 31, 2016. Below information reflects pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including (i) Lilis’ Common Stock issued to convert Brushy’s outstanding shares of common stock as of the closing date of the Merger, (ii) adjustments to conform Brushy’s historical policy of accounting for its oil and natural gas properties from the successful efforts method to the full cost method of accounting, (iii) depletion of Brushy's fair-valued proved oil and gas properties, and (iv) the estimated tax impacts of the pro forma adjustments. The pro forma results of operations do not include any cost savings or other synergies that may result from the Merger or any estimated costs that have been or will be incurred by Lilis to integrate the Brushy assets. The pro forma combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Merger taken place on January 1, 2016; furthermore, the financial information is not intended to be a projection of future results.
| March 31, 2016 | ||||
| (In thousands, except share data) | ||||
| Revenue | $ | 822 | ||
| Net loss | $ | (5,479 | ) | |
| Net loss attributable to common stockholders | $ | (5,479 | ) | |
| Net loss per common share basic and diluted | $ | (0.18 | ) | |
| Weighted average shares outstanding: | ||||
| Basic and diluted | 30,606,552 | |||
NOTE 6 - FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company measures fair value of its financial assets on a three-tier value hierarchy, which prioritizes the inputs, used in the valuation methodologies in measuring fair value:
| ● | Level 1 - Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets. | |
| ● | Level 2 - Other inputs that are directly or indirectly observable in the marketplace. | |
| ● | Level 3 - Unobservable inputs which are supported by little or no market activity. |
The fair value hierarchy also requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.
The Company’s interest rate Term Loan and Debentures are measured using Level 3 inputs.
The following table provides a summary of the recurring fair values of assets and liabilities measured at fair value (in thousands):
| March 31, 2017 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| Recurring fair value measurements: | ||||||||||||||||
| Warrant liabilities | - | - | (683 | ) | (683 | ) | ||||||||||
| Total recurring fair value measurements | $ | - | $ | - | $ | (683 | ) | $ | (683 | ) | ||||||
| F-13 |
| December 31, 2016 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| Recurring fair value measurements: | ||||||||||||||||
| Warrant liabilities | - | - | (1,400 | ) | (1,400 | ) | ||||||||||
| Total recurring fair value measurements | $ | - | $ | - | $ | (1,400 | ) | $ | (1,400 | ) | ||||||
The following table provides a summary of changes in fair value of the Company’s Level 3 financial assets and liabilities during the three months ended March 31, 2017 and 2016 (in thousands):
| Bristol/ Heartland/SOS warrant liability | Total | |||||||
| Balance at January 1, 2017 | $ | (1,400 | ) | $ | (1,400 | ) | ||
| Cashless exercise of warrant (1) | 371 | 371 | ||||||
| Change in fair value of liability | 346 | 346 | ||||||
| Balance at March 31, 2017 | $ | (683 | ) | $ | (683 | ) | ||
| (1) | On March 14, 2017, the Company issued 77,131 shares of its common stock to Bristol Capital, LLC (“Bristol”) for a cashless exercise of the warrant. The Bristol warrant was also revalued on March 14, 2017 resulting in the Company incurring 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, the Company reclassified the $0.4 million of Bristol derivative liability to additional paid-in capital as of March 31, 2017. |
| Convertible
Debenture derivative liability | Bristol/ Heartland/SOS warrant liability | Incentive bonus | Total | |||||||||||||
| Balance at January 1, 2016 | $ | (6 | ) | $ | (56 | ) | $ | (223 | ) | $ | (285 | ) | ||||
| Reversal of accrued bonus | - | - | 223 | 223 | ||||||||||||
| Change in fair value of liability | (49 | ) | (19 | ) | - | (68 | ) | |||||||||
| Balance at March 31, 2016 | $ | (55 | ) | $ | (75 | ) | $ | - | $ | (130 | ) | |||||
Assets and liabilities measured at fair value on a nonrecurring basis. Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis, but are subject to fair value adjustments in certain circumstances. These assets and liabilities can include proved and unproved oil and gas properties and other long-lived assets that are written down to fair value when they are impaired or held for sale.
The Company did not have any transfers of assets or liabilities between Level 1, Level 2 or Level 3 of the fair value measurement hierarchy during the three months ended March 31, 2017 and 2016.
| F-14 |
NOTE 7 - LONG-TERM DEBTS
| March 31 | December 31 | |||||||
| 2017 | 2016 | |||||||
| (In thousands) | ||||||||
| Term Loan: | ||||||||
| 6% Senior Secured Term Loan, due 2019, net of deferred financing costs and debt discount | $ | 35,131 | $ | 29,214 | ||||
| 6% note payable to SOS Investment, LLC, due 2019 | 1,000 | 1,000 | ||||||
| Other notes payable | 23 | 29 | ||||||
| 36,154 | 30,243 | |||||||
| Less: current portion | (17 | ) | (17 | ) | ||||
| $ | 36,137 | $ | 30,226 | |||||
First Lien Credit Agreement
On September 29, 2016, the Company entered into the First Lien Credit Agreement by and among the Company and its wholly owned subsidiaries, Brushy, Impetro Operating and Resources (the “Initial Guarantors”), and the lenders party thereto (each a “Lender” and together, the “Lenders”) and T.R. Winston & Company, LLC (“TRW”) acting as initial collateral agent (the “First Lien Credit Agreement”).
The First Lien Credit Agreement provided for a $50 million three-year senior secured term loan with initial commitments of $31 million, of which $25 million was collected as of September 30, 2016, and the additional $6 million was collected at December 31, 2016. On February 7, 2017, pursuant to the terms of the First Lien Credit Agreement, the Company exercised the accordion advance feature increasing the aggregate principal amount outstanding under the term loan from $31 million to $38.1 million (the “Existing Term Loans”).
In connection with the Company’s entry into the First Lien Credit Agreement, it incurred commitment fees to each of the Lenders equal to 2.0% of their respective initial loan advances and advisory fees totaled to approximately $1.2 million as of December 31, 2016. The Company accounted for the $1.2 million as deferred financing costs to be amortized over the term of the loan. As partial consideration given to the lenders, we also amended certain warrants issued in the Series B preferred stock offering held by the lenders during the third and fourth quarters of the year ended December 31, 2016, to purchase up to an aggregate amount of approximately 2,850,000 and approximately 672,000, shares of common stock, respectively, such that the exercise price per share was lowered from $2.50 to $0.01 on such warrants. The portion repriced in the fourth quarter was due to certain delayed funding that occurred after the initial commitment. Additionally, each lender received a 2.0% commitment fee equal to their respective initial loan advance. All of the amended warrants are immediately exercisable from the original issuance date, for a period of two years, subject to certain conditions.
In connection with the exercise of the accordion advance feature for $7.1 million, the Company incurred additional $0.4 million in commitment fees and also amended certain warrants issued in the Series B preferred stock offering held by the lenders to purchase up to an aggregate amount of approximately 738,638 shares of common stock at an exercise price of $0.01 per share. The Company accounted for these repriced warrants as additional debt discount to the Term Loan for $1.0 million which will be accreted together with the remaining $0.6 million debt discount from the third and fourth quarters of 2016 over the remaining term of the loan. For the three months ended March 31, 2017, the Company amortized approximately $0.1 million of deferred financing costs, respectively, and accreted approximately $0.2 million of debt discount relating to the loan. These amounts were recorded as a component of non-cash interest expense. As of March 31, 2017, the unamortized portion of the deferred financing costs and debt discounts were $1.5 million and $3.5 million, respectively. As of December 31, 2016, the unamortized portion of the deferred financing costs and debt discounts were $1.2 million and $0.6 million, respectively.
The Existing Term Loans bore interest at a rate of 6.0% per annum and were scheduled to mature on September 30, 2019. The Company had the right to prepay the Term Loan, in whole or in part, at any time at a prepayment premium equal to 6.0% of the amount repaid. Such prepayment premium would also have been required to be paid if the Term Loan was repaid prior to maturity as a result of a change in control. In certain situations, the First Lien Credit Agreement required mandatory prepayments of the Existing Term Loans at the request of the Lenders, including in the event of certain non-ordinary course asset sales, the incurrence of certain debt, and receipt of proceeds in connection with insurance claims.
| F-15 |
The First 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. The amounts under the First Lien Credit Agreement could be accelerated and become due and payable upon an event of default.
SOS Investment LLC Note
On June 30, 2016, pursuant to the Merger Agreement and as a condition of the Fourth Amendment, the Company was required to make a cash payment of $500,000 to SOSV, LLC, and also executed a subordinated promissory note with SOSV, LLC, for $1 million, at an interest rate of 6% per annum which matures on June 30, 2019. In conjunction with cash payment and the note, the Company also issued 200,000 warrants at an exercise price of $25.00. The Company accounted for the cost of warrants of $0.2 million as part of the Merger transaction costs for the year ended December 31, 2016.
Interest Expense
Interest expense for the three months ended March 31, 2017 and 2016 was approximately $0.8 million and $1.3 million, respectively. The non-cash interest expense during the three months ended March 31, 2017 and 2016 was approximately $0.2 million and $0.8 million, respectively. The non-cash interest expense consisted of amortization of the deferred financing costs and accretion of debt discount.
NOTE 8 - RELATED PARTY TRANSACTIONS
During the three months ended March 31, 2017 and 2016, the Company was engaged in the following transactions with related party:
| March 31, | ||||||||||
| Related Party | Transactions | 2017 | 2016 | |||||||
| Directors and Officers: | ||||||||||
| Nuno Brandolini (Director) | Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 | $ | - | $ | 150 | |||||
| Total: | $ | - | $ | 150 | ||||||
| General Merrill McPeak (Director) | Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 | $ | - | $ | 250 | |||||
| Total: | $ | - | $ | 250 | ||||||
| R. Glenn Dawson (Director) | Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 | $ | - | $ | 50 | |||||
| Total: | $ | - | $ | 50 | ||||||
| Ronald D Ormand (Executive Chairman) | Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 through the Bruin Trust(1) | $ | - | $ | 1,150 | |||||
| Total: | $ | - | $ | 1,150 | ||||||
| Abraham Mirman (Chief Executive Officer and Director) | Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 through The Bralina Group, LLC(2) | $ | - | $ | 1,000 | |||||
| Total: | $ | - | $ | 1,000 | ||||||
| Brennan Short (Chief Operating Officer) | Consulting fees paid to MMZ Consulting, Inc which is owned by Mr. Short. Mr. Short is the sole member of the corporation. | $ | 203 | $ | - | |||||
| Total: | $ | 203 | $ | - | ||||||
| Kevin Nanke (former Chief Financial Officer) | Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 | $ | - | $ | 100 | |||||
| Purchased the DJ Basin properties from the Company through Nanke Energy, LLC | 2,000 | - | ||||||||
| Total: | $ | 2,000 | $ | 100 | ||||||
| (1) | An irrevocable trust managed by Jerry Ormand, Mr. Ormand's brother, as trustee and whose beneficiaries are adult children of Ronald Ormand |
| (2) | Mr. Mirman has shared voting and dispositive power over the securities held by The Bralina Group, LLC with Susan Mirman. |
| F-16 |
NOTE 9 - SHAREHOLDERS’ EQUITY
Conditionally Redeemable 6% Preferred Stock
In August 2014, the Company designated 2,000 shares of its authorized preferred stock as Conditionally Redeemable 6% Preferred Stock, or (the “Redeemable Preferred”). All 2,000 shares of Redeemable Preferred were issued in September 2014, pursuant to the Settlement Agreement with Hexagon, LLC (f/k/a Hexagon Investments, LLC) (“Hexagon”). The Redeemable Preferred has the same par value and stated value characteristics as the Series A Preferred Stock, yet the Conditionally Redeemable 6% Preferred Stock is not convertible into Common Stock or any other securities of the Company. Except as otherwise required by law, holders of the Redeemable Preferred shall not be entitled to voting rights.
The Redeemable Preferred Stock bears a 6% dividend per annum, payable quarterly, and is redeemable at face value (plus any accrued and unpaid dividends) at any time at the Company’s option, or at the Holders option upon the Company’s achievement of certain production and reserves thresholds. These thresholds include, the Company’s annualized gross production average for 90 consecutive days at 2,500 BOE per day or higher or the Company’s present value discounted at 10% of its proved developed producing properties filed with the Securities and Exchange Commission exceeds $50 million. As of March 31, 2017 and December 31, 2016, the Company has accrued a cumulative dividend of $270,000 and $240,000, respectively.
Series B 6% Convertible Preferred Stock
On June 15, 2016, the Company entered into a purchase agreement for the private placement of 20,000 shares of its Series B Preferred Stock, along with detachable warrants to purchase up to 9,090,926 shares of Common Stock, at an exercise price of $2.50 per share, for aggregate gross proceeds of $20 million.
Each share of Series B Preferred Stock is convertible, at the option of the holder, subject to adjustment under certain circumstances into shares of Common Stock of the Company at a conversion price of $1.10. Except as otherwise required by law, holders of the Series B Preferred Stock shall not be entitled to voting rights. The Series B Preferred Stock is convertible at any time, subject to certain conditions, at the option of the holders, or at the Company’s discretion when the Company’s Common Stock trades above $10.00 (subject to any reverse or forward stock splits and the like) for ten consecutive days. In addition, the Company has the right to redeem the shares of Series B Preferred Stock, along with any accrued and unpaid dividends, at any time, subject to certain conditions set forth in the Certificate of Designation. The holders of the Series B Preferred Stock are entitled to receive a dividend payable (subject to certain conditions set forth in the Certificate of Designation), in cash or shares of Common Stock of the Company, at the election of the Company, at a rate of 6% per annum.
The Series B Preferred Stock is classified as equity based on the following criteria: i) the redemption of the instrument at the control of the Company, ii) the instrument is convertible into a fixed amount of shares at a conversion price of $1.10, iii) the instrument is closely related to the underlying Company’s common stock, iv) the conversion option is indexed to the Company’s stock, v) the conversion option cannot be settled in cash and can only be redeemed at the discretion of the Company, and vi) the Series B Preferred Stock is not considered convertible debt.
Shares of the Series B Preferred Stock and related warrants were valued using the relative fair value method. The Company determined the transaction created a beneficial conversion feature of $7.9 million, which was expensed immediately and calculated by taking the net proceeds of approximately $15.2 million and valuing the warrants as of June 15, 2016, utilizing a Black Scholes option pricing model. The inputs for the pricing model are: i) $1.20 market price per share, ii) exercise price of $2.50 per share, iii) contractual life of 2 years, iv) volatility of 238% and v) a risk-free rate of 0.78%. As of March 31, 2017 and December 31, 2016, the stated value of the issued and outstanding shares of Series B Preferred Stock was approximately $11.0 million and $13.4 million, respectively.
| F-17 |
As of March 31, 2017, approximately 2,449 shares of the Series B Preferred Stock plus approximately $0.1 million of cumulative dividend payable had been converted into approximately 2.3 million shares of the Company’s Common Stock at a conversion price of $1.10 per share. As of March 31, 2017, the Company accrued approximately $0.7 million of cumulative dividends for Series B Preferred Stock.
Private Placement
On February 28, 2017, the Company entered into a Securities Subscription Agreement (the “Subscription Agreement”) with certain institutional and accredited investors in connection with a private placement the (“March 2017 Private Placement”) to sell 5.2 million units, consisting of approximately 5.2 million shares of common stock and warrants to purchase approximately an additional 2.6 million shares of common stock. Each unit consists of one share of common stock and a warrant to purchase 0.50 shares of common stock (each, a “Unit”), at a price per unit of $3.85. Each warrant has an exercise price of $4.50 and may be subject to redemption by the Company, upon prior written notice, if the price of the Company’s common stock closes at or above $6.30 for twenty trading days during a consecutive thirty trading day period. As of March 31, 2017, the Company received aggregate gross proceeds of $20.0 million and issued 5,194,821 shares of common stock and 2,597,420 of warrants to purchase shares of common stock.
Warrants
The following table provides a summary of warrant activity for the three months ended March 31, 2017:
| Warrants | Weighted- Average Exercise Price |
|||||||
| Outstanding at January 1, 2017 | 15,915,511 | $ | 3.34 | |||||
| Warrants issued in connection with private placement | 2,597,420 | 4.50 | ||||||
| Exercised, forfeited, or expired | (1,827,309 | ) | (0.01 | ) | ||||
| Outstanding at March 31, 2017 | 16,685,622 | $ | 3.37 | |||||
NOTE 10 - SHARE BASED AND OTHER COMPENSATION
The Company’s stock-based compensation consisted of the following:
| Three
Months Ended March 31, 2017 | Three
Months Ended March 31, 2016 | |||||||||||||||||||||||
| Stock
Options | Restricted Stock | Total | Stock
Options | Restricted
Stock | Total | |||||||||||||||||||
| Stock-based compensation expensed | $ | 1,776 | $ | 1,003 | $ | 2,779 | $ | 192 | $ | 49 | $ | 241 | ||||||||||||
| Unrecognized stock-based compensation costs | $ | 5,114 | $ | 1,120 | $ | 6,234 | $ | 1,707 | $ | 171 | $ | 1,878 | ||||||||||||
| Weighted average amortization period remaining | 1.31 | 1.08 | - | 2.93 | 1.08 | - | ||||||||||||||||||
Restricted Stock
A summary of restricted stock grant activity pursuant to the 2016 Plan for the three months ended March 31, 2017 is presented below:
| Number of Shares | Weighted Average Grant Date Price | |||||||
| Outstanding at January 1, 2017 | 1,068,305 | $ | 1.55 | |||||
| Granted | 223,750 | $ | 3.76 | |||||
| Vested and issued | (174,250 | ) | $ | (3.90 | ) | |||
| Forfeited | (1,136 | ) | $ | (2.93 | ) | |||
| Outstanding at March 31, 2017 | 1,116,669 | $ | 2.95 | |||||
| F-18 |
Restricted Stock Units
A summary of restricted stock unit grant activity pursuant to the 2012 Plan for the three months ended March 31, 2017 is presented below.
| Number of Shares | Weighted Average Grant Date Price | |||||||
| Outstanding at January 1, 2017 | 149,584 | $ | 10.56 | |||||
| Vested and issued | (139,585 | ) | 16.62 | |||||
| Outstanding at March 31, 2017 | $ | 9,999 | $ | 16.50 | ||||
Stock Options
A summary of stock option activity for the three months ended March 31, 2017 is presented below:
| Stock Options
Outstanding and Exercisable |
|||||||||||||||||
| Number of Options |
Weighted Average Exercise Price |
Number of Options Vested/ Exercisable |
Weighted Average Remaining Contractual Life (Years) |
||||||||||||||
| Outstanding at January 1, 2017 | 5,956,833 | $ | 2.04 | 2,208,757 | 9.68 | ||||||||||||
| Granted | 825,000 | 3.51 | - | - | |||||||||||||
| Exercised | (170,000 | ) | 1.34 | - | - | ||||||||||||
| Forfeited or cancelled | (293,333 | ) | (2.84 | ) | - | - | |||||||||||
| Outstanding at March 31, 2017 | 6,318,500 | $ | 3.05 | 2,683,808 | 9.24 | ||||||||||||
During the three months ended March 31, 2017, options to purchase 825,000 shares of the Company’s common stock were granted under the 2016 Plan. The weighted average fair value of these options of $3.51. The fair values were determined using the Black-Scholes-Merton option valuation method assuming no dividends, a risk-free interest rate of 1.27%, a weighted average expected life of 2 years and weighted-average volatility of 112.10%
As of March 31, 2017, total unrecognized compensation costs relating to the outstanding options was approximately $5.1 million, which is expected to be recognized over the remaining vesting period of approximately 1.3 years.
NOTE 11 - SUPPLEMENTAL NON-CASH TRANSACTIONS
The following table presents information about supplemental cash flows for the three months ended March 31, 2017 and 2016 (in thousands);
| 2017 | 2016 | |||||||
| Non-cash investing and financing activities excluded from the statement of cash flows: | ||||||||
| Conversion of Series B preferred stock and accrued dividends to common stock | $ | 2,549 | $ | - | ||||
| Commitment fees offset by issuance of common stock for private placement | 250 | - | ||||||
| Fair value of repriced warrants as debt discount to term loan | 1,031 | 546 | ||||||
| Increase in final settlement on the divestiture of DJ Basin properties in accrued liabilities | 584 | - | ||||||
| Cashless exercise of warrants | 371 | - | ||||||
| Change in capital expenditures for drilling costs in accrued liabilities | 812 | - | ||||||
| F-19 |
NOTE 12 - COMMITMENTS AND CONTINGENCIES
Environmental and Governmental Regulation
At March 31, 2017, there were no known environmental or regulatory matters which are reasonably expected to result in a material liability to the Company. Many aspects of the oil and gas industry are extensively regulated by federal, state, and local governments in all areas in which the Company has operations. Regulations govern such things as drilling permits, environmental protection and air emissions/pollution control, spacing of wells, the unitization and pooling of properties, reports concerning operations, land use, and various other matters including taxation. Oil and gas industry legislation and administrative regulations are periodically changed for a variety of political, economic, and other reasons. As of March 31, 2017, the Company had not been fined or cited for any violations of governmental regulations that would have a material adverse effect on the financial condition of the Company.
Legal Proceedings
The Company may from time to time be involved in various legal actions arising in the normal course of business. In the opinion of management, the Company’s liability, if any, in these pending actions would not have a material adverse effect on the financial position of the Company. The Company’s general and administrative expenses would include amounts incurred to resolve claims made against the Company.
The Company believes there is no litigation pending that could have, individually or in the aggregate, a material adverse effect on its results of operations or financial condition.
NOTE 13 - SUBSEQUENT EVENTS
First Lien Credit Agreement Amendments
On April 24, 2017, and subsequently on April 26, 2017, the Company entered into the first and second amendments (together, the “First Lien Amendments”) to our First Lien Credit Agreement, 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 bridge loans in an aggregate principal amount of $15.0 million (the “Bridge Loans”). Under the terms of the First Lien Amendments, Lilis Operating joined the Initial Guarantors as a guarantor (together the “Guarantor”) under the First Lien Credit Agreement. The Bridge Loans were fully drawn on April 24, 2017.
On April 26, 2017, in connection with the closing of the Second Lien Credit Agreement, the Company paid off the Existing Loans in full including accrued and unpaid interest thereon.
The Bridge Loans are secured by first priority liens on substantially all of the Company’s and Guarantors’ assets, including their 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.
| F-20 |
Redemption of Conditionally Redeemable 6% Preferred Stock
Effective as of April 24, 2017, the Company has redeemed, in full, the Company’s Redeemable Preferred (as defined above in Note 9). In accordance therewith, the Company and Hexagon, the only holder of the Redeemable Preferred, 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 Redeemable Preferred has been redeemed in full.
Series B 6% Convertible Preferred Stock Conversion
On April 24, 2017, the Company and all of the holders of its 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 Series B 6% Convertible Preferred Stock (“A&R COD”) in order to remove certain restrictions contained therein with respect to beneficial ownership limitations. On the same date, the Company 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, the Company 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.
Second Lien Credit Agreement
On April 26, 2017, the Company 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”), including Värde Partners, Inc., a Delaware corporation, as lead lender (the “Lead Lender”), pursuant to which the Lenders agreed to make convertible loans to the Company 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 the Company’s and the Guarantors’ assets, including their 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 Second Lien Term Loan will be used 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 the Company’s working capital needs, including capital expenditures, and for general corporate purposes, including the exploration, acquisition and development of oil and gas property. The proceeds of the Delayed Draw Loans will be used only to fund acreage leasing activity and/or acreage acquisition.
The Loans mature on April 26, 2021. The Loans are subject to mandatory prepayment with the net proceeds of certain asset sales, casualty events and debt incurrences, subject to the right of the Company to reinvest the net proceeds of asset sales and casualty events within 180 days and, in the case of asset sales and casualty events, prepayment of the Bridge Loans. The Company 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. The Company will be required to pay a customary make-whole premium in connection with any mandatory or voluntary prepayment of the Loans.
| F-21 |
The Second Lien Credit Agreement contains 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. 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 become 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, the Company 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 its 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, 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”).
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) including such Lender, owning in excess of 19.999% of the outstanding shares of common stock or voting power of 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) 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 newly created 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 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 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. |
| F-22 |
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 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 the Company 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 (ii) 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.
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.
Registration Rights Agreement
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 the Company will be required to file with the Securities and Exchange Commission a registration statement under the Securities Act of 1933 registering for resale the shares of common stock issuable upon conversion of the Loans or any shares of Lender Preferred Stock issued. The Registration Rights Agreement contains customary covenants and indemnification and contribution provisions.
| F-23 |
Report of Independent Registered Public Accounting Firm
To the Audit Committee of the
Board of Directors and Shareholders
of Lilis Energy, Inc. and Subsidiaries
We have audited the accompanying consolidated balance sheets of Lilis Energy, Inc. and Subsidiaries (the “Company”) as of December 31, 2016 and 2015, and the related consolidated statements of operations, changes in stockholders’ equity (deficit) and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Lilis Energy, Inc. and Subsidiaries, as of December 31, 2016 and 2015, and the consolidated results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.
/s/ Marcum LLP
Marcum LLP
New York, NY
March 3, 2017
| F-24 |
Lilis Energy, Inc. and Subsidiaries
Consolidated Balance Sheets
(In thousands, except share and per share data)
| December 31, | ||||||||
| 2016 | 2015 | |||||||
| ASSETS | ||||||||
| Current assets: | ||||||||
| Cash and cash equivalents | $ | 11,738 | $ | 110 | ||||
| Accounts receivables, net of allowance of $106 and $80, respectively | 2,247 | 952 | ||||||
| Prepaid expenses and other current assets | 767 | 79 | ||||||
| Total current assets | 14,752 | 1,141 | ||||||
| Oil and gas properties, full cost method of accounting | ||||||||
| Unproved | 24,461 | - | ||||||
| Proved | 69,809 | 50,096 | ||||||
| Less: accumulated depreciation, depletion, amortization and impairment | (55,771 | ) | (49,573 | ) | ||||
| Total oil and gas properties, net | 38,499 | 523 | ||||||
| Other property and equipment, net | 52 | 44 | ||||||
| Other assets | 216 | 2,000 | ||||||
| Total other assets | 268 | 2,044 | ||||||
| Total assets | $ | 53,519 | $ | 3,708 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
| F-25 |
Lilis Energy, Inc. and Subsidiaries
Consolidated Balance Sheet
(In thousands, except share and per share data)
| December 31, | ||||||||
| 2016 | 2015 | |||||||
| LIABILITIES, REDEEMABLE PREFERRED STOCK AND STOCKHOLDERS' EQUITY | ||||||||
| Current liabilities: | ||||||||
| Accounts payable | $ | 5,166 | $ | 1,331 | ||||
| Accrued liabilities | 2,706 | 3,496 | ||||||
| Dividends payable | 808 | 719 | ||||||
| Asset retirement obligations | 338 | - | ||||||
| Current portion of long-term debt | 17 | 11,067 | ||||||
| Total current liabilities | 9,035 | 16,613 | ||||||
| Asset retirement obligations | 919 | 209 | ||||||
| Long-term debt | 30,226 | - | ||||||
| Long-term derivative liabilities | 1,400 | 56 | ||||||
| Total liabilities | 41,580 | 16,878 | ||||||
| Commitments and contingencies (Note 9) | ||||||||
| Conditionally redeemable 6% preferred stock, $0.0001 par value, 7,000 shares authorized, 2,000 shares issued and outstanding with a liquidation preference of $2,240 at December 31, 2016. | 1,874 | 1,173 | ||||||
| Stockholders’ Equity (Deficit): | ||||||||
| Series A Preferred stock, $0.0001 par value; stated rate $1,000:10,000 shares authorized, 0 and 7,500 shares issued and outstanding as of December 31, 2016 and 2015, respectively. | - | 6,794 | ||||||
| Series B Preferred stock, $0.0001 par value; stated rate $1,000: 20,000 shares authorized; 17,000 and 0 shares issued and outstanding at December 31, 2016 and 2015, respectively, with a liquidation preference of $20,627 at December 31, 2016. | 13,432 | - | ||||||
| Common stock, $0.0001 par value per share; 100,000,000 shares authorized, 20,918,901 and 2,786,275 shares issued and outstanding as of December 31, 2016 and 2015, respectively. | 2 | - | ||||||
| Additional paid-in capital | 219,837 | 159,773 | ||||||
| Accumulated deficit | (223,206 | ) | (180,910 | ) | ||||
| Total stockholders’ equity (deficit) | 10,065 | (14,343 | ) | |||||
| Total liabilities, redeemable preferred stock and stockholders’ equity | $ | 53,519 | $ | 3,708 | ||||
The accompanying notes are an integral part of these consolidated financial statements
| F-26 |
Lilis Energy, Inc. and Subsidiaries
Consolidated Statements of Operations
(In thousands, except share and per share data)
| Years Ended December 31, | ||||||||
| 2016 | 2015 | |||||||
| Oil, natural gas and natural gas liquid sales | $ | 3,435 | $ | 396 | ||||
| Costs and expenses: | ||||||||
| Production costs | 1,247 | 195 | ||||||
| Production taxes | (167 | ) | 28 | |||||
| General and administrative | 14,570 | 7,930 | ||||||
| Depreciation, depletion and amortization | 1,566 | 574 | ||||||
| Accretion of asset retirement obligations | 132 | 10 | ||||||
| Impairment of evaluated oil and gas properties | 4,718 | 24,478 | ||||||
| Total operating expenses | 22,066 | 33,215 | ||||||
| Loss from operations | (18,631 | ) | (32,819 | ) | ||||
| Other income (expenses): | ||||||||
| Other income | 90 | 3 | ||||||
| Debt conversion inducement expense | (8,307 | ) | - | |||||
| Gain on extinguishment of debt | 250 | - | ||||||
| Gain (loss) in fair value of derivative instruments | (1,222 | ) | 1,638 | |||||
| Gain (loss) in fair value of conditionally redeemable 6% preferred stock | (701 | ) | 514 | |||||
| Gain on modification of convertible debts | 602 | - | ||||||
| Interest expense | (4,924 | ) | (1,697 | ) | ||||
| Total other income (expenses) | (14,212 | ) | 458 | |||||
| Net loss | (32,843 | ) | (32,361 | ) | ||||
| Dividends on redeemable preferred stock | (407 | ) | (120 | ) | ||||
| Loss on extinguishment of Series A Convertible Preferred Stock | (540 | ) | - | |||||
| Dividend and deemed dividend Series B Convertible Preferred stock | (8,506 | ) | (600 | ) | ||||
| Net loss attributable to common stockholders | $ | (42,296 | ) | $ | (33,081 | ) | ||
| Net loss per common share basic and diluted | $ | (3.73 | ) | $ | (12.13 | ) | ||
| Weighted average common shares outstanding: | ||||||||
| Basic and diluted | 11,328,252 | 2,726,775 | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
| F-27 |
Lilis Energy, Inc. and Subsidiaries
Consolidated Statements of Changes in Stockholders’ Equity (Deficit)
(In thousands, except share and per share data)
| Series A Preferred | Series B Preferred | Additional | ||||||||||||||||||||||||||||||||||
| Shares | Shares | Common Shares | Paid In | Accumulated | ||||||||||||||||||||||||||||||||
| Shares | Amount | Shares | Amount | Shares | Amount | Capital | Deficit | Total | ||||||||||||||||||||||||||||
| Balance, January 1, 2015 | 7,500 | $ | 6,794 | - | $ | - | 2,699,273 | $ | - | $ | 155,101 | $ | (147,829 | ) | $ | 14,066 | ||||||||||||||||||||
| Issuances of common stock | - | - | - | - | 87,002 | - | 365 | - | 365 | |||||||||||||||||||||||||||
| Fair value of warrants issued for professional services | - | - | - | - | - | - | 425 | - | 425 | |||||||||||||||||||||||||||
| Fair value of warrants issued for bridge term loan | - | - | - | - | - | - | 1,222 | - | 1,222 | |||||||||||||||||||||||||||
| Stock based compensation | - | - | - | - | - | - | 2,660 | - | 2,660 | |||||||||||||||||||||||||||
| Dividend Preferred stockholders | - | - | - | - | - | - | - | (120 | ) | (120 | ) | |||||||||||||||||||||||||
| Deemed dividend Series A Convertible Preferred Stock | - | - | - | - | - | - | - | (600 | ) | (600 | ) | |||||||||||||||||||||||||
| Net loss | - | - | - | - | - | - | - | (32,361 | ) | (32,361 | ) | |||||||||||||||||||||||||
| Balance, December 31, 2015 | 7,500 | 6,794 | - | - | 2,786,275 | - | 159,773 | (180,910 | ) | (14,343 | ) | |||||||||||||||||||||||||
| Stock based compensation | - | - | - | - | 711,667 | - | 7,078 | - | 7,078 | |||||||||||||||||||||||||||
| Exercise of warrants | - | - | - | - | 420,707 | - | 187 | - | 187 | |||||||||||||||||||||||||||
| Fair value of warrants issued for financing costs | - | - | - | - | - | - | 713 | - | 713 | |||||||||||||||||||||||||||
| Issuance and repricing of warrants to induce conversion | - | - | - | - | - | - | 8,307 | - | 8,307 | |||||||||||||||||||||||||||
| Gain on modification of convertible debentures | - | - | - | - | - | - | (602 | ) | - | (602 | ) | |||||||||||||||||||||||||
| Fair value of warrants issued for debt discount | - | - | - | - | - | - | 1,479 | - | 1,479 | |||||||||||||||||||||||||||
| Common stock issued for conversion of convertible notes and | ||||||||||||||||||||||||||||||||||||
| accrued interest | - | - | - | - | 6,778,115 | 1 | 14,871 | - | 14,872 | |||||||||||||||||||||||||||
| Common stock and warrants issued in connection with the | ||||||||||||||||||||||||||||||||||||
| Brushy merger | - | - | - | - | 5,785,119 | - | 7,111 | - | 7,111 | |||||||||||||||||||||||||||
| Series B Preferred stock issued for cash, net of fees | - | - | 20,000 | 18,195 | - | - | - | - | 18,195 | |||||||||||||||||||||||||||
| Warrants issued for Series B Preferred Stock offering fees | - | - | - | (1,590 | ) | - | - | 1,590 | - | - | ||||||||||||||||||||||||||
| Common stock issued for conversion of Series A Preferred | ||||||||||||||||||||||||||||||||||||
| Stock and accrued dividends | (7,500 | ) | (6,794 | ) | - | - | 1,500,000 | 1 | 7,681 | - | 888 | |||||||||||||||||||||||||
| Loss on extinguishment of Series A Preferred Stock | - | - | - | - | - | - | 540 | (540 | ) | - | ||||||||||||||||||||||||||
| Common stock issued for conversion of Series B Preferred | ||||||||||||||||||||||||||||||||||||
| Stock and accrued dividends | - | - | (3,000 | ) | (3,173 | ) | 2,937,018 | - | 3,230 | - | 57 | |||||||||||||||||||||||||
| Dividends and deemed dividends for Preferred Stock | - | - | - | - | - | - | 7,879 | (8,913 | ) | (1,034 | ) | |||||||||||||||||||||||||
| Net Loss | - | - | - | - | - | - | - | (32,843 | ) | (32,843 | ) | |||||||||||||||||||||||||
| Balance, December 31, 2016 | - | $ | - | 17,000 | $ | 13,432 | 20,918,901 | $ | 2 | $ | 219,837 | $ | (223,206 | ) | $ | 10,065 | ||||||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
| F-28 |
Lilis Energy, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
(In thousands)
| Years Ended December 31, | ||||||||
| 2016 | 2015 | |||||||
| Cash flows from operating activities: | ||||||||
| Net loss | $ | (32,843 | ) | $ | (32,361 | ) | ||
| Adjustments to reconcile net loss to net cash used in operating activities: | ||||||||
| Equity instruments issued for services and compensation | 7,078 | 3,450 | ||||||
| Bad debt expense | 494 | - | ||||||
| Inducement Expense | 8,307 | - | ||||||
| Amortization of deferred financing cost | 328 | 52 | ||||||
| Accretion of debt discount | 2,857 | - | ||||||
| Gain on extinguishment of debt | (250 | ) | - | |||||
| Gain (loss) in fair value of derivative instruments | 1,222 | (1,604 | ) | |||||
| Gain (loss) in fair value of conditionally redeemable 6% preferred stock | 701 | (514 | ) | |||||
| Gain on modification of convertible debt | (602 | ) | - | |||||
| Depreciation, depletion, amortization and accretion of asset retirement obligation | 1,698 | 584 | ||||||
| Impairment of evaluated oil and gas properties | 4,718 | 24,478 | ||||||
| Changes in operating assets and liabilities: | ||||||||
| Accounts receivable | (1,264 | ) | (120 | ) | ||||
| Other assets | 1,554 | 57 | ||||||
| Accounts payable, accrued expenses and other liabilities | (307 | ) | 2,027 | |||||
| Net cash used in operating activities | (6,309 | ) | (3,951 | ) | ||||
| Cash flows from investing activities: | ||||||||
| Cash advance to Brushy Resources, Inc. | - | (1,750 | ) | |||||
| Cash consideration for Brushy merger, net of cash acquired | (2,302 | ) | - | |||||
| Restricted cash | - | 145 | ||||||
| Capital expenditures | (16,828 | ) | (98 | ) | ||||
| Net cash used in investing activities | (19,130 | ) | (1,703 | ) | ||||
| Cash flows from financing activities: | ||||||||
| Net proceeds from issuance of Series B Preferred Stock | 18,195 | - | ||||||
| Proceeds from bridge notes, net | 2,863 | 5,950 | ||||||
| Proceeds from warrant exercise | 187 | - | ||||||
| Dividend payments on preferred stock | - | (180 | ) | |||||
| Debt issuance costs | (1,299 | ) | (266 | ) | ||||
| Proceeds from issuance of term loan | 31,000 | - | ||||||
| Repayment of debt | (13,879 | ) | (250 | ) | ||||
| Net cash provided by financing activities | 37,067 | 5,254 | ||||||
| Increase (decrease) in cash | 11,628 | (400 | ) | |||||
| Cash at beginning of period | 110 | 510 | ||||||
| Cash at end of period | $ | 11,738 | $ | 110 | ||||
| Supplemental disclosure: | ||||||||
| Cash paid for interest | $ | 762 | $ | 365 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
| F-29 |
Lilis Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
NOTE 1 – ORGANIZATION
On September 21, 2007, Universal Holdings, Inc. (“Universal”), a Nevada corporation, completed the acquisition of Coronado Acquisitions, LLC (“Coronado”). Under the terms of the acquisition, Coronado was merged into Universal. On October 12, 2009, Universal changed its name to Recovery Energy, Inc. On December 1, 2013, Recovery Energy, Inc. changed its name to Lilis Energy, Inc. (“Lilis”, “Lilis Energy” and the “Company”).
The Company is an independent oil and gas exploration and production company focused on the Delaware Basin in Winkler and Loving Counties, Texas and Lea County, New Mexico and the Denver-Julesburg Basin (“DJ Basin”) in Wyoming, Colorado, and Nebraska.
On June 23, 2016, the Company effected a 1-for-10 reverse stock split of its Common Stock (the “Reverse Split”). The accompanying consolidated financial statements and these notes to the consolidated financial statements give retroactive effect to the Reverse Split for all periods presented.
All references to production, sales volumes and reserves quantities are net to the Company’s interest unless otherwise indicated.
NOTE 2 – MANAGEMENT PLANS AND LIQUIDITY
The Company has reported net operating losses during the year ended December 31, 2016 and for the past five years. As a result, the Company funded its operations in 2016 and the merger with Brushy Resources, Inc. through additional debt and equity financing. On September 29, 2016, the Company entered into a new Credit and Guaranty Agreement (the “Credit Agreement”) that provides for a three-year, senior, secured term loan with initial aggregate principal commitments of $31 million and a maximum facility size of $50 million. The term loan was funded in two draws, with $25 million collected as of September 30, 2016 and the additional $6 million collected as of November 11, 2016.
As of December 31, 2016, the Company had a working capital balance and a cash balance of approximately $5.7 million and $11.7 million, respectively. As of March 1, 2017, the Company’s cash balance was approximately $9.0 million, which included a drawdown of additional principal under its Credit Agreement on February 7, 2017 of $7.1 million and excluded net proceeds of the equity offering completed on March 1, 2017, or approximately $18.6 million. The Company believes that it will have sufficient capital to operate over the next 12 months from the date of the filing of this annual report. However, it is possible that the Company will seek to raise additional debt, equity capital, or both depending on the pace of its drilling and leasing activity.
NOTE 3 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND ESTIMATES
Principles of Consolidation
The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. The Company’s wholly owned subsidiaries include Brushy Resources, Inc (“Brushy”), ImPetro Operating, LLC (“ImPetro Operating”) and ImPetro Resources, LLC (“ImPetro”), and Lilis Operating Company, LLC (“Lilis Operating”). All significant intercompany accounts and transactions have been eliminated in consolidation.
Use of Estimates
The preparation of consolidated financial statements in conformity with generally accepted accounting principles in the United States (“U.S. GAAP”) requires the Company to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities; disclosure of contingent assets and liabilities at the date of the financial statements; the reported amounts of revenues and expenses during the reporting period; and the quantities and values of proved oil, natural gas and NGL reserves used in calculating depletion and assessing impairment of its oil and gas properties.
| F-30 |
The most significant financial estimates are associated with the Company’s estimated volumes of proved oil and natural gas reserves, asset retirement obligations, assessments of impairment imbedded in the carrying value of undeveloped acreage and undeveloped properties, fair value of financial instruments, including derivative liabilities, depreciation and accretion, income taxes and contingencies. Although management believes that these estimates are reasonable, actual results could differ significantly from those estimates.
Reclassifications
Certain prior-period amounts have been reclassified for comparative purposes to conform with the fiscal 2016 presentation. These reclassifications have no effect on the Company’s previously reported results of operations.
Cash and Cash Equivalent
Cash and cash equivalents include highly liquid instruments with an original maturity of three months or less when purchased to be cash equivalents as these instruments are readily convertible to known amounts of cash and do not bear significant risk of changes in value due to their short maturity period.
Accounts Receivable
The Company records actual and estimated oil and gas revenue receivable from third parties at its net revenue interest. The Company also reflects costs incurred on behalf of joint interest partners. The Company typically has the right to withhold future revenue disbursements to recover outstanding joint interest billings on outstanding receivables from joint interest owners. Management periodically reviews accounts receivable amounts for collectability and records its allowance for uncollectible receivables using the allowance method based on past experience. Allowance for doubtful accounts are based primarily on joint interest billings for expenses related to oil and natural gas wells. Receivables which derive from sales of certain oil and gas production are collateral under the Company’s Credit Agreement.
Concentration of Credit Risk
The Company’s cash is invested at major financial institutions primarily within the United States. At December 31, 2016 and 2015, the Company’s cash was maintained in accounts that are insured up to the limit determined by the federal governmental agency. The Company may at times have balances in excess of the federally insured limits. Periodically, the Company evaluates the creditworthiness of the financial institutions, and has not experienced any losses in such accounts.
Significant Customers
The Company’s major customers include, Noble Energy, Texican and Energy Transfer, Inc. These customers accounted for approximately 41%, 38% and 16% of the Company’s revenue for the year ended December 31, 2016. The Company’s major customers include, Shell Trading (US), PDC Energy and Noble Energy, which accounted for approximately 43%, 26% and 21% of its revenue for the year ended December 31, 2015.
However, the Company believe that the loss of a single purchaser could not materially affect the Company’s business because alternative purchasers are available.
Reserves
All of the reserves data included herein are estimates. Estimates of the Company’s crude oil and natural gas reserves are prepared in accordance with guidelines established by the Securities Exchange Commission (“SEC”), including rule revisions designed to modernize the oil and gas company reserves reporting requirements, which the Company implemented effective December 31, 2010. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Uncertainties include the projection of future production rates and the expected timing of development expenditures. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserves estimates may be different from the quantities of crude oil and natural gas that are ultimately recovered. In addition, the ability to produce economic reserves is dependent on the oil and gas prices used in the reserves estimate. The Company’s reserves estimates are based on 12-month average commodity prices, unless contractual arrangements otherwise designate the price to be used, in accordance with the SEC rules. However, oil and gas prices are volatile and, as a result, the Company’s reserves estimates may change in the future.
| F-31 |
Estimates of proved crude oil and natural gas reserves significantly affect the Company’s depreciation, depletion, and amortization (“DD&A”) expense. For example, if estimates of proved reserves decline, the DD&A rate will increase, resulting in a decrease in net income. A decline in estimates of proved reserves could also result in an impairment charge, which would reduce earnings.
Oil and Gas Properties
The Company uses the full cost method of accounting for oil and gas operations. Under this method, costs related to the exploration, non-production related development and acquisition of oil and natural gas reserves are capitalized. Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling, developing and completing productive wells and/or plugging and abandoning non-productive wells, and any other costs directly related to acquisition and exploration activities. Proceeds from property sales are generally applied as a credit against capitalized exploration and development costs, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of proved reserves.
The Company accounts for its unproven long-lived assets in accordance with Accounting Standards Codification (“ASC”) Topic 360-10-05, Accounting for the Impairment or Disposal of Long-Lived Assets. ASC Topic 360-10-05 requires that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the historical cost carrying value of an asset may no longer be appropriate.
Depletion of exploration and development costs and depreciation of wells and tangible production assets is computed using the units-of-production method based upon estimated proved oil and gas reserves. Costs included in the depletion base to be amortized include (a) all proved capitalized costs including capitalized asset retirement costs net of estimated salvage values, less accumulated depletion, (b) estimated future development cost to be incurred in developing proved reserves; and (c) estimated decommissioning and abandonment/restoration costs, net of estimated salvage values, that are not otherwise included in capitalized costs.
Costs associated with undeveloped acreage are excluded from the depletion base until it is determined whether proved reserves can be assigned to the properties. When proved reserves are assigned to such properties or one or more specific properties are deemed to be impaired, the cost of such properties is added to full cost pool which is subject to depletion calculations.
Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the sum of the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves and the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are not subject to amortization. Should capitalized costs exceed this ceiling, an impairment expense is recognized. During 2016, commodity prices continued to trade in a low range. With low commodity prices sustained for the majority of 2016 in the DJ Basin, some of the Company’s properties became uneconomic triggering an impairment charge of $4.7 million at December 31, 2016. Due to the decline in commodity prices and lack of liquidity the Company recorded an impairment charge during the year ended December 31, 2015. During the years ended December 31, 2016 and 2015, the Company recorded $4.7 million and $24.5 million impairment charges, respectively.
The present value of estimated future net cash flows was computed by applying: a flat oil price to forecast revenues from estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves (assuming the continuation of existing economic conditions), less any applicable future taxes.
Wells in Progress
Wells in progress connotes wells that are currently in the process of being drilled or completed or otherwise under evaluation as to their potential to produce oil and gas reserves in commercial quantities. Such wells continue to be classified as wells in progress and withheld from the depletion calculation and the ceiling test until such time as either proved reserves can be assigned, or the wells are otherwise abandoned. Upon either the assignment of proved reserves or abandonment, the costs for these wells are then transferred to the full cost pool and become subject to both depletion and the ceiling test calculations in accordance with full cost accounting under Rule 4-10 of Regulation S-X of the Securities Exchange Act of 1934, as amended.
| F-32 |
Other Property and Equipment
Property and equipment include office equipment and furniture which are stated at cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets. The estimated useful lives of property and equipment range from three to seven years. The Company recorded approximately $0.04 million and $0.03 million of depreciation for the years ended December 31, 2016 and 2015, respectively.
Impairment of Long-lived Assets
The Company accounts for long-lived assets (other than oil and gas properties) at cost. The Company may impair these assets whenever events or changes in circumstances indicate that the carrying amount of such assets may not be fully recoverable. Recoverability is measured by comparing the carrying amount of an asset to the expected undiscounted future net cash flows generated by the asset. If it is determined that the asset may not be recoverable, and if the carrying amount of an asset exceeds its estimated fair value, an impairment charge is recognized to the extent of the difference.
Asset Retirement Obligation
The Company incurs retirement obligations for certain assets at the time they are placed in service. The fair values of these obligations are recorded as liabilities on a discounted basis. The costs associated with these liabilities are capitalized as part of the related assets and depreciated. Over time, the liabilities are accreted for the change in their present value. For purposes of depletion calculations, the Company includes estimated dismantlement and abandonment cost, net of salvage values, associated with future development activities that have not yet been capitalized as asset retirement obligations. Asset retirement obligations incurred are classified as Level 3 (unobservable inputs) fair value measurements. The asset retirement liability is allocated to operating expense using a systematic and rational method.
Fair Value of Financial Instruments
As of December 31, 2016 and 2015, the carrying value of cash and cash equivalents, accounts receivable, accounts payable, accrued expenses, interest and dividends payable and advance from joint interest partners approximates fair value due to the short-term nature of such items. The carrying value of the Company’s secured debt is carried at cost which is approximately the fair value of the debt as the related interest rate are at the terms approximates rates currently available to the Company.
Revenue Recognition
The Company recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller's price to the buyer is fixed or determinable and (iv) collectability is reasonably assured.
The Company uses the entitlements method of accounting for oil, NGLs and gas revenues. Sales proceeds in excess of the Company's entitlement are included in other liabilities and the Company's share of sales taken by others is included in other assets in the accompanying consolidated balance sheets. The Company had no material oil, NGL or gas entitlement assets or liabilities as of December 31, 2016 or 2015.
Stock Based Compensation
The Company measures the fair value of stock-based compensation expense awards made to employees and directors, including stock options, restricted stock units, and restricted stock, on the date of grant using a Black-Scholes model. For equity awards, compensation expense is based on the fair value on the grant or modification date and is recognized in the Company’s financial statements over the vesting period. The measurement of share-based compensation expense is based on several criteria, including but not limited to, the valuation model used and associated input factors, such as expected term of the award, stock price volatility, risk free interest rate, dividend rate and award cancellation rate. These inputs are subjective and are determined using management’s judgment. If differences arise between the assumptions used in determining share-based compensation expense and the actual factors, which become known over time, the Company may change the input factors used in determining future share-based compensation expense.
The Company accounts for warrant grants to nonemployees whereby the fair values of such warrants are determined using the option pricing model at the earlier of the date at which the nonemployee’s performance is complete or a performance commitment is reached.
| F-33 |
Warrant Modification Expense
The Company accounts for the modification of warrants as an exchange of the old award for a new award. The incremental value is measured as the excess, if any, of the fair value of the modified award over the fair value of the original award immediately before modification, and is either expensed as a period expense or amortized over the performance or vesting date. The Company estimates the incremental value of each warrant using the Black-Scholes option pricing model. The Black-Scholes model is highly complex and dependent on key estimates by management. The estimate with the greatest degree of subjective judgment is the estimated volatility of the Company’s stock price.
Earnings (Loss) Per Share
Basic income (loss) per share was calculated by dividing net income or loss applicable to common shares by the weighted average number of common shares outstanding during the periods presented. The calculation of diluted income (loss) per share should include the potential dilutive impact of shares issuable upon the conversion of debt or preferred stock, vested restricted stock and exercise of warrants and options during the period, unless their effect is anti-dilutive. At December 31, 2016 and 2015, shares underlying restricted stock units, restricted stock, options, warrants, preferred stock and debentures have been excluded from the diluted share calculations as they were anti-dilutive as a result of net losses incurred. The Company has included 3,522,735 warrants, with an exercise price of $.01, in its earnings per share calculation for the year ended December 31, 2016.
The Company had the following shares of Common Stock equivalents at December 31, 2016 and 2015:
| December 31, | ||||||||
| 2016 | 2015 | |||||||
| Stock Options | 5,956,833 | 6,083,333 | ||||||
| Restricted Stock Units | 149,584 | 1,869,000 | ||||||
| Restricted Stock | 1,068,305 | - | ||||||
| Series A Preferred Stock | - | 3,112,033 | ||||||
| Series B Preferred Stock | 15,454,545 | - | ||||||
| Stock Purchase Warrants | 12,392,776 | 24,383,161 | ||||||
| Convertible Debentures | - | 3,423,233 | ||||||
| Convertible Bridge Notes | - | 5,900,004 | ||||||
| 35,022,043 | 44,770,764 | |||||||
Income Taxes
The Company uses the asset and liability method in accounting for income taxes. Deferred tax assets and liabilities are recognized for temporary differences between financial statement carrying amounts and the tax bases of assets and liabilities, and are measured using the tax rates expected to be in effect when the differences reverse. Deferred tax assets are also recognized for operating loss and tax credit carry forwards. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the results of operations in the period that includes the enactment date. A valuation allowance is used to reduce deferred tax assets when uncertainty exists regarding their realization.
The Company recognizes its tax benefits only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely to be realized upon settlement. A liability for “unrecognized tax benefits” is recorded for any tax benefits claimed that do not meet these recognition and measurement standards. As of December 31, 2016 and 2015, the Company has determined that no liability is required to be recognized.
The Company’s policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense. No interest or penalties were required to be accrued at December 31, 2016 and 2015. Further, the Company does not expect that the total amount of unrecognized tax benefits will significantly increase or decrease during the next 12 months.
Recently Issued Accounting Pronouncements
The Company considers the applicability and impact of all Accounting Standards Updates (“ASUs”). The ASUs not listed below were assessed and determined to be either not applicable or are expected to have minimal impact on its consolidated financial position and/or results of operations.
| F-34 |
In January 2017, the FASB issued ASU 2017-01 “Business Combinations (Topic 805): Clarifying the Definition of a Business”, which clarifies the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. The standard introduces a screen for determining when assets acquired are not a business and clarifies that a business must include, at a minimum, an input and a substantive process that contribute to an output to be considered a business. This standard is effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period. The Company adopted this ASU on January 1, 2017, and expects that the adoption of this ASU could have a material impact on future consolidated financial statements for acquisitions that are not considered to be businesses.
The FASB issued ASU 2016-18, “Restricted Cash (Topic 230),” to clarify the presentation of restricted cash in the statement of cash flows. The amendments require that a statement of cash flows explain the change during the period in restricted cash or restricted cash equivalents. In additions to changes in cash and cash equivalents, restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. As a result, transfers between cash and restricted cash will not be presented as a separate line item in the operating, investing or financing section of the cash flow statement. The amendments are effect for public business entities for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted. The Company will adopt this ASU in 2017. The adoption of this ASU will affect the presentations in the Company’s consolidated balance sheets and consolidated statement of cash flows and will not materially impact the results of operations.
In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842),” which requires companies to recognize the assets and liabilities for the rights and obligations created by long-term leases of assets on the balance sheet. The guidance requires adoption by application of a modified retrospective transition approach for existing long-term leases and is effective for fiscal years beginning after December 15, 2018, including interim periods within those years. The effect of this guidance relating to the Company’s existing long-term leases will not have material impact on the Company’s consolidated financial statements. As of December 31, 2016, the Company currently has only one 2-year operating lease.
The FASB issued ASU 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. This ASU will simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This ASU is effective for annual and interim periods beginning in 2017 with early adoption permitted. The Company adopted this ASU on January 1, 2017 and does not believe that the simplification of accounting for share-based compensation and related income taxes will have a material impact on its consolidated financial statements.
In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). This ASU amends the principal versus agent guidance in ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), which was issued in May 2014 (“ASU 2014-09”). Further, in April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing. This ASU also amends ASU 2014-09 and is related to the identification of performance obligations and accounting for licenses. The effective date and transition requirements for both of these amendments to ASU 2014-09 are the same as those of ASU 2014-09, which was deferred for one year by ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date. That is, the guidance under these standards is to be applied using a full retrospective method or a modified retrospective method, as outlined in the guidance, and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted only for annual periods, and interim period within those annual periods, beginning after December 15, 2016. The Company has not selected a transition method and is evaluating its revenue recognition policies and existing customer contracts to determine the impact this guidance will have on its financial statements.
In March 2016, the FASB issued ASU No. 2016-06, “Derivatives and Hedging (Topic 815): Contingent Put and Call Options in Debt Instruments” (“ASU 2016-06”). This new standard simplifies the embedded derivative analysis for debt instruments containing contingent call or put options by removing the requirement to assess whether a contingent event is related to interest rates or credit risks. This new standard will be effective for the Company on January 1, 2017. The Company expects the adoption of this standard may have material impact on the Company’s result of operations from its continued efforts in raising capital to fund its operations and develop its oil and gas properties from issuing convertible equity or debt instruments.
On August 26, 2016, the FASB issued ASU No. 2016-15, Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force), (“ASU 2016-15”). The amendments in ASU 2016-15 address eight specific cash flow issues and apply to all entities, including both business entities and not-for-profit entities that are required to present a statement of cash flows under FASB Accounting Standards Codification (FASB ASC) 230, Statement of Cash Flows. The amendments in ASU 2016-15 are effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The Company adopted this ASU on January 1, 2017 and expects the adoption will only affect the classifications within the consolidated statement of cash flows.
| F-35 |
In September 2015, the FASB issued ASU No. 2015-16, “Business Combinations (Topic 805), Simplifying the Accounting for Measurement-Period Adjustments” (“ASU 2015-16”). The update requires that the acquirer in a business combination recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined (not retrospectively as with prior guidance). Additionally, the acquirer must record in the same period’s financial statements the effect on earnings of changes in depreciation, amortization or other income effects as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the time of acquisition. The acquiring entity is required to disclose, on the face of the financial statements or in the footnotes to the financial statements, the portion of the amount recorded in current period earnings, by financial statement line item, that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The guidance in ASU No. 2015-16 is effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. Earlier application is permitted for financial statements that have not been issued. The Company adopted this standard on January 1, 2016 and there were no material impact on its consolidated financial statements.
In April 2015, the FASB issued ASU No. 2015-03 (“ASU 2015-03”), “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs.” ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, consistent with debt discounts, instead of being presented as an asset. ASU 2015-03 is effective for the Company on January 1, 2016. Once adopted, entities are required to apply the new guidance retrospectively to all prior periods presented. The retrospective application represents a change in accounting principle. Early adoption is permitted for financial statements that have not been previously issued. The Company adopted this standard on January 1, 2016. The adoption of ASU 2015-03 only affects the presentation of the Company’s accompanying consolidated balance sheets and related financial statement disclosures in Note 9. In conjunction with the adoption of ASU 2015-03, $1.8 million and $0.2 million of debt issuance costs, previously presented as part of other assets was included as part of long-term debt which was reclassified as a direct deduction from the carrying amount of that debt liability as of December 31, 2016 and 2015, respectively.
In August 2014, the FASB issued ASU No. 2014–15 (“ASU 2014-15”), “Presentation of Financial Statements – Going Concern.” ASU 2014-15 provides GAAP guidance on management’s responsibility in evaluating whether there is substantial doubt about a company’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, management will be required to evaluate whether there are conditions or events that raise substantial doubt about a company’s ability to continue as a going concern within one year from the date the financial statements are issued. The new standard is effective for the Company on January 1, 2017. As of December 31, 2016, the Company believes that it has sufficient capital to operate for the next 12 months – see management’s assessment and analysis of its plans and liquidity in Note 2 - Management Plans and Liquidity above.
NOTE 4 – OIL AND GAS PROPERTIES
The following table sets forth a summary of oil and gas property costs (net of divestitures) not being amortized at December 31, 2016 and 2015:
| December 31, | ||||||||
| 2016 | 2015 | |||||||
| (In thousands) | ||||||||
| Undeveloped unevaluated acreage | ||||||||
| Beginning Balance | $ | - | $ | 2,886 | ||||
| Lease purchases | 546 | - | ||||||
| Assets conveyed | 23,915 | - | ||||||
| Transfer and other reclassification to evaluated properties | - | (2,886 | ) | |||||
| Total undeveloped acreage | $ | 24,461 | $ | - | ||||
| Wells in progress: | ||||||||
| Beginning Balance | $ | - | $ | 6,042 | ||||
| Additions | 7,453 | - | ||||||
| Disposition of wells in progress for elimination of accrued expenses for drilling | - | (5,198 | ) | |||||
| Reclassification to evaluated properties | - | (844 | ) | |||||
| Total wells in progress and not subject to DD&A | $ | 7,453 | $ | - | ||||
| F-36 |
During the year ended December 31, 2016, the Company entered the Delaware Basin through the Merger. Since then, Lilis has increased its Delaware Basin acreage position by 53% and has added 860 net contiguous acres further expanding its Delaware Basin footprint. At December 31, 2016 and 2015, the Company completed an assessment of its inventory of unevaluated acreage, which resulted in a transfer of $0 and $2.9 million, respectively from unevaluated acreage to evaluated properties.
Depreciation, depletion and amortization (“DD&A”) expenses related to the proved properties were approximately $1.6 million and $0.6 million for the years ended December 31, 2016 and 2015, respectively.
NOTE 5 – MERGER WITH BRUSHY RESOURCES, INC. AND RELATED TRANSACTIONS
On June 23, 2016, the Company completed the merger transaction contemplated by the Agreement and Plan of Merger dated as of December 29, 2015, as amended to date (the “Merger Agreement”) by and among the Company, Brushy and Lilis Merger Sub, Inc., a Delaware corporation, a wholly-owned subsidiary of the Company (“Merger Sub”). Pursuant to the terms of the Merger Agreement, at the effective time (the “Effective Time”), Merger Sub merged with and into Brushy (the “Merger”), with Brushy continuing as the surviving corporation and becoming a wholly-owned subsidiary of Brushy. The Merger resulted in the acquisition of Brushy’s properties in the Delaware Basin as well as the majority of its current operating activity. The results of Brushy, since the closing date of the Merger are included in the Company’s consolidated statement of operations. The Merger was effected through the issuance of approximately 5.785 million shares of Common Stock in exchange for all outstanding shares of Brushy common stock using a ratio of 0.4550916 shares of Lilis Common Stock for each share of Brushy common stock and the assumption of Brushy's liabilities, including approximately $11.4 million of outstanding debt with Independent Bank, Brushy’s former senior lender, and approximately $6.2 million of accounts payable, accrued expenses and asset retirement obligations. In connection with the closing of the Merger, Lilis paid-down $6.0 million of the principal amount outstanding on Brushy’s term loan with Independent Bank, made a cash payment of $500,000 to SOSV Investments, LLC (“SOS”), Brushy's former subordinated lender and issued a $1 million promissory note to SOS (the “SOS Note”), along with a warrant to purchase 200,000 shares of Common Stock (the “SOS Warrant”).
In connection with the Merger, Lilis incurred costs of approximately $3.22 million to date, including (i) $3.05 million of consulting, investment, advisory, legal and other Merger-related fees, and (ii) $170,000 of value in conjunction with the warrants issued to SOS recorded additional Merger consideration.
Allocation of Purchase Price - The Merger has been accounted for as a business combination, using the acquisition method. The following table represents the allocation of the total purchase price of Brushy to the assets and liabilities assumed based on the fair value on the closing date of the Merger.
The following table sets forth the Company’s purchase price allocation (in thousands, except shares data and stock price):
| Shares of Lilis Common Stock issued to Brushy shareholders | 5,785,119 | |||||||
| Lilis Common Stock closing price on June 23, 2016 | $ | 1.20 | ||||||
| Fair value of Common Stock issued | $ | 6,942 | ||||||
| Cash consideration paid to SOS | 500 | |||||||
| SOS Note | 1,000 | |||||||
| Fair value of SOS warrant | 170 | |||||||
| Warrant liability - repricing derivative | 164 | |||||||
| Advance to Brushy pre-merger | 2,508 | |||||||
| Total purchase price | 11,284 | |||||||
| Plus: liabilities assumed by Lilis | ||||||||
| Current Liabilities | ||||||||
| Account payable and accrued expenses | $ | 5,447 | ||||||
| Term loan - Independent Bank | 11,379 | 16,826 | ||||||
| Long-Term Debt | 19 | |||||||
| Asset Retirement Obligation | 777 | |||||||
| Amount attributable to liabilities assumed | 17,622 | |||||||
| $ | 28,906 | |||||||
| Fair Value of Brushy Assets | ||||||||
| Current Assets: | ||||||||
| Cash | $ | 706 | ||||||
| Other current assets | 624 | |||||||
| $ | 1,330 | |||||||
| Oil and Gas Properties: | ||||||||
| Evaluated properties | 7,512 | |||||||
| Unevaluated properties | 19,662 | |||||||
| 27,174 | ||||||||
| Other assets | ||||||||
| Other Property Plant & Equipment | 42 | |||||||
| Other assets | 360 | 402 | ||||||
| Total Asset Value | $ | 28,906 |
| F-37 |
Pro forma Financial Information - The following pro forma condensed combined financial information was derived from the historical financial statements of Lilis and Brushy and gives effect to the Merger as if it had occurred on January 1, 2015 for the year ended December 31, 2015. Below information reflects pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including (i) Lilis’s Common Stock issued to convert Brushy’s outstanding shares of common stock as of the closing date of the Merger, (ii) adjustments to conform Brushy’s historical policy of accounting for its oil and natural gas properties from the successful efforts method to the full cost method of accounting, (iii) depletion of Brushy's fair-valued proved oil and gas properties, and (iv) the estimated tax impacts of the pro forma adjustments. The pro forma results of operations do not include any cost savings or other synergies that may result from the Merger or any estimated costs that have been or will be incurred by Lilis to integrate the Brushy assets. The pro forma combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Merger taken place on January 1, 2015; furthermore, the financial information is not intended to be a projection of future results.
| December 31, | ||||||||
| 2016 | 2015 | |||||||
| (In thousands, except share data) | ||||||||
| Revenue | $ | 4,989 | $ | 3,173 | ||||
| Net loss | $ | (35,835 | ) | $ | (75,808 | ) | ||
| Net loss attributable to common stockholders | $ | (45,288 | ) | $ | (76,528 | ) | ||
| Net loss per common share basic and diluted | $ | (4.00 | ) | $ | (13.32 | ) | ||
| Weighted average shares outstanding: | ||||||||
| Basic and diluted | 11,328,252 | 5,745,785 | ||||||
NOTE 6 – FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company measures fair value of its financial assets on a three-tier value hierarchy, which prioritizes the inputs, used in the valuation methodologies in measuring fair value:
| ● | Level 1 - Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets. |
| ● | Level 2 - Other inputs that are directly or indirectly observable in the marketplace. |
| ● | Level 3 - Unobservable inputs which are supported by little or no market activity. |
The fair value hierarchy also requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.
| F-38 |
Asset Retirement Obligation
The fair value of the Company’s asset retirement obligation liability is calculated at the point of inception by taking into account, the cost of abandoning oil and gas wells, which is based on the Company’s and/or Industry’s historical experience for similar work, or estimates from independent third-parties; the economic lives of its properties, which are based on estimates from reserve engineers; the inflation rate; and the credit adjusted risk-free rate, which takes into account the Company’s credit risk and the time value of money. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs.
Executive Compensation
In September 2013, the Company announced the appointment of Abraham Mirman as its new president. In connection with Mr. Mirman’s appointment, the Company entered into an employment agreement with Mr. Mirman (the “Mirman Agreement”). The Mirman Agreement provides for an incentive bonus package that, depending upon the relative performance of the Company’s Common Stock compared to the performance of stocks of certain peer group companies as measured from Mr. Mirman’s initial date of employment through December 31, 2014, may result in a cash bonus payment to Mr. Mirman of up to 3.0 times his base salary. The incentive bonus is recorded as a liability and valued at each reporting period. The Company engaged a valuation firm (“VFIRM”) to complete a valuation of this incentive bonus. As previously announced, on March 30, 2015, the Company entered into an amended and restated employment agreement, which the Company refers to as the Mirman CEO Agreement with Mr. Mirman. The Mirman CEO Agreement also provides for Mr. Mirman to receive a cash incentive bonus if certain production thresholds are achieved by the Company. Mr. Mirman’s new incentive bonus liability was valued by VFIRM at $104,000 at December 31, 2015. As of December 31, 2016, there was no bonus liability due to Mr. Mirman since the production thresholds were not met by the Company. As of December 31, 2015, the Company provided for $87,000 of the bonus liability which represents the amount earned as of December31, 2015.
On March 6, 2015, the Company announced the appointment of Kevin Nanke as its new Executive Vice President and Chief Financial Officer. Mr. Nanke would also receive a cash incentive bonus if certain production thresholds were achieved by the Company and a performance bonus of $100,000 if the Company achieved certain goals set forth in Mr. Nanke’s employment agreement. Mr. Nanke’s new incentive bonus liability was valued by VFIRM at $83,000 at December 31, 2015. As of December 31, 2016, there was no bonus liability due to Mr. Nanke since the production thresholds were not met by the Company. As of December 31, 2015, the Company provided for $69,000 of the liability which represents the amount earned as of that date.
On March 16, 2015, the Company entered into an employment agreement with Ariella Fuchs for services to be performed as General Counsel to the Company. Ms. Fuchs will also receive a cash incentive bonus if certain production thresholds are achieved by the Company. Ms. Fuchs’ new incentive bonus liability was valued by VFIRM at $80,000 at December 31, 2015. As of December 31, 2016, there was no bonus liability due to Ms. Fuchs since the production thresholds were not met by the Company. As of December 31, 2015, the Company provided for $67,000 of the liability which represents the amount earned as of that date.
Change in Warrant Liability
On September 2, 2014, the Company entered into a Consulting Agreement with Bristol Capital, LLC, pursuant to which the Company issued to Bristol a warrant to purchase up to 100,000 shares of Common Stock at an exercise price of $20.00 per share (or, in the alternative, 100,000 options, but in no case both). The agreement has a price protection feature that will automatically reduce the exercise price if the Company enters into another consulting agreement pursuant to which warrants are issued with a lower exercise price, which triggered during fiscal year 2016.. On December 31, 2016, the Company revalued the warrants/option using the revised terms as follows: (i) 641,026 total warrants/options issued; (ii) stock price of $3.10; (iii) adjusted exercise price of $3.12; (iv) expected life of 2.67 years; (v) volatility of 101%; (vi) risk free rate of 1.38% for a total value of $1.21 million, which adjusted the change in fair value valuation of the derivative by $1.17 million. On December 31, 2015, the Company revalued the warrants/options using the following variables: (i) 100,000 total warrants/options issued (as stated above, the Company will only issue a total of 100,000 shares of Common Stock under the option or the warrant, but no more than 100,000 shares of Common Stock in the aggregate); (ii) stock price of $2.00; (iii) exercise price of $20.00; (iv) expected life of 3.7 years; (v) volatility of 100%; risk free rate of 1.5% for a total value of approximately $44,000, which adjusted the change in fair value valuation of the derivative by $350,000 for the year ended December 31, 2015.
On January 8, 2015, the Company entered into the Credit Agreement. In connection with the Credit Agreement, the Company issued to Heartland a warrant to purchase up to 22,500 shares of Common Stock at an adjusted exercise price of $4.05 with the initial advance, which contains an anti-dilution feature that will automatically reduce the exercise price if the Company enters into another agreement pursuant to which warrants are issued with a lower exercise price.
On December 31, 2015, the Company revalued the warrants issued to the Heartland Bank using the following variables: (i) 22,500 warrants issued; (ii) stock price of $2.00; (iii) exercise price of $ 25.00; (iv) expected life of 4.0 years; (v) volatility of 100%; (vi) risk free rate of 1.5% for a total value of $12,000, which adjusted the change in fair value valuation of the derivative by $12,000 for the year ended December 31, 2015. On December 31, 2016, the Company revalued the warrants using the following variables: (i) 22,500 warrants issued; (ii) stock price of $3.10; (iii) adjusted exercise price of $ 4.05; (iv) expected life of 3.02 years; (v) volatility of 101%; (vi) risk free rate of 1.5% for a total value of approximately $42,000, which adjusted the change in fair value valuation of the derivative by $30,000 for the year ended December 31, 2016.
| F-39 |
Pursuant to the Merger Agreement and as a condition to the Fourth Amendment (defined below), the Company was required to make a cash payment of $500,000, issue the SOS Note and the SOS Warrant. The SOS Warrant contains a price protection feature that will automatically reduce the exercise price if the Company enters into another financing agreement pursuant to which warrants are issued with a lower exercise price after June 23, 2016. This initial value of $164,000 was recorded as additional Merger consideration. On December 31, 2016, the Company evaluated the SOS Warrant using the following variables: (i) stock price of $3.10 (ii) exercise price of $25.00 (iii) contractual life of 1.48 years; (iv) volatility of 101%; (v) risk free rate of 1.02% for a total value of approximately $144,000, which adjusted the fair value valuation of the derivative by approximately $20,000 for the year ended December 31, 2016.
Debentures Conversion Derivative Liability
As of December 31, 2015, the Company had $6.85 million in remaining Debentures, which, subject to stockholder approval, were convertible at any time at the holders’ option into shares of Common Stock at $20.00 per share, or 342,323 underlying conversion shares prior to the execution of the Debenture Conversion Agreement. The Debentures have elements of a derivative due to the potential for certain adjustments, including both the conversion option and the price protection embedded in the Debentures. The conversion option allows the Debenture holders to convert their Debentures to underlying Common Stock at a conversion price of $20.00 per share, subject to certain adjustments, including the requirement to reset the conversion for any subsequent offering at a lower price per share amount. The Company values this conversion liability at each reporting period using a Monte Carlo pricing model.
On June 23, 2016, pursuant to the terms of the Debenture Conversion Agreement, dated December 29, 2015, the Company's remaining outstanding 8% Convertible Debentures (the “Debentures”) of approximately $6,846,000 converted automatically upon consummation of the Merger. The conversion price was modified from $20.00 per share to $5.00 per share, resulting in the issuance of 1,369,293 shares of Common Stock. Upon the conversion of the Debentures, the associated conversion liability of approximately $54,000 was reclassified to additional paid-in capital. At December 31, 2016 and 2015, the Company valued the conversion feature associated with the Debentures at $0 and $6,000, respectively. As of December 31, 2016, the remaining debentures were fully converted into 1,369,293 shares of the Company’s common stock.
The following table provides a summary of the recurring fair values of assets and liabilities measured at fair value (in thousands):
| December 31, 2016 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| Recurring fair value measurements: | ||||||||||||||||
| Warrant liabilities | - | - | (1,400 | ) | (1,400 | ) | ||||||||||
| Total recurring fair value measurements | $ | - | $ | - | $ | (1,400 | ) | $ | (1,400 | ) | ||||||
| December 31, 2015 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| Recurring fair value measurements: | ||||||||||||||||
| Executive employment agreement | $ | - | $ | - | $ | (223 | ) | $ | (223 | ) | ||||||
| Warrant liabilities | - | - | (56 | ) | (56 | ) | ||||||||||
| Convertible debenture conversion derivative liability | - | - | (6 | ) | (6 | ) | ||||||||||
| Total recurring fair value measurements | $ | - | $ | - | $ | (285 | ) | $ | (285 | ) | ||||||
| F-40 |
The following table provides a summary of changes in fair value of the Company’s Level 3 financial assets and liabilities as of December 31, 2016 and 2015 (in thousands):
| Conversion derivative liability | Bristol/ Heartland/SOS warrant liability | Incentive bonus | Total | |||||||||||||
| Balance at January 1, 2016 | $ | (6 | ) | $ | (56 | ) | $ | (223 | ) | $ | (285 | ) | ||||
| Additional liability | - | (164 | ) | (393 | ) | (557 | ) | |||||||||
| Reversal of accrued bonus | - | - | 718 | 718 | ||||||||||||
| Converted to equity | (54 | ) | - | - | (54 | ) | ||||||||||
| Change in fair value of liability | 60 | (1,180 | ) | (102 | ) | (1,222 | ) | |||||||||
| Balance at December 31, 2016 | $ | - | $ | (1,400 | ) | $ | - | $ | (1,400 | ) | ||||||
| Conversion derivative liability | Bristol/Heartland warrant
| Incentive bonus | Total | |||||||||||||
| Balance at January 1, 2015 | $ | (1,249 | ) | $ | (394 | ) | $ | (40 | ) | $ | (1,683 | ) | ||||
| Additional liability | - | (56 | ) | (149 | ) | (205 | ) | |||||||||
| Change in fair value of liability | 1,243 | 394 | (34 | ) | 1,603 | |||||||||||
| Balance at December 31, 2015 | $ | (6 | ) | $ | (56 | ) | $ | (223 | ) | $ | (285 | ) | ||||
Assets and liabilities measured at fair value on a nonrecurring basis. Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis, but are subject to fair value adjustments in certain circumstances. These assets and liabilities can include proved and unproved oil and gas properties and other long-lived assets that are written down to fair value when they are impaired or held for sale.
Proved oil and gas properties. The Company estimates the expected undiscounted future cash flows of its oil and natural gas properties and compares such amounts to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value are subject to management’s judgement and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates or proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. These assumptions represent Level 3 inputs. Impairment of oil and gas assets for the year ended December 31, 2016 and 2015 was $4.7 million and $24.5 million, respectively.
The following table provides a summary of the non-recurring fair values of assets and liabilities measured at fair value (in thousands):
| December 31, 2016 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| Non-recurring fair value measurements | ||||||||||||||||
| Impairment of proved oil and gas properties | - | - | 4,700 | 4,700 | ||||||||||||
| Total non-recurring fair value measurements | $ | - | $ | - | $ | 4,700 | $ | 4,700 | ||||||||
December 31, 2015 | ||||||||||||||||
| Non-recurring fair value measurements | ||||||||||||||||
| Impairment of proved oil and gas properties | - | - | 24,500 | 24,500 | ||||||||||||
| Total non-recurring fair value measurements | $ | - | $ | - | $ | 24,500 | $ | 24,500 | ||||||||
The Company did not have any transfers of assets or liabilities between Level 1, Level 2 or Level 3 of the fair value measurement hierarchy during the years ended December 31, 2016 and 2015.
| F-41 |
NOTE 7 – ASSET RETIREMENT OBLIGATIONS (ARO)
The information below reconciles the value of the asset retirement obligation for the periods presented (in thousands):
| Year Ended December 31, | ||||||||
| 2016 | 2015 | |||||||
| (In thousands) | ||||||||
| Balance, beginning of year | $ | 208 | $ | 200 | ||||
| Liabilities assumed from the Merger | 777 | - | ||||||
| Liabilities incurred | 311 | - | ||||||
| Accretion expense | 132 | 10 | ||||||
| Conveyance of liability with oil and gas properties conveyance | (92 | ) | - | |||||
| Change in estimate | (79 | ) | (1 | ) | ||||
| Balance, end of year | 1,257 | 209 | ||||||
| Less: current portion of ARO at end of year | (338 | ) | - | |||||
| Total Long-term ARO at end of year | $ | 919 | $ | 209 | ||||
NOTE 8 – LONG-TERM DEBTS
| As of December 31, | ||||||||
| 2016 | 2015 | |||||||
| (In thousands) | ||||||||
| Term Loan: | ||||||||
| 6% Senior Secured Term Loan, due 2019, net of deferred financing costs and debt discount | $ | 29,214 | $ | - | ||||
| Senior Secured Term Loan, interest at prime rate, due 2018, net of deferred financing costs and debt discount | - | 2,492 | ||||||
| 6% note payable to SOS Investment, LLC, due 2019 | 1,000 | - | ||||||
| Convertible Notes: | ||||||||
| 12% convertible related party note, due 2016, net of deferred financing costs and debt discount | - | 1,055 | ||||||
| 12% convertible non-related party note, due 2016, net of deferred financing costs and debt discount | - | 674 | ||||||
| Convertible Debentures: | ||||||||
| 8% convertible debentures, due 2018, net of deferred financing costs and debt discount | 6,846 | |||||||
| Other notes payable | 29 | - | ||||||
| $ | 30,243 | $ | 11,067 | |||||
| Less: current portion | (17 | ) | (11,067 | ) | ||||
| $ | 30,226 | $ | - | |||||
Credit and Guarantee Agreement
On September 29, 2016, the Company entered into a credit and guaranty agreement (the “Credit and Guarantee Agreement”) by and among the Company and its wholly owned subsidiaries, Brushy, ImPetro Operating, LLC (“Operating”) and ImPetro Resources, LLC (“Resources”, and together with Brushy and Operating, the “Initial Guarantors”), and the lenders party thereto (each a “Lender” and together, the “Lenders”) and T.R. Winston & Company, LLC (“TRW”) acting as collateral agent.
The Credit and Guarantee Agreement provides for a three-year senior secured term loan with initial commitments of $31 million, of which $25 million was collected as of September 30, 2016, and the additional $6 million was collected at December 31, 2016. The initial aggregate principal amount may be increased to a maximum principal amount of $50 million at the Company’s request and with the consent of the Lenders holding loans in excess of 60% of the then outstanding loans pursuant to an accordion advance provision in the Credit and Guarantee Agreement (the “Term Loan”).
In connection with the Company’s entry into the Credit and Guarantee Agreement, it incurred commitment fees to each of the Lenders equal to 2.0% of their respective initial loan advances and advisory fees totaled to approximately $1.2 million as of December 31, 2016. The Company accounted for the $1.2 million as deferred financing costs to be amortized over the term of the loan. As partial consideration given to the lenders, we also amended certain warrants issued in the Series B preferred stock offering held by the lenders during the third and fourth quarters of the year ended December 31, 2016, to purchase up to an aggregate amount of approximately 2,850,000 and approximately 672,000, shares of common stock respectively, such that the exercise price per share was lowered from $2.50 to $0.01 on such warrants. The portion repriced in the fourth quarter was due to certain delayed funding that occurred after the initial commitment. Additionally, each lender received a 2.0% commitment fee equal to their respective initial loan advance. All of the amended warrants are immediately exercisable from the original issuance date, for a period of two years, subject to certain conditions. The Company accounted for the reduction in the conversion price as a debt discount of $714,000 and will be accreted over the term of the loan. For the year ended December 31, 2016, the Company amortized approximately $108,000 of deferred financing costs and accreted approximately $119,000 of debt discount relating to the loan. These amounts were recorded as a component of non-cash interest expense. As of December 31, 2016, the unamortized portion of the debt discount and deferred financing costs were $0.6 million and $1.2 million, respectively.
| F-42 |
The Term Loan bears interest at a rate of 6.0% per annum and matures on September 30, 2019. The Company has the right to prepay the Term Loan, in whole or in part, at any time at a prepayment premium equal to 6.0% of the amount repaid. Such prepayment premium must also be paid if the Term Loan is repaid prior to maturity as a result of a change in control. In certain situations, the Credit and Guarantee Agreement requires mandatory prepayments of the Term Loans at the request of the Lenders, including in the event of certain non-ordinary course asset sales, the incurrence of certain debt, and receipt of proceeds in connection with insurance claims.
The Credit and Guarantee Agreement also provides for events of default, including failure to pay any principal or interest when due, failure to perform or observe covenants, cross-default on certain outstanding debt obligations, the failure of a Guarantor to comply with the provisions of its Guaranty, and bankruptcy or insolvency events. The amounts under the Credit Agreement could be accelerated and be due and payable upon an event of default.
SOS Investment LLC Note
On June 30, 2016, pursuant to the Merger Agreement and as a condition of the Fourth Amendment, the Company was required to make a cash payment of $500,000 to SOSV LLC, and also executed a subordinated promissory note with SOSV LLC, for $1 million, at an interest rate of 6% per annum which matures on June 30, 2019. In conjunction with cash payment and the note, the Company also issued 200,000 warrants at an exercise price of $25.00. The Company accounted for the cost of warrants of $0.2 million as part of the Merger transaction costs for the year ended December 31, 2016.
Independent Bank and Promissory Note
On June 22, 2016, in connection with the completion of the Merger, the Company, Brushy and Independent Bank (the “Lender”), Brushy’s senior secured lender, entered into an amendment to Brushy’s forbearance agreement with the Lender (the “Fourth Amendment”), which, among other things, provided for a pay-down of approximately $6.0 million of the principal amount outstanding on the loan (the “Loan”), plus fees and other expenses incurred in connection with the Loan, in exchange for an extension of the maturity date through December 15, 2016, at an interest rate of 6.5%, payable monthly. Additionally, the Company agreed to (i) guaranty the approximately $5.4 million aggregate principal amount of the Loan, (ii) grant a lien in favor of the Lender on all of the Company’s real and personal property, (iii) restrict the incurrence of additional debt and (iv) maintain certain deposit accounts with various restrictions with the Lender. On September 29, 2016, in connection with the Company’s entry into the Credit and Guarantee Agreement, the Company used part of the proceeds of the Term Loan to repay the balance of Brushy’s outstanding indebtedness with Independent Bank in full.
Heartland Bank
On January 8, 2015, the Company entered into the Credit Agreement with Heartland Bank (the “Credit Agreement”), as administrative agent and the Lenders party thereto. The Credit Agreement provided for a three-year senior secured term loan in an initial aggregate principal amount of $3 million, or the Term Loan. On December 29, 2015, after a default on an interest payment and in connection with the Merger, the Company entered into the Forbearance Agreement with Heartland (the “Heartland Forbearance Agreement”). The Heartland Forbearance Agreement, restricted Heartland from exercising any of its remedies until April 30, 2016, which was subject to certain conditions, including a requirement for the Company to make a monthly interest payment to Heartland.
Following the First Amendment to the Credit Agreement entered into on March 1, 2016, on May 4, 2016, as a result of a default on the required March 1, April 1 and May 1 interest payments pursuant to the Forbearance Agreement, the Company entered into a second amendment to the Forbearance Agreement (the “Second Amendment”). Pursuant to the Second Amendment, the limit on the amount of New Subordinated Debt the Company had been permitted to raise was eliminated and the Forbearance Expiration Date was extended to May 31, 2016. As consideration for the forgoing, the Company paid Heartland the overdue interest owed pursuant to the Term Loan and interest due through June 23, 2016 in the approximate amount of $160,000 and reimbursement of a portion of Heartland’s fees and expenses in an approximate amount of $53,000. During the year ended December 31, 2016, the Company amortized approximately $38,000 of debt discount. This amount is recorded as a component of non-cash interest expense. As of December 31, 2016 and 2015, the unamortized deferred financing costs were $0 and $38,000, respectively.
In connection with the consummation of the Merger, on June 23, 2016, the Company repaid the entire balance of its outstanding indebtedness with Heartland at a discount of $250,000 (recognized as a gain in other income (expense), resulting in the elimination of $2.75 million in senior secured debt and the extinguishment of Heartland’s security interest in the assets of the Company.
| F-43 |
Convertible Notes
From December 29, 2015 to January 5, 2016, the Company entered into 12% Convertible Subordinated Note Purchase Agreements with various lending parties, which the Company refers to as the Purchasers, for the issuance of an aggregate principal amount of $3.75 million unsecured subordinated convertible notes, or the Convertible Notes, which includes the $750,000 of short-term notes exchanged for Convertible Notes by the Company and warrants to purchase up to an aggregate of approximately 1,500,000 shares of Common Stock at an exercise price of $2.50 per share. The proceeds from this financing were used to pay a $2 million refundable deposit in connection with the Merger, to fund approximately $1.3 million of interest payments to the Company’s lenders and for its working capital and accounts payable.
The Convertible Notes bear interest at a rate of 12% per annum, payable at maturity on June 30, 2016. The Convertible Notes and the accrued but unpaid interest thereon are convertible in whole or in part from time to time at the option of the holders thereof into shares of the Company’s Common Stock at a conversion price of $5.00. The Convertible Notes may be prepaid in whole or in part (but with payment of accrued interest to the date of prepayment) at any time at a premium of 103% for the first 120 days and a premium of 105% thereafter, so long as no Senior Debt is outstanding. The Convertible Notes contain customary events of default, which, if uncured, entitle each noteholder to accelerate the due date of the unpaid principal amount of, and all accrued and unpaid interest, subject to certain subordination provisions.
Additionally, on March 18, 2016, the Company issued an additional aggregate principal amount of $500,000 of Convertible Notes, which have the same terms and conditions as the Convertible Notes with the exception of the maturity date, which is April 1, 2017. The proceeds from these Convertible Notes were used to make advances to Brushy for payment of operating expenses pending completion of the Merger. These notes were fully converted following the consummation of the Merger.
In connection with the closing of the Merger, on June 23, 2016, certain holders of Convertible Notes in an aggregate principal amount of approximately $4.0 million entered into a Conversion Agreement with the Company (the "Note Conversion Agreement"). The terms of the Note Conversion Agreement provided that the Convertible Notes were automatically converted into Common Stock upon the closing of the Merger. Pursuant to the terms of the Note Conversion Agreement, in exchange for immediate conversion upon closing, the conversion price of the Convertible Notes was reduced to $1.10, which resulted in the issuance of 3,636,366 shares of Common Stock. The modification of such conversion rate resulted in a $3.4 million inducement charge recorded in other expense. Holders of these Convertible Notes waived and forfeited approximately $198,000 rights to receive accrued but unpaid interest.
On August 3, 2016, the Company entered into the first amendment to the Convertible Notes with the remaining holders of approximately $1.8 million of Convertible Notes. Pursuant to the first amendment: (i) the maturity date was changed to January 2, 2017, (ii) the conversion price was adjusted to $1.10 and (iii) the coupon rate was increased to 15% per annum. All accrued and unpaid interest on the Convertible Notes would also be convertible in certain circumstances at the conversion price. Additionally, if the aggregate principal amount outstanding on the Convertible Notes was not either converted by the holder or repaid in full on or before the maturity date, the Company agreed to pay a 25% premium on the maturity date. The Company accounted for the reduction in the conversion price of remaining outstanding convertible notes as an inducement expense and recognized approximately $1.6 million in other income (expense). In exchange for the holders’ willingness to enter into the first amendment, the Company issued to the holders additional warrants to purchase up to approximately 1.65 million shares of Common Stock. The warrants issued were valued using the following variables: (i) stock price of $1.12; (ii) exercise price of $2.50; (iii) contractual life of 3 years; (iv) volatility of 203%; (v) risk free rate of 0.76% for a total value of approximately $1.63 million. This amount was recorded as an inducement expense and an increase to additional paid-in capital.
On September 29, 2016, in connection with the Company’s entry into the Credit and Guarantee Agreement the remaining holders of the Convertible Notes converted the outstanding principal amount of approximately $1.8 million and accrued and unpaid interest in an amount of approximately $138,000 into 1,772,456 shares of Common Stock.
Convertible Debentures
In numerous separate private placement transactions between February 2011 and October 2013, the Company issued an aggregate of approximately $15.6 million of Debentures, secured by mortgages on several of its properties. On January 31, 2014, the Company entered into a debenture conversion agreement (the “First Conversion Agreement”) with all of the holders of the Debentures.
| F-44 |
Pursuant to the terms of the First Conversion Agreement, $9.0 million in Debentures (approximately $8.73 million of principal and $270,000 in interest) was converted by the holders to shares of Common Stock at a conversion price of $20.00 per share. In addition, the Company issued warrants to the Debenture holders to purchase one share of Common Stock for each share issued in connection with the conversion of the Debentures, at an exercise price equal to $25.00 per share.
Under the terms of the First Conversion Agreement, the balance of the Debentures may be converted to Common Stock on the terms provided therein (including the terms related to the warrants) at the election of the holder, subject to receipt of stockholder approval as required by Nasdaq continued listing requirements.
On December 29, 2015, the Company entered into a second agreement with the holders of its Debentures, which provides for the full automatic conversion of Debentures into shares of the Company’s Common Stock at a price of $5.00 per share, upon the receipt of requisite stockholder approval and the consummation of the Merger. If the Debentures are converted on these terms, it would result in the issuance of 1,369,293 shares of Common Stock and the elimination of $8.08 million in short-term debt obligations including accrued but unpaid interest which would be forfeited and cancelled upon conversion pursuant to the terms of the agreement.
On June 23, 2016, pursuant to the terms of the Debenture Conversion Agreement, dated December 29, 2015, the Company's remaining outstanding 8% Convertible Debentures (the “Debentures”) of approximately $6,846,000 converted automatically upon consummation of the Merger. The conversion price was modified from $20.00 per share to $5.00 per share, resulting in the issuance of 1,369,293 shares of Common Stock. In exchange for the reduction in conversion price, all accrued but unpaid interest of approximately $1,835,000 was forgiven by the Debenture holders, resulting in a net gain on the modification and conversion of the Debentures of approximately $602,000 and recorded as other income and expenses in the accompanying consolidated statements of operations. Upon the conversion of the Debentures, the associated conversion liability of approximately $54,000 was reclassified to additional paid-in capital. There were no unamortized deferred financing costs and debt discount at December 31, 2016 and 2015, respectively.
Interest Expense
Interest expense for the years ended December 31, 2016 and 2015 was approximately $4.9 million and $1.7 million, respectively. The non-cash interest expense during the years ended December 31, 2016 and 2015 was approximately $4.2 million and $1.3 million, respectively. The non-cash interest expenses consisted of non-cash interest expense and amortization of the deferred financing costs, accretion of the Debentures payable discount, and Debentures interest paid in Common Stock.
NOTE 9 – COMMITMENTS AND CONTINGENCIES
Environmental and Governmental Regulation
At December 31, 2016, there were no known environmental or regulatory matters which are reasonably expected to result in a material liability to the Company. Many aspects of the oil and gas industry are extensively regulated by federal, state, and local governments in all areas in which the Company has operations. Regulations govern such things as drilling permits, environmental protection and air emissions/pollution control, spacing of wells, the unitization and pooling of properties, reports concerning operations, land use, and various other matters including taxation. Oil and gas industry legislation and administrative regulations are periodically changed for a variety of political, economic, and other reasons. As of December 31, 2016 the Company had not been fined or cited for any violations of governmental regulations that would have a material adverse effect upon the financial condition of the Company.
Legal Proceedings
The Company may from time to time be involved in various legal actions arising in the normal course of business. In the opinion of management, the Company’s liability, if any, in these pending actions would not have a material adverse effect on the financial position of the Company. The Company’s general and administrative expenses would include amounts incurred to resolve claims made against the Company.
The Company believes there is no litigation pending that could have, individually or in the aggregate, a material adverse effect on its results of operations or financial condition.
Operating Leases
The Company has a two-year operating lease for office space in San Antonio, Texas and various other operating leases on a month-to-month basis which include office leases in Denver, Colorado and New York City, New York and corporate apartment leases in San Antonio, Texas. Rent expense for the years ended December 31, 2016 and 2015, was approximately $201,000 and $73,000, respectively. As of December 31, 2016, the Company has approximately $0.4 million of minimum lease payments on its operating lease which consists of annual minimum lease payments of approximately $0.2 million in 2017 and $0.2 million in 2018.
| F-45 |
NOTE 10 – RELATED PARTY TRANSACTIONS
During the years ended December 31, 2016 and 2015, the Company has engaged in the following transactions with related party:
| December 31, | ||||||||||
| Related Party | Transactions | 2016 | 2015 | |||||||
| More than 5% Shareholder: | (In thousands) | |||||||||
| T.R. Winston & Company LLC ("TRW") | Cash paid for Series B Preferred Stock offering fees | $ | 500 | $ | - | |||||
| Reinvest fee for 150 shares of Series B Preferred Stock and 68,182 warrants at exercise price of $2.50 | 150 | - | ||||||||
| Cash paid for advisory fee on Convertible Notes | 350 | - | ||||||||
| Sublet office space in New York to Lilis Energy, Inc for rent of $10,000 per month | 15 | - | ||||||||
| Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 | 400 | - | ||||||||
| Cashless net exercised warrants to purchase 80,000 shares of Common Stock at a reset exercise price of $0.10, resulting in the issuance of 75,820 shares. | - | - | ||||||||
| Total: | $ | 1,415 | $ | - | ||||||
| Steven B. Dunn and Laura Dunn Revocable Trust dated 10/28/10 | Conversion of convertible debentures into common stock | $ | 1,020 | $ | 1,017 | |||||
| Bryan Ezralow (EZ Colony Partners, LLC) | Conversion of convertible debentures into common stock | $ | 1,540 | $ | - | |||||
| Participated in the Series B Preferred offering | 1,300 | - | ||||||||
| Total: | $ | 2,840 | $ | - | ||||||
| Pierre Caland (Wallington Investment Holdings, Ltd.) | Conversion of convertible debentures into common stock | $ | 2,090 | $ | 2,090 | |||||
| Participated in the Series B Preferred offering | 250 | - | ||||||||
| Conversion of Series A Preferred stock into common stock | 125 | - | ||||||||
| Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 | 300 | - | ||||||||
| Total: | $ | 2,765 | $ | 2,090 | ||||||
| Directors and Officers: | ||||||||||
| Nuno Brandolini (Director) | Conversion of Series A Preferred stock into common stock | $ | 100 | $ | - | |||||
| Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 | 250 | 150 | ||||||||
| Total: | $ | 350 | $ | 150 | ||||||
| F-46 |
| General Merrill McPeak (Director) | Conversion of Series A Preferred stock into common stock | $ | 250 | $ | - | |||||
| Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 | 250 | 250 | ||||||||
| Total: | $ | 500 | $ | 250 | ||||||
| R. Glenn Dawson (Director) | Participated in the Series B Preferred offering | $ | 125 | $ | - | |||||
| Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 | 50 | 50 | ||||||||
| Total: | $ | 175 | $ | 50 | ||||||
| Ronald D Ormand (Executive Chairman) | Participated in the Series B Preferred offering through Perugia Investments LP (1) | $ | 1,000 | $ | - | |||||
| Conversion of convertible debentures into common stock through Perugia Investments LP | 500 | - | ||||||||
| Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 through Brian Trust(2) | 1,150 | 1,150 | ||||||||
| Consulting fee paid to MLV & Co. LLC (“MLC”) which Mr. Ormand previously was the Managing Director and Head of the Energy Investment Banking Group at MLV | 100 | 150 | ||||||||
| Total: | $ | 2,750 | $ | 1,300 | ||||||
| Abraham Mirman (Chief Executive Officer and Director) | Participated in the Series B Preferred offering through Bralina Group, LLC(3) | $ | 1,650 | $ | - | |||||
| Conversion of Series A Preferred stock into common stock | 250 | - | ||||||||
| Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 through Bralina Group, LLC | 750 | 1,000 | ||||||||
| Total: | $ | 2,650 | $ | 1,000 | ||||||
| Kevin Nanken (former Executive Vice President and Chief Financial Officer) | Participated in the Series B Preferred offering through KKN Holdings LLC(4) | $ | 200 | $ | - | |||||
| Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 through KKN Holdings LLC | 100 | - | ||||||||
| Total: | $ | 300 | $ | - |
| (1) | Mr. Ormand is the manager of Perugia Investments L.P. ("Perugia") and has sole voting and dispositive power over the securities held by Perugia |
| (2) | An irrevocable trust managed by Jerry Ormand, Mr. Ormand's brother, as trustee and whose beneficiaries are adult children of Mr. Ormand |
| (3) | Mr. Mirman has shared voting and dispositive power over the securities held by The Bralina Group, LLC with Susan Mirman. |
| (4) | Mr, Nanke is the natural person with sole voting and dispositive power over the securities held by KKN Holdings LLC. |
| F-47 |
NOTE 11 – INCOME TAXES
The income tax provision (benefit) for the years ended December 31, 2016 and 2015 consisted of the following:
| December 31, | ||||||||
| 2016 | 2015 | |||||||
| (In thousands) | ||||||||
| U.S. Federal: | ||||||||
| Current | $ | - | $ | - | ||||
| Deferred | (2,971 | ) | (10,560 | ) | ||||
| State and local: | ||||||||
| Current | - | - | ||||||
| Deferred | (124 | ) | (914 | ) | ||||
| (3,095 | ) | (11,474 | ) | |||||
| Change in valuation allowance | 3,095 | 11,474 | ||||||
| Income tax provision | $ | - | $ | - | ||||
The tax effects of temporary differences that give rise to the Company’s deferred tax asset as of December 31, 2016 and 2015 consisted of the following:
| December 31, | ||||||||
| 2016 | 2015 | |||||||
| (In thousands) | ||||||||
| Deferred tax assets: | ||||||||
| Oil and gas properties and equipment | $ | 5,156 | $ | 3,848 | ||||
| Net operating loss carry-forward | 42,017 | 41,389 | ||||||
| Share based compensation | 2,135 | 1,279 | ||||||
| Abandonment obligation | 445 | 77 | ||||||
| Derivative instruments | - | 21 | ||||||
| Accrued liabilities | - | 37 | ||||||
| Debt conversion costs | 482 | 488 | ||||||
| Other | 28 | 29 | ||||||
| Total deferred tax asset | 50,263 | 47,168 | ||||||
| Valuation allowance | (50,263 | ) | (47,168 | ) | ||||
| Deferred tax asset, net of valuation allowance | $ | - | $ | - | ||||
| Deferred tax liabilities: | ||||||||
| Oil and gas properties and equipment | $ | - | $ | - | ||||
| Total deferred tax liability | - | - | ||||||
| Net deferred tax asset (liability) | $ | - | $ | - | ||||
Reconciliation of the Company’s effective tax rate to the expected U.S. federal tax rate is:
| For the Year Ended December 31, | ||||||||
| 2016 | 2015 | |||||||
| Effective federal tax rate | 34.00 | % | 34.00 | % | ||||
| State tax rate, net of federal benefit | 1.42 | % | 2.94 | % | ||||
| Change in fair value derivative liability | -1.32 | % | 1.42 | % | ||||
| Debt discount amortization | -4.11 | % | -0.01 | % | ||||
| Share based compensation differences and forfeitures | -2.28 | % | -4.18 | % | ||||
| Change in rate | -5.90 | % | 2.34 | % | ||||
| Other permanent differences | -12.29 | % | -1.07 | % | ||||
| Other | -0.10 | % | 0.01 | % | ||||
| Valuation allowance | -9.42 | % | -35.45 | % | ||||
| Net | - | % | - | % | ||||
| F-48 |
The net operating losses for these years will not be available to reduce future taxable income until the returns are filed. Assuming these returns are filed, as of December 31, 2016 and 2015, the Company had net operating loss carry-forwards for federal income tax purposes of approximately $118.6 million and $112.0 million, respectively, available to offset future taxable income. To the extent not utilized, the net operating loss carry-forwards as of December 31, 2016 will expire beginning in 2027 through 2036. The net operating loss carryovers may be subject to reduction or limitation by application of Internal Revenue Code Section 382 from the result of ownership changes. A full Section 382 analysis has not been prepared and the Company's net operating losses could be subject to limitation under Section 382.
In assessing the need for a valuation allowance on the Company’s deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon whether future book income is sufficient to reverse existing temporary differences that give rise to deferred tax assets, as well as whether future taxable income is sufficient to utilize net operating loss and credit carryforwards. Assessing the need for, or the sufficiency of, a valuation allowance requires the evaluation of all available evidence, both positive and negative. Management had no positive evidence to consider. Negative evidence considered by management includes cumulative book and tax losses in recent years, forecasted book and tax losses, no taxable income in available carryback years, and no tax planning strategies contemplated to realize the valued deferred tax assets.
As of December 31, 2016 and 2015, management assessed the available positive and negative evidence to estimate if sufficient future taxable income would be generated to use the Company’s deferred tax assets and determined that it is not more-likely-than-not that the deferred tax assets would be realized in the near future. Therefore, the Company recorded a full valuation allowance of approximately $50. million and $47.2 million on its deferred tax assets as of December 31, 2016 and 2015, respectively.
NOTE 12 – STOCKHOLDERS’ EQUITY
May 2014 Private Placement - Series A 8% Convertible Preferred Stock
On May 30, 2014, the Company consummated a private placement of 7,500 shares of Series A Preferred Stock, along with detachable warrants to purchase up to 155,602 shares of Common Stock, at an exercise price of $28.90 per share, for aggregate gross proceeds of $7.50 million. The Series A Preferred Stock has a par value of $0.0001 per share, a stated value of $1,000 per share, a conversion price of $24.10 per share, and a liquidation preference to any junior securities. Except as otherwise required by law, holders of Series A Preferred Stock shall not be entitled to voting rights, except with respect to proposals to alter or change adversely the powers, preferences or rights given to the Series A Preferred Stock, authorize or create any class of stock ranking senior to the Series A Preferred Stock as to dividends, redemption or distribution of assets upon liquidation, amend its certificate of incorporation or other charter documents in any manner that adversely affects any rights of the Preferred Stock holder, or increase the number of authorized Series A Preferred Stock. The holders of the Series A Preferred Stock are entitled to receive a dividend payable, at the election of the Company (subject to certain conditions as set forth in the Certificate of Designations), in cash or shares of Common Stock, at a rate of 8% per annum payable a day after the end of each quarter. The Series A Preferred Stock is convertible at any time at the option of the holders, or at the Company’s discretion when the Common Stock trades above $75.00 for ten consecutive days with a daily dollar trading volume above $300,000. In addition, the Company has the right to redeem the shares of Series A Preferred Stock, along with any accrued and unpaid dividends, at any time, subject to certain conditions as set forth in the Certificate of Designations. In addition, holders of the Series A Preferred Stock can require the Company to redeem the Series A Preferred upon the occurrence of certain triggering events, including (i) failure to timely deliver shares of Common Stock after valid delivery of a notice of conversion by the holder; (ii) failure to have available a sufficient number of authorized and unreserved shares of Common Stock to issue upon conversion; (iii) the occurrence of certain change of control transactions; (iv) the occurrence of certain events of insolvency; and (v) the ineligibility of the Company to electronically transfer its shares via the Depository Trust Company or another established clearing corporation.
In connection with issuance of the Series A Preferred Stock, the beneficial conversion feature (“BCF”) was valued at $2.21 million and the fair value of the warrant was valued at $1.35 million. The aggregate value of the Series A Preferred Stock and warrant, valued at $3.56 million, was considered a deemed dividend and the full amount was expensed immediately. The Company determined the transaction created a beneficial conversion feature which is calculated by taking the net proceeds of $6.79 million and valuing the warrants as of May 2014, utilizing a Black Scholes option pricing model. The inputs for the pricing model are: $24.80 market price per share; exercise price of $28.90 per share; expected life of 3 years; volatility of 70%; and risk free rate of 0.20%. The Company calculated the total consideration given to be $8.40 million comprised of $6.80 million for the Series A Preferred and $1.6 million for the warrants. The Company deemed the value of the beneficial conversion feature to be $2.21 million and immediately accreted that amount as a deemed dividend. As of December 31, 2015, the Company has accrued a cumulative dividend for approximately $0.6 million.
| F-49 |
On June 23, 2016, in connection with the completion of the Merger, each outstanding share of the Company’s Series A Preferred Stock (the “Series A Preferred Stock”) automatically converted into Common Stock at a conversion price of $5.00, resulting in the issuance of 1,500,000 shares of Common Stock with a market value of $1.20 per share. As consideration for the automatic conversion, the Company reduced the conversion price on the Series A Preferred Stock from $24.10 to $5.00. The modification of such conversion price and forgiveness of accrued but unpaid dividend of approximately $0.9 million resulted in a net loss on the conversion of the Series A Preferred Stock of approximately $0.5 million.
Conditionally Redeemable 6% Preferred Stock
In August 2014, the Company designated 2,000 shares of its authorized preferred stock as Conditionally Redeemable 6% Preferred Stock, or the Redeemable Preferred. All 2,000 shares of Redeemable Preferred were issued in September 2014, pursuant to the Settlement Agreement with Hexagon. The Redeemable Preferred has the same par value and stated value characteristics as the Series A Preferred Stock, yet the Conditionally Redeemable 6% Preferred Stock is not convertible into Common Stock or any other securities of the Company. Except as otherwise required by law, holders of the Redeemable Preferred shall not be entitled to voting rights.
The Redeemable Preferred Stock bears a 6% dividend per annum, payable quarterly, and is redeemable at face value (plus any accrued and unpaid dividends) at any time at the Company’s option, or at the Holders option upon the Company’s achievement of certain production and reserves thresholds. These thresholds include, the Company’s annualized gross production average for 90 consecutive days at 2,500 BOE per day or higher or the Company’s PV-10 value of its producing developed properties filed with the Securities and Exchange Commission exceeds $50 million. As of December 31, 2016 and 2015, the Company has accrued a cumulative dividend of $240,000 and $120,000, respectively. The total outstanding Redeemable Preferred was valued at approximately $1.9 million and $1.2 million at December 31, 2016 and 2015, respectively.
Series B 6% Convertible Preferred Stock
On June 15, 2016, the Company entered into a purchase agreement for the private placement of 20,000 shares of its Series B Preferred Stock, along with detachable warrants to purchase up to 9,090,926 shares of Common Stock, at an exercise price of $2.50 per share, for aggregate gross proceeds of $20 million.
Each share of Series B Preferred Stock is convertible, at the option of the holder, subject to adjustment under certain circumstances into shares of Common Stock of the Company at a conversion price of $1.10. Except as otherwise required by law, holders of the Series B Preferred Stock shall not be entitled to voting rights. The Series B Preferred Stock is convertible at any time, subject to certain conditions, at the option of the holders, or at the Company’s discretion when the Company’s Common Stock trades above $10.00 (subject to any reverse or forward stock splits and the like) for ten consecutive days. In addition, the Company has the right to redeem the shares of Series B Preferred Stock, along with any accrued and unpaid dividends, at any time, subject to certain conditions as set forth in the Certificate of Designation. The holders of the Series B Preferred Stock are entitled to receive a dividend payable (subject to certain conditions as set forth in the Certificate of Designation), in cash or shares of Common Stock of the Company, at the election of the Company, at a rate of 6% per annum.
The Series B Preferred Stock is classified as equity based on the following criteria: i) the redemption of the instrument at the control of the Company; ii) the instrument is convertible into a fixed amount of shares at a conversion price of $1.10; iii) the instrument is closely related to the underlying Company’s Common Stock; iv) the conversion option is indexed to the Company’s stock; v) the conversion option cannot be settled in cash and only can be redeemed at the discretion of the Company; vi) and the Series B Preferred Stock is not considered convertible debt.
Shares of the Series B Preferred Stock and related warrants were valued using the relative fair value method. The Company determined the transaction created a beneficial conversion feature of $7.9 million, which was expensed immediately and was calculated by taking the net proceeds of approximately $15.2 million and valuing the warrants as of June 15, 2016, utilizing a Black Scholes option pricing model. The inputs for the pricing model are: $1.20 market price per share; exercise price of $2.50 per share; contractual life of 2 years; volatility of 238%; and risk free rate of 0.78%. As of December 31, 2016, the total value of the issued and outstanding shares of Series B Preferred Stock was approximately $13.4 million.
As of December 31, 2016, approximately 3,000 shares of the Series B Preferred Stock plus approximately $0.06 million of cumulative dividend payable were converted into approximately 2.7 million shares of the Company’s Common Stock at conversion price of $1.10 per share. As of December 31, 2016, the Company accrued approximately $0.6 million of cumulative dividend for Series B Preferred Stock.
| F-50 |
Warrants
A summary of warrant activity for the twelve months ended December 31, 2016 and 2015 (adjusted to reflect 1-for10 reverse stock split on June 23, 2016):
| Warrants | Weighted- Average Exercise Price | |||||||
| Outstanding at January 1, 2015 | 1,700,707 | $ | 1.76 | |||||
| Warrants issued to consultants | 60,000 | 16.30 | ||||||
| Warrants issued to Heartland | 22,500 | 8.70 | ||||||
| Warrants issued with Convertible Notes | 1,180,000 | 2.50 | ||||||
| Exercised, forfeited, or expired | (484,891 | ) | (61.30 | ) | ||||
| Outstanding at December 31, 2015 | 2,478,316 | $ | 14.80 | |||||
| Warrants issued to Series B Preferred Stock | 9,090,926 | 1.54 | ||||||
| Warrants issued for fees | 1,272,727 | 1.30 | ||||||
| Warrants issued with Convertible Notes | 1,145,238 | 2.47 | ||||||
| Warrants issued to amend Convertible Notes | 1,648,267 | 2.50 | ||||||
| Additional warrants issued to Bristol | 541,026 | 3.12 | ||||||
| Warrants issued to SOS in connection with the Merger | 200,000 | 2.50 | ||||||
| Exercised, forfeited, or expired | (460,989 | ) | (34.74 | ) | ||||
| Outstanding at December 31, 2016 | 15,915,511 | $ | 3.34 | |||||
The aggregate intrinsic value associated with outstanding warrants was approximately $18.3 million at December 31, 2016, as the strike price of all warrants exceeded the market price for Common Stock, based on the Company’s closing Common Stock price of $3.10. The weighted average remaining contract life was 1.64 years and 2.13 years as of December 31, 2016 and 2015.
During the year ended December 31, 2016, the Company issued approximately 13.16 million warrants to purchase shares of Common Stock to Purchasers of the Convertible Notes, Purchasers of Series B Preferred Stock and placement agent fees in connection with the Series B Preferred Stock Offering. The Company also issued a warrant to purchase 200,000 shares of Common Stock to Brushy's subordinated lender in exchange for extinguishment of certain debt owed by Brushy.
The fair value of each stock warrant issued is determined using the Black-Scholes-Merton pricing model based on the following variables as summarized in the table below (fair value in thousands):
| Fair Value of Warrants | Number of Warrants | Stock Price | Exercise Price | Expected Volatility | Risk Free Rate | Contractual Life | ||||||||||||||||||||
| As of December 31, 2016: | ||||||||||||||||||||||||||
| Warrants issued for Series B Preferred Stock | $ | 9,486 | 9,090,926 | $ | 1.30 | $ | 2.50 | 238 | % | 0.78 | % | 2 years | ||||||||||||||
| Warrants issued for Series B Preferred Stock offering fees | $ | 1,590 | 1,272,724 | $ | 1.30 | $ | 1.30 | 238 | % | 0.92 | % | 3 years | ||||||||||||||
| Warrants issued with Convertible Notes | $ | 1,446 | 975,051 | $ | 1.70 | $ | 1.00 | 245 | % | 0.75 | % | 2 years | ||||||||||||||
| Warrants issued with Convertible Notes | $ | 277 | 170,187 | $ | 1.70 | $ | 1.10 | 245 | % | 0.75 | % | 3 years | ||||||||||||||
| Warrants issued to amend convertible debts | $ | 1,625 | 1,648,270 | $ | 1.12 | $ | 2.50 | 203 | % | 0.76 | % | 3 years | ||||||||||||||
| Warrants issued to SOS | $ | 170 | 200,000 | $ | 1.20 | $ | 25.00 | 199 | % | 0.76 | % | 3 years | ||||||||||||||
| Additional warrants issued to Bristol | $ | 1,024 | 541,026 | $ | 3.10 | $ | 3.12 | 101 | % | 1.38 | % | 3 years | ||||||||||||||
| As of December 31, 2015: | ||||||||||||||||||||||||||
| Warrants issued for bridge term loan | $ | 1,222 | 1,180,000 | $ | 2.48 | $ | 2.89 | 170 | % | 0.20 | % | 3 years | ||||||||||||||
| Warrants issued for consultants | $ | 425 | 60,000 | $ | 23.30 | $ | 42.50 | 99 | % | 1.29 | % | 5 years | ||||||||||||||
| Warrants issued for Heartland Bank | $ | 56 | 22,500 | $ | 25.00 | $ | 25.00 | 99 | % | 1.29 | % | 5 years | ||||||||||||||
| F-51 |
In connection with the May Financing, in exchange for additional consideration in the form of participation in the May Convertible Notes offering, certain Purchasers received amended and restated warrants to purchase approximately 620,000 shares of Common Stock, which reduced the exercise price of the warrants issued to these Purchasers in each of the prior two Convertible Notes issuances from $2.50 to $0.10, 80,000 of which were subsequently exercised. Additionally, during the three months ended June 30, 2016, in exchange for several offers to immediately exercise a portion of each investor’s outstanding warrants issued between 2013 and 2014, the Company reduced the exercise price on warrants to purchase a total of 416,454 shares of Common Stock ranging from $42.50 to $25.00 per share to $0.10 per share, of which a total of 315,990 were subsequently exercised, resulting in the issuance of an aggregate amount of 300,706 shares of Common Stock due to certain cashless exercises. The Company accounted for the reduction in the exercise price as an inducement expense and recognized $1.72 million in other income (expense).
Additionally, in connection with the Credit and Guarantee Agreement, as partial consideration to the Lenders, the Company also amended certain warrants issued in the Series B private placement held by the Lenders to purchase up to an aggregate amount of approximately 3.5 million shares of Common Stock to date, such that the exercise price per share was lowered from $2.50 to $0.01 on such warrants. The number of warrants amended for each Lender was based on the amount of each Lender’s respective participation in the initial Term Loan relative to the amount invested in the Series B private placement. All of the amended warrants are immediately exercisable from the original issuance date, for a period of two years, subject to certain conditions. For a more detailed description of the terms of the Credit and Guarantee Agreement and the warrant reprice see “Note 8—Loan Agreements—Credit and Guarantee Agreement.”
NOTE 13 – SHARE BASED AND OTHER COMPENSATION
Share-Based Compensation
On April 20, 2016, the Company’s Board and the Compensation Committee of the Board approved the Company’s 2016 Omnibus Incentive Plan (the “2016 Plan”). On November 3, 2016, the Company’s stockholders voted to increase number of shares of Common Stock authorized for issuance under the 2016 Plan to 10.0 million.
During the year ended December 31, 2016, the Company granted 120,000 shares of restricted Common Stock to certain nonemployee directors in connection with each of their appointment anniversaries pursuant to each director's nonemployee director award agreement and 85,000 shares of restricted Common Stock as Board fees for the quarter ended December 31, 2015, paid in stock in lieu of cash. During the year ended December 31, 2016, the Company also issued (i) 10,000 restricted stock units and options to purchase 45,000 shares of Common Stock under the 2016 Plan to a newly appointed director pursuant to his nonemployee director award and 32,052 shares of restricted common stock as compensation for consulting services. Additionally, during the year ended December 31, 2016, the Company granted options to purchase a total of 5,683,500 shares of Common Stock to management and employees under the 2016 Plan.
During the year ended December 31, 2016, certain of the Company's employees, directors and consultants forfeited 26,483 restricted stock units and 335,000 options to purchase Common Stock previously granted in connection with various terminations and forfeitures.
As a result, as of December 31, 2016, the Company had 149,584 restricted stock units, 1,068,305 restricted shares, and 5,956,833 options to purchase shares of Common Stock outstanding to employees and directors. Options issued to employees vest in equal installments over specified time periods during the service period or upon achievement of certain performance based operating thresholds.
The Company requires that employees and directors pay the tax on equity grants in order to issue the shares and there is currently no cashless exercise option. As of December 31, 2016, 149,584 restricted stock units and 1,780,052 restricted shares have been granted, but have not been issued.
| F-52 |
Compensation Costs (in thousands)
| As of December 31, 2016 | As of December 31, 2015 | |||||||||||||||||||||||
| Stock Options | Restricted Stock | Total | Stock Options | Restricted Stock | Total | |||||||||||||||||||
| Stock-based compensation expensed | $ | 4,475 | $ | 2,398 | $ | 6,873 | $ | 2,191 | $ | 469 | $ | 2,660 | ||||||||||||
| Unamortized stock-based compensation costs | $ | 5,200 | $ | 1,249 | $ | 6,449 | $ | 2,091 | $ | 266 | $ | 2,357 | ||||||||||||
| Weighted average amortization period remaining* | 1.68 | 1.45 | 2.18 | 1.05 | ||||||||||||||||||||
* Only includes directors and employees which the options vest over time instead of performance criteria which the performance criteria have not been met as of December 31, 2016 and 2015.
Restricted Stock
Summary of non-cash compensation in Statement of Changes in Stockholders’ Equity:
| As of December 31, | ||||||||
| 2016 | 2015 | |||||||
| (In thousands) | ||||||||
| Statement of Stockholder’s Equity: | ||||||||
| Common stock issued for directors’ fees | $ | 85 | $ | 215 | ||||
| Common stock issued for officer and Board compensation | 120 | - | ||||||
| Stock based compensation for vesting of restricted stock | - | 469 | ||||||
| Stock based compensation for issuance of stock options | 4,475 | 2,191 | ||||||
| Stock based compensation for issuance of restricted stock | 2,398 | - | ||||||
| Common stock issued for professional services | - | 150 | ||||||
| Fair value of warrants issued for professional services | - | 425 | ||||||
| Total non-cash compensation in Statement of Changes in Stockholders’ Equity | $ | 7,078 | $ | 3,450 | ||||
A summary of restricted stock grant activity pursuant to the 2016 Plan for the year ended December 31, 2016 is presented below:
| Number of Shares | Weighted Average Grant Date Price | |||||||
| Outstanding at January 1, 2016 | - | $ | - | |||||
| Granted | 1,780,052 | 1.54 | ||||||
| Vested and issued | (711,747 | ) | (1.75 | ) | ||||
| Forfeited | - | - | ||||||
| Outstanding at December 31, 2016 | 1,068,305 | $ | 1.55 | |||||
There was no restricted stock grant activity for the year ended December 31, 2015.
A summary of restricted stock unit grant activity pursuant to the 2012 Plan for the years ended December 31, 2016 and 2015 is presented below. Share activities for the year ended December 31, 2015 have been adjusted for 1-for-10 reverse stock split on June 23, 2016.
| F-53 |
| Number of Shares | Weighted Average Grant Date Price | |||||||
| Outstanding at January 1, 2015 | 163,067 | $ | 24.40 | |||||
| Granted | 114,501 | 9.00 | ||||||
| Vested and issued | (77,835 | ) | 6.60 | |||||
| Forfeited | (12,833 | ) | 22.70 | |||||
| Outstanding at December 31, 2015 | 186,900 | 12.29 | ||||||
| Granted | - | - | ||||||
| Vested and issued | (10,834 | ) | (18.75 | ) | ||||
| Forfeited | (26,482 | ) | (16.15 | ) | ||||
| Outstanding at December 31, 2016 | $ | 149,584 | $ | 10.56 | ||||
As of December 31, 2016, the total unrecognized compensation costs related to 1,217,889 unvested shares of restricted stock was approximately $1.2 million, which is expected to be recognized over a weighted-average remaining services period of 1.45 year. As of December 31, 2015, the Company had 151,900 shares vested but unissued and total unrecognized compensation cost related to the 34,999 unvested shares of restricted stock was approximately $266,000, which is expected to be recognized over a weighted-average remaining service period of 1.05 years.
Stock Options
A summary of stock options activity for the years ended December 31, 2016 and 2015 is presented below:
| Stock Options Outstanding
and Exercisable | ||||||||||||||||
| Number of Options | Weighted Average Exercise Price | Number of Options Vested/ Exercisable | Weighted Average Remaining Contractual Life (Years) | |||||||||||||
| Outstanding at January 1, 2015 | 358,333 | $ | 21.60 | 138,333 | 4.24 | |||||||||||
| Granted | 480,000 | $ | 12.60 | |||||||||||||
| Exercised | - | |||||||||||||||
| Forfeited or cancelled | (230,000 | ) | $ | (24.60 | ) | |||||||||||
| Outstanding at December 31, 2015 | 608,333 | $ | 14.60 | 296,666 | 4.10 | |||||||||||
| Granted | 5,683,500 | 2.14 | ||||||||||||||
| Exercised | - | |||||||||||||||
| Forfeited or cancelled | (335,000 | ) | (5.34 | ) | ||||||||||||
| Outstanding at December 31, 2016 | 5,956,833 | $ | 2.04 | 2,208,757 | 1.68 | |||||||||||
During 2016, option to purchase 5,683,500 shares of the Company’s common stock were granted under the 2016 Plan. The weighted average fair values of these options of $1.38. The fair values were determined using the Black-Scholes-Merton option valuation method assuming no dividends, a risk-free interest rate of 1.08%, a weighted average expected life of 4.12 years and weighted-average volatility of 152%
As of December 31, 2016, total unrecognized compensation costs relating to the outstanding options was $5.2 million, which is expected to be recognized over the remaining vesting period of approximately 3.68 years.
The outstanding options have an intrinsic value of approximately $12.3 million at December 31, 2016.
During the year ended December 31, 2016 and 2015, the Company issued options to purchase shares of Common Stock to certain officers and directors. The options are valued using a Black Scholes model and amortized over the life of the option. During the years ended December 31, 2016 and 2015, the Company amortized $4.5 million and $2.19 million, respectively relating to options outstanding.
| F-54 |
NOTE 14 – Supplemental Non-cash Transactions
The following table presents information about supplemental cash flows for the years ended December 31, 2016 and 2015 (in thousands);
| 2016 | 2015 | |||||||
| Non-cash investing and financing activities excluded from the statement of cash flows: | ||||||||
| Common stock issued for Series A Preferred Stock and accrued dividends | 7,682 | - | ||||||
| Common stock issued for convertible notes and accrued interest | 14,872 | - | ||||||
| Common stock issued for Brushy’s common stock | 7,111 | - | ||||||
| Common stock issued for Series B Preferred Stock and accrued dividends | 3,230 | - | ||||||
| Warrants issued for fees associated with Series B Preferred Stock issuance | 1,590 | - | ||||||
| Warrants issued for Series B Preferred Stock issuance and recorded as a deemed dividend | 7,879 | - | ||||||
| Fair value of warrants issued as debt discount and financing costs | 2,192 | 1,222 | ||||||
| Disposition of oil and gas assets for elimination of accrued expense for drilling | - | 5,198 | ||||||
NOTE 15 – SUBSEQUENT EVENTS
Credit Agreement Drawdown
On February 7, 2017, pursuant to the terms of the Credit Agreement, we exercised the accordion advance feature, increasing the aggregate principal amount outstanding under the term loan from $31 million to $38.1 million. The total availability for borrowing remaining under the Credit Agreement is $11.9 million. We intend to use the proceeds to fund its drilling and development program, for working capital and for general corporate purposes.
As partial consideration, we also amended certain warrants issued in the June 2016 private placement held by the Lenders to purchase up to an aggregate amount of approximately 738,638 shares of common stock such that the exercise price per share was lowered from $2.50 to $0.01 on such warrants The number of warrants amended for each Lender was based on the amount of each Lender’s respective participation in the initial Term Loan relative to the amount invested in the June 2016 private placement. All of the amended warrants are immediately exercisable from the original issuance date, for a period of two years, subject to certain conditions.
March 2017 Private Placement
On February 28, 2017, we entered into a Securities Subscription Agreement (the “Subscription Agreement”) with certain institutional and accredited investors in connection with a private placement (the “March 2017 Private Placement”) to sell 5.2 million units, consisting of approximately 5.2 million shares of common stock and warrants to purchase approximately an additional 2.6 million. Each unit consists of one share of common stock and a warrant to purchase 0.50 shares of common stock (each, a “Unit”), at a price per unit of $3.85. Each warrant has an exercise price of $4.50 and may be subject to redemption by the Company, upon prior written notice, if the price of the Company’s common stock closes at or above $6.30 for twenty trading days during a consecutive thirty trading day period.
We expect to use the net proceeds from the Offering to support our planned 2017 capital budget, and for general corporate purposes including working capital.
The securities to be sold in the private placement have not been registered under the Securities Act or any state securities laws and may not be offered or sold in the United States absent registration or an applicable exemption from registration. However, in conjunction with the closing of the March 2017 Private Placement, we have also entered into a registration rights agreement whereby we agreed to use our reasonable best efforts to register, on behalf of the investors, the shares of common stock underlying the Units and the shares of common stock underlying the warrants no later than April 1, 2017.
Our 2017 capital budget may require additional financing above the level of cash generated by our operations and proceeds from recent financing activities. We can provide no assurance that additional financing would be available to us on acceptable terms, if
NOTE 16 – SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)
The following table sets forth information for the years ended December 31, 2016 and 2015 with respect to changes in the Company's proved (i.e. proved developed and undeveloped) reserves:
| F-55 |
| Crude Oil (Bbls) | Natural Gas (Mcf) | |||||||
| December 31, 2014 | 899,727 | 4,237,241 | ||||||
| Purchase of reserves | - | - | ||||||
| Revisions of previous estimates | (859,230 | ) | (4,063,500 | ) | ||||
| Extensions, discoveries | - | - | ||||||
| Sale of reserves | - | - | ||||||
| Production | (7,067 | ) | (32,291 | ) | ||||
| December 31, 2015 | 33,430 | 141,450 | ||||||
| Purchase of reserves | 93,972 | 292,018 | ||||||
| Revisions of previous estimates | 455,202 | 3,506,794 | ||||||
| Extensions, discoveries | ||||||||
| Sale of reserves | ||||||||
| Production | (31,899 | ) | (68,756 | ) | ||||
| December 31, 2016 | 550,705 | 3,871,506 | ||||||
| Proved Developed Reserves, included above: | ||||||||
| Balance, December 31, 2014 | 50,185 | 197,146 | ||||||
| Balance, December 31, 2015 | 33,430 | 141,450 | ||||||
| Balance, December 31, 2016 | 550,705 | 3,871,506 | ||||||
| Proved Undeveloped Reserves, included above: | ||||||||
| Balance, December 31, 2014 | 849,542 | 4,040,095 | ||||||
| Balance, December 31, 2015 | - | - | ||||||
| Balance, December 31, 2016 | - | - | ||||||
As of December 31, 2016 and December 31, 2015, the Company had estimated proved reserves of 550,705 and 33,430 barrels of oil, respectively and 3,871,506 and 141,450 thousand cubic feet (“MCF”) of natural gas, respectively. The Company’s reserves are comprised of 46% and 59% crude oil and 54% and 41% natural gas on an energy equivalent basis, as of December 31, 2016 and December 31, 2015, respectively.
The following values for the December 31, 2016 and December 31, 2015 oil and gas reserves are based on the 12 month arithmetic average first of month price January through December 31; resulting in a natural gas price of $2.05 and $2.79 per MMBtu (NYMEX price), respectively, and crude oil price of $37.30 and $42.59 per barrel (West Texas Intermediate price), respectively. All prices are then further adjusted for transportation, quality and basis differentials.
The following summary sets forth the Company's future net cash flows relating to proved oil and gas reserves (in thousands):
| For the Year Ended December 31, | ||||||||
| 2016 | 2015 | |||||||
| Future oil and gas sales | $ | 28,514 | $ | 1,819 | ||||
| Future production costs | (15,939 | ) | (983 | ) | ||||
| Future development costs | (3,388 | ) | - | |||||
| Future income tax expense (1) | - | - | ||||||
| Future net cash flows | 9,187 | 836 | ||||||
| 10% annual discount | (2,531 | ) | (228 | ) | ||||
| Standardized measure of discounted future net cash flows | $ | 6,656 | $ | 608 | ||||
| F-56 |
The principal sources of change in the standardized measure of discounted future net cash flows are (in thousands):
| 2016 | 2015 | |||||||
| Balance at beginning of period | $ | 608 | $ | 23,254 | ||||
| Sales of oil and gas, net | (1,989 | ) | (146 | ) | ||||
| Net change in prices and production costs | (309 | ) | (26,115 | ) | ||||
| Net change in future development costs | 4,617 | 20,626 | ||||||
| Extensions and discoveries | - | - | ||||||
| Acquisition of reserves | 7,919 | - | ||||||
| Sale / conveyance of reserves | - | - | ||||||
| Revisions of previous quantity estimates | 1,087 | (19,336 | ) | |||||
| Previously estimated development costs incurred | (8,942 | ) | - | |||||
| Net change in income taxes | - | - | ||||||
| Change in timing and other | 3,630 | - | ||||||
| Accretion of discount | 35 | 2,325 | ||||||
| Balance at end of period | $ | 6,656 | $ | 608 | ||||
| (1) | Calculations of the standardized measure of discounted future net cash flows include the effect of estimated future income tax expenses for all years reported. The Company expects that all of its Net Operating Loss’ (“NOL”) will be realized within future carry forward periods. All of the Company's operations, and resulting NOLs, are attributable to its oil and gas assets. |
A variety of methodologies are used to determine the Company’s proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields.
| F-57 |
BRUSHY RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
AS OF AND FOR THE THREE MONTHS ENDED MARCH 31, 2016
| F-58 |
BRUSHY RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In thousands, except par value and share data)
March 31, 2016 | December 31, 2015 | |||||||
| (Unaudited) | ||||||||
| ASSETS | ||||||||
| Current assets | ||||||||
| Cash | $ | 864 | $ | 2,839 | ||||
| Trade receivable | 785 | 1,101 | ||||||
| Joint interest receivable | 162 | 172 | ||||||
| Current derivative asset | - | 733 | ||||||
| Prepaid expenses | 124 | 59 | ||||||
| Total current assets | 1,935 | 4,904 | ||||||
| Oil and natural gas properties and other equipment | ||||||||
| Oil and natural gas properties, successful efforts method, net of accumulated depletion and impairment | 16,366 | 16,884 | ||||||
| Other property and equipment, net of depreciation | 63 | 67 | ||||||
| Total oil and natural gas properties and other equipment, net | 16,429 | 16,951 | ||||||
| Other assets | ||||||||
| Goodwill | 960 | 960 | ||||||
| Other | 359 | 359 | ||||||
| Total other assets | 1,319 | 1,319 | ||||||
| Total assets | $ | 19,683 | $ | 23,174 | ||||
The accompanying notes are an integral part of these condensed financial statements
| F-59 |
BRUSHY RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In thousands, except par value and share data)
March 31, 2016 | December 31, 2015 | |||||||
| (Unaudited) | ||||||||
| LIABILITIES AND STOCKHOLDERS’ DEFICIT | ||||||||
| Current liabilities | ||||||||
| Accounts payable and accrued liabilities | $ | 4,728 | $ | 5,564 | ||||
| Going public delay fee | 738 | 738 | ||||||
| Joint interest revenues payable | 1,025 | 1,018 | ||||||
| Current maturities of related party notes payable | 21,718 | 20,892 | ||||||
| Current maturities of notes payable | 13,743 | 14,172 | ||||||
| Current asset retirement obligations | 400 | 392 | ||||||
| Total current liabilities | 42,352 | 42,776 | ||||||
| Long-term liabilities | ||||||||
| Asset retirement obligations | 3,260 | 3,204 | ||||||
| Other long-term liabilities | 30 | 35 | ||||||
| Total long-term liabilities | 3,290 | 3,239 | ||||||
| Commitments and contingencies | ||||||||
| Stockholders’ deficit | ||||||||
| Preferred stock, $.001 par value, authorized 10,000,000 shares; none issued and outstanding | - | - | ||||||
| Common stock, $.001 par value, authorized 150,000,000 shares; 12,711,986 shares issued at March 31, 2016 and December 31, 2015 | 13 | 13 | ||||||
| Additional Paid-in capital | 57,251 | 57,044 | ||||||
| Accumulated deficit | (83,223 | ) | (79,898 | ) | ||||
| Total stockholders’ deficit | (25,959 | ) | (22,841 | ) | ||||
| Total liabilities and stockholders’ deficit | $ | 19,683 | $ | 23,174 | ||||
The accompanying notes are an integral part of these condensed financial statements
| F-60 |
BRUSHY RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In thousands, except share data)
| Three Months Ended March 31, | ||||||||
| 2016 | 2015 | |||||||
| Oil, natural gas, and related product sales | $ | 1,232 | $ | 2,757 | ||||
| Expenses | ||||||||
| Depreciation and depletion | 718 | 2,507 | ||||||
| Lease operating | 908 | 1,126 | ||||||
| General and administrative | 684 | 1,342 | ||||||
| Professional fees | 674 | 211 | ||||||
| Production taxes | 59 | 103 | ||||||
| Accretion of discount on asset retirement obligation | 63 | 63 | ||||||
| Exploration | - | 21 | ||||||
| Total expenses | 3,106 | 5,373 | ||||||
| Operating loss | (1,874 | ) | (2,616 | ) | ||||
| Other expenses | ||||||||
| Interest | (1,100 | ) | (773 | ) | ||||
| Realized gain from derivative contracts | 732 | 616 | ||||||
| Change in fair value of derivative contracts | (733 | ) | (202 | ) | ||||
| Loss on sales of assets | - | (2 | ) | |||||
| Settlement expense | (350 | ) | - | |||||
| Total other expenses | (1,451 | ) | (361 | ) | ||||
| Loss before income taxes | (3,325 | ) | (2,977 | ) | ||||
| Deferred income taxes | - | 288 | ||||||
| Net loss | $ | (3,325 | ) | $ | (2,689 | ) | ||
| Net loss per basic and diluted common shares | $ | (0.26 | ) | $ | (0.22 | ) | ||
| Weighted average basic and diluted common share outstanding | 12,711,986 | 12,482,711 | ||||||
The accompanying notes are an integral part of these condensed financial statements.
| F-61 |
BRUSHY RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands, except per share amounts)
| Three Months Ended March 31, | ||||||||
| 2016 | 2015 | |||||||
| Cash flows from operating activities | ||||||||
| Net loss | $ | (3,325 | ) | $ | (2,689 | ) | ||
| Adjustments to reconcile net loss to net cash used in operating activities: | ||||||||
| Depreciation and depletion | 718 | 2,507 | ||||||
| Deferred income taxes | - | (288 | ) | |||||
| Stock-based compensation | 206 | 506 | ||||||
| Accretion of asset retirement obligation | 63 | 63 | ||||||
| Change in fair value of derivative contracts | 733 | 202 | ||||||
| Loss on asset sales | - | 2 | ||||||
| Amortization of debt issuance costs | 7 | 54 | ||||||
| Increase (decrease) in cash attributable to changes in operating assets and liabilities: | ||||||||
| Trade receivables | 316 | 631 | ||||||
| Joint interest receivables | 10 | 135 | ||||||
| Prepaid expenses and other assets | (65 | ) | 15 | |||||
| Accounts payable and accrued liabilities | (117 | ) | (2,151 | ) | ||||
| Joint interest revenues payable | 7 | (118 | ) | |||||
| Net cash (used) in operating activities | (1,447 | ) | (1,131 | ) | ||||
| Cash flows from investing activities | ||||||||
| Acquisition and development of oil and natural gas properties | (90 | ) | (316 | ) | ||||
| Acquisition of other property and equipment | (4 | ) | - | |||||
| Proceeds from sales of oil and natural gas properties | - | 3 | ||||||
| Net cash (used) in investing activities | (94 | ) | (313 | ) | ||||
| Cash flows from financing activities | ||||||||
| Proceeds from notes payable | 608 | - | ||||||
| Repayments of notes payable | (1,042 | ) | (765 | ) | ||||
| Deferred offering costs | - | (7 | ) | |||||
| Net cash (used) in financing activities | (434 | ) | (772 | ) | ||||
| Net decrease in cash | (1,975 | ) | (2,216 | ) | ||||
| Cash, beginning of period | 2,839 | 3,574 | ||||||
| Cash, end of period | $ | 864 | $ | 1,138 | ||||
| Supplemental disclosure of cash flow information | ||||||||
| Cash paid during the period for interest | $ | 451 | $ | 270 | ||||
| Supplemental disclosure of non-cash investing transactions | ||||||||
| Payables related to oil and natural gas capitalized expenditures | $ | 102 | $ | 298 | ||||
The accompanying notes are an integral part of these condensed financial statements.
| F-62 |
BRUSHY RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
NOTE 1 - NATURE OF OPERATIONS
Brushy was originally formed as Starboard Resources LLC in Delaware on June 2, 2011 as a limited liability company to acquire, own, operate, produce, and develop oil and natural gas properties primarily in Texas and Oklahoma. On June 28, 2012, Starboard converted from a Delaware limited liability company to a Delaware C-Corporation and was named Starboard Resources, Inc. The membership units of Starboard Resources LLC were exchanged on a 1:1 basis for common shares of the Company. On July 31, 2015, Brushy sold substantially all of its Oklahoma producing properties and is primarily now focused on its Texas and New Mexico properties. On August 25, 2015, Starboard changed its name to Brushy Resources, Inc. (“Brushy,” the “Company,” or “its”).
NOTE 2 - GOING CONCERN
The Company’s independent registered public accounting firm for the year ended December 31, 2015 issued their report dated April 20, 2016, that included an explanatory paragraph describing the existence of conditions that raise substantial doubt about the Company’s ability to continue as a going concern due to its significant accumulated deficit, working capital deficit, significant net losses and need to raise additional funds to meet its obligations and sustain its operations.
Given the precipitous decline in oil and natural gas prices during 2015 and into 2016, the Company expects to continue to face liquidity constraints. The Company’s cash flows are negatively impacted by lower realized oil and natural gas sales prices and the significant decline in oil and natural gas prices also increases the uncertainty as to the impact of commodity prices on its estimated proved reserves. As a result, the Company has been in default under the 2013 Credit Agreement between it and Independent Bank, acting for itself and as administrative agent for the other lenders (as amended, the “IB Credit Agreement”) since November 2015. As a result of these defaults, the Company is no longer permitted to make further draws on the IB Credit Agreement and has been subject to a forbearance agreement with the lenders (the “IB Forbearance Agreement”) pursuant to which the lenders agreed to forbear exercising any of their remedies for the existing covenant defaults for a period of time (the “Forbearance Period”) to permit the Company to seek refinancing of the indebtedness owed under the IB Credit Agreement in the approximate amount of $11,000,000, which is referred to as the IB Indebtedness or a sale of sufficient assets to repay the IB Indebtedness. During the Forbearance Period the Company is not permitted to drill new oil or gas wells or make distributions to equity holders. Furthermore, this also cross defaulted the SOSventures Credit Agreement. The Forbearance Period began with the execution of the IB Forbearance Agreement on November 24, 2015 and ended on January 31, 2016, was subsequently extended to March 31, 2016. The Company is currently in discussions with the lender under the IB Credit Agreement regarding a further extension of the Forbearance Period. If the Company does not obtain a further extension of the Forbearance Period, the lenders under the IB Credit Agreement will be able to accelerate the repayment of debt under the IB Credit Agreement. For more information see Note 9 - Notes Payable.
Proposed Merger with Lilis
On December 29, 2015, the Company agreed to combine its business with Lilis pursuant to the Agreement and Plan of Merger (the “merger agreement”). Pursuant to the merger agreement, Lilis Merger Sub, Inc. (“Merger Sub”) will merge with and into Brushy, with Brushy surviving the merger as a wholly-owned subsidiary of Lilis (the “merger”). Upon completion of the merger, each share of the Company’s common stock issued and outstanding immediately prior to the effective time will be converted into the right to receive an amount of shares of Lilis’s common stock such that the Company’s former stockholders will represent approximately 50% of the then-outstanding shares of Lilis’s common stock after the closing of the merger (without taking into account outstanding restricted stock units or options or warrants to purchase shares of Lilis’s common stock). In connection with the merger, the Company is obligated to convey Giddings Field and the Bigfoot Area, to SOSventures, LLC (“SOSventures”), in exchange for a release of its obligations under the subordinated credit agreement with SOSventures, dated March 29, 2013, as amended. The Company expects the closing of the merger to occur in the first half of 2016. However, the merger is subject to the satisfaction or waiver of other conditions, and it is possible that factors outside the Company’s control could result in the merger being completed at an earlier time, a later time or not at all. If the merger has not been completed on or before May 31, 2016, either Lilis or Brushy may terminate the merger agreement unless the failure to complete the merger by that date is due to the failure of the party seeking to terminate the merger agreement to fulfill any material obligations under the merger agreement or a material breach of the merger agreement by such party.
| F-63 |
Collectively, these matters raise substantial doubt about the Company’s ability to continue as a going concern. The Company’s Board of Directors and management team continue to take steps to try to strengthen the Company’s balance sheet. The Company intends to execute the merger (which is subject to usual and customary closing conditions beyond the Company’s control) and, in the event the merger is not consummated, the Company intends to refinance its existing debt, sell non-core properties and seek private financings to fund its cash needs. Any decision regarding the merger or financing transaction, and the Company’s ability to complete such a transaction, will depend on prevailing market conditions and other factors. No assurances can be given that such transactions can be consummated on terms that are acceptable to the Company, or at all. If the Company is unable to restructure its current obligations under its existing outstanding debt and preferred stock instruments, and address near-term liquidity needs, the Company may need to seek relief under the U.S. Bankruptcy Code. This relief may include: (i) seeking bankruptcy court approval for the sale or sales of some, most or substantially all of the Company’s assets pursuant to section 363(b) of the U.S. Bankruptcy Code and a subsequent liquidation of the remaining assets in the bankruptcy case; (ii) pursuing a plan of reorganization (where votes for the plan may be solicited from certain classes of creditors prior to a bankruptcy filing) that the Company would seek to confirm (or “cram down”) despite any classes of creditors who reject or are deemed to have rejected such plan; or (iii) seeking another form of bankruptcy relief, all of which involve uncertainties, potential delays and litigation risks.
NOTE 3 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
The condensed consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”). Additionally, the accompanying unaudited condensed consolidated financial statements as of March 31, 2016 and for the three months ended March 31, 2016 and 2015 have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial statements and with the instructions to Form 10-Q, and reflect, in the opinion of management, all adjustments, which are of a normal and recurring nature, necessary for a fair presentation of the results for such periods. Operating results for the three months ended March 31, 2016 are not necessarily indicative of the results that may be expected for the year ending December 31, 2016. Certain information and footnote disclosures normally included in the consolidated financial statements prepared in accordance with GAAP have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). These condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in the Company’s annual report on Form 10-K for the year ended December 31, 2015 and filed with the SEC on April 20, 2016.
Principles of Consolidation
The accompanying condensed consolidated financial statements include the accounts of the Company together with its wholly owned subsidiaries, ImPetro Resources, LLC (“ImPetro”) and ImPetro Operating (“Operating”) which collectively are referred to as the Company. All intercompany transactions and balances have been eliminated in consolidation.
| F-64 |
Reclassification
In April 2015, the FASB issued ASU No. 2015-03 (“ASU 2015-03”), “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs.” ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, consistent with debt discounts, instead of being presented as an asset. ASU 2015-03 is effective for the Company on January 1, 2016. Once adopted, entities are required to apply the new guidance retrospectively to all prior periods presented. The retrospective application represents a change in accounting principle. Early adoption is permitted for financial statements that have not been previously issued. The Company adopted of this guidance during the first quarter of 2016. The adoption of this guidance did not have a material impact on the Company’s condensed consolidated financial statements.
A $7,000 reclassification from “Prepaid expenses” to a reduction of “Current maturities of related party notes payable” associated with the aforementioned adoption of ASU No. 2015-3, “Interest - Imputation of Interest,” have been made to 2015 condensed consolidated financial statements to conform to the 2016 presentation and have no effect on previously reported net (loss).
Oil and Gas Natural Gas Properties
The Company uses the successful efforts method of accounting for oil and natural gas producing activities, as further defined under ASC 932, Extractive Activities - Oil and Natural Gas . Under these provisions, costs to acquire mineral interests in oil and natural gas properties, to drill exploratory wells that find proved reserves, and to drill and equip development wells are capitalized.
Exploratory drilling costs are capitalized when incurred pending the determination of whether a well has found proved reserves. A determination of whether a well has found proved reserves is made shortly after drilling is completed. The determination is based on a process that relies on interpretations of available geologic, geophysic and engineering data. If a well is determined to be successful, the capitalized drilling costs will be reclassified as part of the cost of the well. Capitalized costs of producing oil and natural gas interests are depleted on a unit-of-production basis at the field level.
If an exploratory well is determined to be unsuccessful, the capitalized drilling costs will be charged to expense in the period the determination is made. If a determination cannot be made as to whether the reserves that have been found can be classified as proved, the cost of drilling the exploratory well is not carried as an asset for more than one year following completion of drilling. If, after that year has passed, a determination that proved reserves exist cannot be made, the well is assumed to be impaired and its costs are charged to expense. Its cost can, however, continue to be capitalized if a sufficient quantity of reserves is discovered in the well to justify its completion as a producing well and the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project.
The carrying value of oil and gas properties is assessed for possible impairment on a field by field basis and on at least an annual basis, or as circumstances warrant, based on geological analysis or changes in proved reserve estimates. When impairment occurs, an adjustment is recorded as a reduction of the asset carrying value. For the three months ended March 31, 2016 and 2015, there were no impairment charge.
| F-65 |
Goodwill
Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. Goodwill is not amortized; rather, it is tested for impairment annually and when events or changes in circumstances indicate that fair value of a reporting unit with goodwill has been reduced below carrying value. The impairment test requires allocating goodwill and other assets and liabilities to reporting units. However, the Company only has one reporting unit. To assess impairment, the Company has the option to qualitatively assess if it is more likely than not that the fair value of the reporting unit is less than the book value. Absent a qualitative assessment, or, through the qualitative assessment, if the Company determines it is more likely than not that the fair value of the reporting unit is less than the book value, a quantitative assessment is prepared to calculate the fair market value of the reporting unit. If it is determined that the fair value of the reporting unit is less than the book value, the recorded goodwill is impaired to its implied fair value with a charge to operating expenses. As of March 31, 2016 and December 31, 2015 there was no impairment of goodwill. Goodwill of $959,681 was from the acquisition of ImPetro on June 13, 2011.
Revenue Recognition and Natural Gas Imbalances
The Company utilizes the accrual method of accounting for natural gas and crude oil revenues, whereby revenues are recognized based on the Company’s net revenue interest in the wells upon delivery to third parties. The Company will also enter into physical contract sale agreements through its normal operations.
Gas imbalances are accounted for using the sales method. Under this method, revenues are recognized based on actual volumes of oil and gas sold to purchasers. However, the Company has no history of significant gas imbalances.
Stock-Based Compensation and Equity Incentive Plans
The Company accounts for stock-based compensation in accordance with ASC 718, Compensation - Stock Compensation. The standard requires the measurement and recognition of compensation expense in the Company’s condensed consolidated statements of operations for all share-based payment awards made to the Company’s employees, directors and consultants including employee stock options, non-vested equity stock and equity stock units, and employee stock purchase grants. Stock-based compensation expense is measured at the grant date, based on the estimated fair value of the award, reduced by an estimate of the annualized rate of expected forfeitures, and is recognized as an expense over the employees’ expected requisite service period, generally using the straight-line method. In addition, ASC 718 requires the benefits of tax deductions in excess of recognized compensation expense to be reported as a financing cash flow, rather than as an operating cash flow as prescribed under previous accounting rules.
The Company’s forfeiture rate represents the historical rate at which the Company’s stock-based awards were surrendered prior to vesting. ASC 718 requires forfeitures to be estimated at the time of grant and revised on a cumulative basis, if necessary, in subsequent periods if actual forfeitures differ from those estimates.
During the three months ended March 31, 2016 and 2015, the Company incurred stock based compensation expense of approximately $206,000 and $506,000, respectively, and is included in the accompanying condensed consolidated statements of operations in general and administrative expenses.
| F-66 |
Net Loss Per Common Share
Basic net loss per common share is computed by dividing the net loss attributable to stockholders by the weighted average number of common shares outstanding during the period. Diluted net loss per common share is calculated in the same manner, but also considers the impact to common shares for the potential dilution from stock options, non-vested share appreciation rights and non-vested restricted shares. For the three months ended March 31, 2016, there were 900,000 potentially dilutive non-vested and vested stock options and 2,542,397 stock warrants. For the three months ended March 31, 2015, there were 900,000 potentially dilutive non-vested restricted shares and stock options. The potentially dilutive shares, for the three months ended March 31, 2016 and 2015, are considered antidilutive since the Company is in a net loss position and thus result in the basic net loss per common share equaling the diluted net loss per common share.
Use of Estimates
The preparation of condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
The Company’s estimates of oil and natural gas reserves are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable natural gas and oil reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future natural gas and oil prices, future operating costs, severance taxes, development costs and workover costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved, undeveloped locations may ultimately increase to the extent that these reserves are later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of expected natural gas and oil attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity of the reserves, which could affect the carrying value of the Company’s oil and natural gas properties and/or the rate of depletion related to the oil and natural gas properties.
The most significant financial estimates are associated with the Company’s estimated volumes of proved oil and natural gas reserves, asset retirement obligations, assessments of impairment imbedded in the carrying value of undeveloped acreages undeveloped properties and developed properties, fair value of financial instruments, including derivative liabilities, depreciation and accretion, income taxes and contingencies.
New Accounting Pronouncement
In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to employee share-based payment accounting, which includes provisions intended to simplify various aspects related to how share-based compensation payments are accounted for and presented in the financial statements. This amendment will be effective prospectively for reporting periods beginning on or after December 15, 2016, and early adoption is permitted. The Company is currently assessing the impact of the ASU on the Company’s condensed consolidated financial statements.
| F-67 |
NOTE 4 - FAIR VALUE MEASUREMENTS
As defined by ASC 820, the fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced or liquidation sale, which was further clarified as the price that would be received to sell an asset or paid to transfer a liability (“an exit price”) in an orderly transaction between market participants at the measurement date. The carrying amounts of the Company’s financial assets and liabilities, such as cash, trade receivable, joint interest receivable, joint interest revenues payable, accounts payable and accrued liabilities and related party payable, approximate their fair values because of the short maturity of these instruments. The carrying amount of the notes payable in long-term debt also approximates fair value due to its variable-rate characteristics.
The following tables present information about the Company’s financial assets and liabilities measured at fair value as of March 31, 2016 and December 31, 2015:
| ($ in thousands) | Level 1 | Level 2 | Level 3 | Balance as of March 31, 2016 | ||||||||||||
| Assets (at fair value): | ||||||||||||||||
| Derivative assets (oil collar and put options) | $ | — | $ | — | $ | — | $ | — | ||||||||
| Liabilities (at fair value): | ||||||||||||||||
| Asset Retirement Obligations | $ | — | $ | — | $ | 3,660 | $ | 3,660 | ||||||||
| ($ in thousands) | Level 1 | Level 2 | Level 3 | Balance as of December 31, 2015 | ||||||||||||
| Assets (at fair value): | ||||||||||||||||
| Derivative assets (oil collar and put options) | $ | — | $ | 733 | $ | — | $ | 733 | ||||||||
| Liabilities (at fair value): | ||||||||||||||||
| Asset Retirement Obligations | $ | — | $ | — | $ | 3,597 | $ | 3,597 | ||||||||
The Company’s derivative contracts consist of NYMEX-based fixed price commodity swaps and NYMEX collars. The NYMEX-based fixed price derivative contracts are indexed to NYMEX futures contracts, which are actively traded, for the underlying commodity and are commonly used in the energy industry. A number of financial institutions and large energy companies act as counter-parties to these type of derivative contracts. As the fair value of these derivative contracts is based on a number of inputs, including contractual volumes and prices stated in each derivative contract, current and future NYMEX commodity prices, and quantitative models that are based upon readily observable market parameters that are actively quoted and can be validated through external sources, the Company have characterized these derivative contracts as Level 2.
The asset retirement liability is measured using primarily Level 3 inputs. The significant unobservable inputs to this fair value measurement include estimates of plugging costs, remediation costs, inflation rate and well life. The inputs are calculated based on historical data as well as current estimated costs. See Note 7 - Asset Retirement Obligations.
The Company estimates the expected undiscounted future cash flows of its oil and natural gas properties and compares such amounts to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates or proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. These assumptions represent Level 3 inputs.
| F-68 |
NOTE 5 - PROPERTY ACQUISITION AND DIVESTITURE
On July 31, 2015, the Company sold all of its Oklahoma properties, which were located in Logan and Kingfisher Counties, Oklahoma, to Remora Petroleum, LP (Austin, TX) for $7,249,390. The purchaser is not affiliated with any Company officers, directors or stockholders.
The following table summarized the results of operation from the properties sold during three months ended March 31, 2015:
| Oil, natural gas, and related product sales | $ | 720 | ||
| Expenses | 138 | |||
| Operating income | $ | 582 |
As part of this transaction, the Company entered into the Fifth Amendment to its Credit Agreement with Independent Bank (“Fifth Amendment”). The Fifth Amendment provides that $4,000,000 of the purchase price was paid to Independent Bank to pay down its credit facility with Independent Bank.
NOTE 6 - OIL AND NATURAL GAS PROPERTIES
The following table presents a summary of the Company’s oil and natural gas properties at March 31, 2016 and December 31, 2015:
| ($ in thousands) | March 31, 2016 | December 31, 2015 | ||||||
| Oil and natural gas properties | ||||||||
| Proved-developed producing properties | $ | 43,710 | $ | 43,912 | ||||
| Proved-developed non-producing properties | 6,228 | 5,865 | ||||||
| Proved-undeveloped properties | - | - | ||||||
| Unproved properties | 2,420 | 2,389 | ||||||
| Gross oil and natural gas properties | 52,358 | 52,166 | ||||||
| Less: Accumulated depletion | (35,992 | ) | (35,282 | ) | ||||
| Total oil and natural gas properties, net of accumulated depletion and impairment | $ | 16,366 | $ | 16,884 | ||||
During the three months ended March 31, 2016 and 2015, the Company incurred depletion expense of approximately $710,000 and $2,495,000, respectively. As of March 31, 2016 and December 31, 2015, the accumulated impairment was approximately $55,985,000.
NOTE 7 - ASSET RETIREMENT OBLIGATIONS
The Company has recognized the fair value of its asset retirement obligations related to the future costs of plugging, abandonment, and remediation of oil and natural gas producing properties. The present value of the estimated asset retirement obligations has been capitalized as part of the carrying amount of the related oil and natural gas properties. The liability has been accreted to its present value as of the end of each period. At December 31, 2015 and December 31, 2014, the Company evaluated 147 and 169 wells, respectively, and has determined a range of abandonment dates between April 2016 and October 2044. The following table represents a reconciliation of the asset retirement obligations for the three months ended March 31, 2016 and the year ended December 31, 2015:
| F-69 |
Three Months Ended March 31, 2016 | Year Ended December 31, 2015 | |||||||
| ($ in thousands) | ||||||||
| Asset retirement obligations, beginning of period | $ | 3,597 | $ | 3.606 | ||||
| Additions to asset retirement obligation | - | - | ||||||
| Liabilities settled during the period | - | (155 | ) | |||||
| Accretion of discount | 63 | 187 | ||||||
| Revision of estimate | - | (41 | ) | |||||
| Asset retirement obligations, end of period | $ | 3,660 | $ | 3,597 | ||||
During the three months ended March 31, 2016 and 2015, the Company incurred accretion expense of approximately $63,000 and $63,000, respectively. As of March 31, 2016 and December 31, 2015, the current asset retirement obligation was approximately $400,000 and $392,000 respectively, and the long term asset retirement obligation was approximately $3,260,000 and $3,204,000, respectively.
See Note 4 - Fair Value Measurements.
NOTE 8 - DERIVATIVES
The Company uses derivatives to hedge its oil production. The Company’s hedge position as of December 31, 2015 consisted of put options, some of which were deferred premiums paid at settlement. As of March 31, 2016, pursuant to the IB Forbearance Agreement, the Company did not have any remaining hedge positions. Specifically, the Company unwound the remaining existing hedge contract with Cargill and Cargill paid Independent Bank all hedge settlement proceeds, all hedge liquidation proceeds, and all amounts otherwise payable by Cargill to the Company. Such payments satisfied outstanding interest and default interest owing to Independent Bank as well as certain other expenses.
Fair Value of Derivative Financial Instruments
| ($ in thousands) | March 31, 2016 | December 31, 2015 | ||||||
| Derivative financial instruments - Current asset | $ | - | $ | 733 | ||||
| Derivative financial instruments - Long-term assets | - | - | ||||||
| Net derivative financial instruments | $ | - | $ | 733 | ||||
Effect of Derivative Financial Instruments
Three Months Ended March 31, | ||||||||
| ($ in thousands) | 2016 | 2015 | ||||||
| Realized gain/(loss) on settlement of derivative contracts | $ | 732 | $ | 616 | ||||
| Change in fair value of derivative contracts | $ | (733 | ) | $ | (202 | ) | ||
| F-70 |
NOTE 9 - NOTES PAYABLE
On June 27, 2013, the Company entered into the IB Credit Agreement to borrow up to $100,000,000 at a current rate of 4.00% annum. The IB Credit Agreement was obtained to fund the development of the Company’s oil and natural gas properties and refinance the prior bank facility. At March 31, 2016 and December 31, 2015, the Company had approximately $11,363,000 and $12,400,000 in borrowings outstanding under the IB Credit Agreement, respectively.
In November 2015, counsel for Independent Bank notified the Company that it was in default under IB Credit Agreement.
On November 24, 2015, the Company entered into the IB Forbearance Agreement and the Third Amendment to the IB Credit Agreement with Independent Bank under which Independent Bank, acting for itself and as administrative agent for other lenders, agreed to forbear exercising any of its remedies for the existing covenant defaults for period of time to permit the Company to seek refinancing of the indebtedness owed to Independent Bank, which is referred to as the IB Indebtedness or a sale of sufficient assets to repay the IB Indebtedness. The Forbearance Period began with the execution of the IB Forbearance Agreement on November 24, 2015 and ended on January 31, 2016. The Forbearance Period was subsequently extended to March 31, 2016.
At the time of the extension of the Forbearance Period to March 31, 2016, the Company agreed to unwind the remaining existing hedge contract with Cargill and permit Cargill to pay to Independent Bank all hedge settlement proceeds, all hedge liquidation proceeds, and all amounts otherwise payable by Cargill to the Company. Such payments satisfied outstanding interest and default interest owing to Independent Bank as well as certain other expenses. In addition, such payments reduced the principal due Independent Bank by $406,720.
During the Forbearance Period, the Company is not permitted to drill new oil or gas wells or to make any distributions to equity holders. Furthermore, this default also cross defaulted the SOSVentures Credit Agreement, however the maturity of the second lien note to SOSventures was extended to August 1, 2016.
The Company is currently in discussions with the lenders under the IB Credit Agreement regarding a further extension of the Forbearance Period. The Company is also in discussions with Lilis and other financing parties regarding possible refinance options for the amount outstanding under the IB Credit Agreement
On December 29, 2015, the Company entered into the merger agreement. At March 31, 2016 and December 31, 2015, the refundable deposit paid by Lilis to the Company was approximately $2,358,000 and $1,750,000, respectively.
NOTE 10 - STOCK BASED COMPENSATION AND CONDITIONAL PERFORMANCE AWARDS
On April 1, 2012, the Company entered into employment agreements (the “Employment Agreement”) which provided a restricted stock grant and a conditional performance award to key members of management.
The restricted stock grant of 349,650 shares had a grant date fair value of $10.00 per share as approved by the Company’s compensation committee and vests in full upon the earlier of an initial public offering (“IPO”) which includes the sale of shares to the public, a business combination whereas 50% or more of the voting power is transferred to the new owners, or March 1, 2015. Those 349,650 shares were earned by the employee recipients and issued to them during the three months ended March 31, 2015.
During the three months ended March 31, 2016 and 2015, the Company incurred a stock-based compensation expense of approximately $0 and $300,000, respectively, related to the restricted stock grant, which is included in the accompanying condensed consolidated statements of operations in general and administrative expenses.
| F-71 |
Additionally, the Employment Agreement provides for a conditional performance award if an IPO occurs, the employee will receive: (1) a cash payment of 1% of the difference between the Company market capital and the book value at the time of the IPO, (2) common stock options to purchase 1.0% of the fully-diluted capital stock as of the IPO date and IPO price which will vest over a four year period and contain a cashless exercise, (3) common stock options to purchase 1.0% of the fully-diluted capital stock as of the 2nd anniversary of the IPO date at the closing price of the common stock on the 2nd anniversary date of the IPO and will vest six years after the grant and contain a cashless exercise. As of the three months ended March 31, 2016 and 2015, the conditional performance feature is not probable and as such, no compensation expense related to the conditional performance feature has been recognized.
On August 30, 2014, the Company amended and restated the Employment Agreement which provided for additional stock options.
The equity award of options to purchase 900,000 shares of common stock at the exercise price of $4.75 per share and vesting over three years from September 4, 2014 with a one-year cliff (in respect of 300,000 shares) and monthly vesting thereafter of 25,000 shares over the remaining two years. During the three months ended March 31, 2016 and 2015, the Company incurred a stock-based compensation expense of approximately $206,000 in both years related to stock options, which is included in the accompanying condensed consolidated statements of operations in general and administrative expenses. As of March 31, 2016, there was approximately $1,169,000 of unrecognized stock-based compensation related to the non-vested stock options to be recognized over 1.42 years.
The assumptions used in the Black-Scholes Option Pricing Model for the stock options granted were as follows:
| 2014 | ||||
| Risk-free interest rate | 1.87 | % | ||
| Expected volatility of common stock | 92 | % | ||
| Dividend yield | $ | 0.00 | ||
| Expected life of options | 5.72 years | |||
For the three months ended March 31, 2016, there were no new stock options granted. As of March 31, 2016, there were 900,000 stock options outstanding and the intrinsic value of the associated options was zero. The weighted average exercise of $4.75/share, weighted average grant date fair value of $2.75/share and the weighted average remaining contractual life of 8.3 years. On March 31, 2016, 500,000 stock options were exercisable.
NOTE 11 - RELATED PARTY TRANSACTIONS
Subordinated Credit Facility with SOSVentures
A director currently serving on the Company’s Board of Directors, Bill Liao, works for SOSventures. Further, a group composed of SOSventures, Sean O’Sullivan Revocable Living Trust and Bradford R. Higgins constitute a group owning 4,863,720 or 39.34% of the Company’s common stock shares.
On June 3, 2014, the Company agreed to amend its credit agreement with SOSventures, originally entered into on July 25, 2013, providing for a term loan through February 16, 2016 in an amount up to $20,000,000 at an 18.00% interest rate. The loan under this agreement is secured by a second lien on the Company’s assets.
The SOSventures credit agreement requires the Company to maintain certain financial ratios. First, the Company must maintain an interest coverage ratio of 3:1 at the end of each quarter so that its consolidated net income less the Company’s fees under the credit facility, lender expenses, non-cash charges relating to the hedge agreements, interest, income taxes, depreciation, depletion, amortization, exploration expenditures and costs and other non-cash charges (netted for noncash income) (“EBITDAX”) is greater than 3 times the Company’s interest expense under the credit facility. Second, the Company must maintain a debt to EBITDAX ratio of less than 3.5:1 at the end of each quarter. Third, the Company must maintain a current ratio of at greater than 1:1 at the end of each quarter, meaning that the Company’s consolidated current assets (including the unused amount of the credit facility by excluding non-cash assets under ASC 410 and 815) must be greater than the Company’s consolidated current liabilities (excluding non-cash obligations under ASC 410 and 815 and current maturities under the credit facility.) The credit agreement prevents the Company from incurring indebtedness to banks or lenders, other than Independent Bank, without the consent of SOSventures. It also prevents the Company from incurring most contingent obligations or liens (other than to Independent Bank). It also restricts the Company’s ability to pay dividends, issue options and warrants and repurchase the Company’s common stock shares. The limitation on options and warrants does not apply to equity compensation plans.
| F-72 |
This credit facility is currently in default due to the default under the IB Credit Agreement.
As of March 31, 2016, with accrued and unpaid interest the Company has $21,718,000 drawn against the SOSventures credit facility. In light of the December 19, 2014 notice from Independent Bank relating to the payment of interest to SOSventures, pursuant to the Intercreditors Agreement, the Company is accruing interest payments to SOSventures since the date of that notice.
NOTE 12 - LEGAL PROCEEDINGS
From time-to-time, the Company may become subject to proceedings, lawsuits and other claims in the ordinary course of business including proceedings related to environmental and other matters. Such matters are subject to many uncertainties, and outcomes are not predictable with assurance.
The Company is subject to various possible contingencies that arise primarily from interpretation of federal and state laws and regulations affecting the oil and natural gas industry. Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Although management believes that it has complied with the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued. In addition, environmental matters are subject to regulation by various federal and state agencies.
Lawsuit Relating to 17.23% of the Company’s Common Stock Shares
Approximately 17.23% of the Company common stock was interpleaded into Connecticut Superior Court for the Judicial District of Stamford/Norwalk at Stamford, Cause No. FST-CV12-6015112-S (“Interpleader Action”). These are the residual shares of common stock that belonged to the Partnerships, after the distribution of the partnerships shares. Claims related to the Interpleader Action were heard in an American Arbitration Association arbitration in 2015. The claims, counterclaims and cross claims relate to the governance, control and termination of the Partnerships, including the distribution by the Partnerships of the Company’s shares of common stock to the limited partners in the Partnerships in a liquidating distribution in February 2014 as part of a “monetization” event, and other matters. On September 10, 2015, the American Arbitration Association issued an arbitration award in the Interpleader Action.
Bexar County Proceedings
On April 17, 2015,the Company was served with a lawsuit filed in Bexar County, Texas (the “Bexar County Proceedings”) by William F. Pettinati, Jr., Nicholas Garofolo, Sigma Gas Barbastella Fund and Sigma Gas Antrozous Fund against Starboard (now Brushy), its directors, its Chief Operating Officer, Edward Shaw, its former Chief Financial Officer, Eric Alfuth, the Company’s stockholder, Bradford Higgins, and Sean O’Sullivan, the managing director of the Company’s stockholder, SOSventures (the “Plaintiffs”). Mr. Pettinati, Mr. Garofolo and the Sigma Gas Antrozous Fund are stockholders. Mr. Pettinati owns 145,112 shares, Mr. Garofolo owns 226,680 shares of common stock and Sigma Gas Antrozous Fund owns 44,610 shares of common stock. Combined these stockholders account for approximately 3.3% of the Company’s outstanding common stock. These parties became stockholders in February 2014.
| F-73 |
The Plaintiffs allege several derivative and direct causes of action. These derivative claims include, breach of fiduciary duty, waste of corporate assets, concerted action and conspiracy, joint enterprise, agency, alter ego, exemplary damages, and unjust enrichment. The direct claims include, breach of fiduciary duty, conversion, stockholder oppression, concerted action and conspiracy, declaratory judgment that the distribution of stock to the plaintiffs was invalid, joint enterprise, agency, alter ego, exemplary damages, concerted action and conspiracy and failure to allow for inspection of books and records. Many of the allegations relate to events that allegedly happened before the Plaintiffs became stockholders, including the distributions from the Partnerships that led to the Plaintiffs becoming stockholders in February 2014. Some similar claims involving these Plaintiffs (including the legality of the Partnerships’ liquidating distribution) were previously heard in the arbitration relating to the Partnerships referenced above. Plaintiffs were parties to that arbitration. For actions after February 2014, Plaintiffs complain that the Company’s common stock still lacks a trading venue, that a books and records request was not honored, that the Company “delayed” a public offering, that SOSventures had allegedly taken steps to “foreclose” on the Company’s assets under the SOSventures Credit Agreement and that the Company filed for an extension to the filing date for the Company’s annual report on Form 10-K for the year ended December 31, 2014. On October 6, 2015, Plaintiffs withdrew the claim about not honoring a books and records request.
The Company’s directors and officers are subject to indemnification under the Company’s bylaws.
Settlement of Interpleader Action and Bexar County Proceedings
On February 17, 2016, the various parties to the Interpleader Action and the Bexar County Proceedings entered into a global settlement agreement (the “Settlement Agreement”) under which the parties to the proceedings issued mutual releases and the plaintiffs in all proceedings agreed to withdraw their claims. In return, the plaintiffs received a cash settlement, the majority of which was covered by the Company’s insurance. $350,000 of the settlement payment will be due and payable by the Company on the first to occur of (a) consummation of the merger with Lilis and (b) July 31, 2016.
NOTE 13 - STOCKHOLDERS’ EQUITY
Warrants
Upon entering into the Second Amendment to the First Amended and Restated Credit Agreement on April 15, 2015 with SOSVentures, SOSVentures received warrants to purchase 2,542,397 shares of the Company’s common stock for $1.00 per share with a two-year term. The intrinsic value associated with the outstanding warrants was zero at March 31, 2016, as the strike price of all warrants exceeded the implied market price for common stock. The remaining contract life was 1 year. The implied value of the warrants were based on the Company’s peer group, which included Company’s owning assets in the same areas and of similar size. This valuation determined that the value of the warrants was approximately zero. As such, the Company has placed no value on the warrants issued.
NOTE 14 - SUBSEQUENT EVENTS
Special Meeting of Stockholders Regarding Merger Agreement
On May 20, 2016, the Company held a special meeting of stockholders to consider and vote on (1) a proposal to approve and adopt the merger agreement; and (2) a proposal to authorize the Company’s board of directors, in its discretion, to adjourn the special meeting to a later date or dates, if necessary or appropriate, to solicit additional proxies in favor of the proposal to approve and adopt the Merger Agreement. The proposals were approved by the Company’s stockholders.
| F-74 |
Third Amendment to Forbearance Agreement with Independent Bank
On May 20, 2016, the Company, ImPetro and Operating entered into the Third Amendment to the Forbearance agreement (the “Third Amendment”) with Independent Bank, pursuant to which Independent Bank agreed to extend the Forbearance Period to May 31, 2016 (and in certain circumstances June 15, 2016) upon payment by the Company of (i) $79,772.64, such payment representing non-default and default interest accrued and to be accrued through May 31, 2016, and (ii) $30,000, such payment representing legal fees and expenses incurred by Independent Bank in connection with the Third Amendment. In the event the Company pays Independent Bank, on or before May 31, 2016, an additional $18,938.11, the Forbearance Period will be extended to June 15, 2016. On May 20, 2016, the above referenced payments were made to Independent Bank by the Company.
| F-75 |
BRUSHY RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED FINANCIAL STATEMENTS
AND
REPORT OF INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM
DECEMBER 31, 2015 AND 2014
| F-76 |
BRUSHY RESOURCES, INC. AND SUBSIDIARIES
| Reports of Independent Registered Public Accounting Firms | F-56 and F-57 |
| Financial Statements | |
| Consolidated Balance Sheets | F-58 |
| Consolidated Statements of Operations | F-59 |
| Consolidated Statements of Changes in Stockholders' (Deficit) Equity | F-60 |
| Consolidated Statements of Cash Flows | F-61 - F-62 |
| Notes to Consolidated Financial Statements | F-63 - F-86 |
| Supplemental Information | |
| Supplemental Oil and Natural Gas Disclosures | F-88 - F-94 |
| F-77 |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Audit Committee of the
Board of Directors and Shareholders
of Brushy Resources, Inc.
We have audited the accompanying consolidated balance sheet of Brushy Resources, Inc. and Subsidiaries (the “Company”) as of December 31, 2015, and the related consolidated statements of operations, changes in stockholders’ (deficit)/equity and cash flows for the year then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Brushy Resources, Inc. and Subsidiaries, as of December 31, 2015, and the consolidated results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.
The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. A more fully described in Note 2, the Company has a significant accumulated and working capital deficit, incurred significant net losses, in default of its loan agreements and needs to raise additional funds to meet its obligations and sustain its operations. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
| /s/ Marcum LLP | |
| Marcum llp | |
| New York, NY | |
| April 20, 2016 |
| F-78 |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Starboard Resources, Inc.:
We have audited the accompanying consolidated balance sheet of Starboard Resources, Inc. and subsidiaries as of December 31, 2014, and the related consolidated statement of operations, changes in stockholders’ equity, and cash flows for the year then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Starboard Resources, Inc. and subsidiaries as of December 31, 2014, and the results of their operations and their cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles.
| KPMG LLP | /s/ KPMG LLP |
Dallas, Texas
April 15, 2015
| F-79 |
BRUSHY RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
| December 31, | 2015 | 2014 | ||||||
| ASSETS | ||||||||
| Current assets | ||||||||
| Cash | $ | 2,839,266 | $ | 3,574,427 | ||||
| Trade receivable | 1,101,161 | 1,860,293 | ||||||
| Joint interest receivable | 171,501 | 508,001 | ||||||
| Current derivative asset | 733,131 | 1,699,156 | ||||||
| Prepaid expenses | 66,120 | 283,580 | ||||||
| Total current assets | 4,911,179 | 7,925,457 | ||||||
| Oil and natural gas properties and other equipment | ||||||||
| Oil and natural gas properties, successful efforts method, net of accumulated depletion and impairment | 16,883,758 | 91,766,118 | ||||||
| Other property and equipment, net of depreciation | 67,321 | 103,757 | ||||||
| Total oil and natural gas properties and other equipment, net | 16,951,079 | 91,869,875 | ||||||
| Other assets | ||||||||
| Derivative asset | - | 66,930 | ||||||
| Goodwill | 959,681 | 959,681 | ||||||
| Other | 358,752 | 981,283 | ||||||
| Total other assets | 1,318,433 | 2,007,894 | ||||||
| Total assets | $ | 23,180,691 | $ | 101,803,226 | ||||
| LIABILITIES AND STOCKHOLDERS' (DEFICIT) EQUITY | ||||||||
| Current liabilities | ||||||||
| Accounts payable and accrued liabilities | $ | 5,563,473 | $ | 5,096,825 | ||||
| Going public delay fee | 738,320 | 738,320 | ||||||
| Joint interest revenues payable | 1,017,823 | 828,924 | ||||||
| Current maturities of related party notes payable | 20,898,750 | - | ||||||
| Current maturities of notes payable | 14,171,713 | 2,353,322 | ||||||
| Current asset retirement obligations | 392,398 | 428,258 | ||||||
| Total current liabilities | 42,782,477 | 9,445,649 | ||||||
| Long-term liabilities | ||||||||
| Notes payable | - | 23,104,333 | ||||||
| Related party note payable | - | 10,180,000 | ||||||
| Deferred tax liabilities | - | 14,039,742 | ||||||
| Asset retirement obligations | 3,204,160 | 3,177,295 | ||||||
| Other long-term liabilities | 35,147 | 57,234 | ||||||
| Total long-term liabilities | 3,239,307 | 50,558,604 | ||||||
| Commitments and contingencies | ||||||||
| Stockholders' (deficit) equity | ||||||||
| Preferred stock, $.001 par value, authorized 10,000,000 shares; none issued and outstanding | ||||||||
| Common stock, $.001 par value, authorized 150,000,000 shares; 12,711,986 and 12,362,336 shares issued at December 31, 2015, and 2014, respectively | 12,712 | 12,362 | ||||||
| Additional Paid-in capital | 57,044,255 | 55,919,905 | ||||||
| Accumulated deficit | (79,898,060 | ) | (14,133,294 | ) | ||||
| Total stockholders' (deficit) equity | (22,841,093 | ) | 41,798,973 | |||||
| Total liabilities and stockholders' (deficit) / equity | $ | 23,180,691 | $ | 101,803,226 | ||||
| F-80 |
BRUSHY RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
| Years Ended December 31, | 2015 | 2014 | ||||||
| Oil, natural gas, and related product sales | $ | 8,606,606 | $ | 20,172,792 | ||||
| Expenses | ||||||||
| Depreciation and depletion | 22,510,290 | 10,140,152 | ||||||
| Lease operating | 3,677,845 | 5,457,471 | ||||||
| General and administrative | 3,938,291 | 3,876,698 | ||||||
| Professional fees | 1,041,527 | 986,774 | ||||||
| Production taxes | 369,317 | 695,693 | ||||||
| Accretion of discount on asset retirement obligation | 187,183 | 319,703 | ||||||
| Exploration | 49,531 | 80,853 | ||||||
| Impairment of oil and gas properties | 55,753,481 | 4,428,378 | ||||||
| Gain on sale of assets | (2,375,333 | ) | (2,115,967 | ) | ||||
| Total expenses | 85,152,132 | 23,869,435 | ||||||
| Operating loss | (76,545,526 | ) | (3,696,643 | ) | ||||
| Other expenses | ||||||||
| Interest | (4,149,251 | ) | (2,617,481 | ) | ||||
| Realized gain from derivative contracts | 2,302,860 | 185,891 | ||||||
| Change in fair value of derivative contracts | (1,032,955 | ) | 1,880,107 | |||||
| Other expenses | (396,793 | ) | - | |||||
| Total other expenses | (3,276,139 | ) | (551,483 | ) | ||||
| Loss before income taxes | (79,821,665 | ) | (4,248,126 | ) | ||||
| Income tax (expense) benefit: | ||||||||
| Current income taxes (expense) benefit | 17,157 | (15,465 | ) | |||||
| Deferred income taxes | 14,039,742 | 1,502,671 | ||||||
| Total income tax expenses | 14,056,899 | 1,487,206 | ||||||
| Net loss | $ | (65,764,766 | ) | $ | (2,760,920 | ) | ||
| Net loss per basic and diluted common shares | $ | (5.20 | ) | $ | (0.22 | ) | ||
| Weighted average basic and diluted common share outstanding | 12,655,467 | 12,362,336 | ||||||
| F-81 |
BRUSHY RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' (DEFICIT) / EQUITY
Years Ended December 31, 2015 and 2014
Common Stock ($.001 Par Value) | Paid-In Capital in | Retained Earnings | ||||||||||||||||||
| Shares | Amount | Excess of Par | (Deficit) | Total | ||||||||||||||||
| Balances, January 1, 2014 | 12,362,336 | $ | 12,362 | $ | 54,446,105 | $ | (11,372,374 | ) | $ | 43,086,093 | ||||||||||
| Stock-based compensation | $ | 1,473,800 | 1,473,800 | |||||||||||||||||
| Net loss | (2,760,920 | ) | (2,760,920 | ) | ||||||||||||||||
| Balances, December 31, 2014 | 12,362,336 | 12,362 | 55,919,905 | (14,133,294 | ) | 41,798,973 | ||||||||||||||
| Stock-based compensation | 349,650 | 350 | 1,124,350 | 1,124,700 | ||||||||||||||||
| Net loss | (65,764,766 | ) | (65,764,766 | ) | ||||||||||||||||
| Balances, December 31, 2015 | 12,711,986 | $ | 12,712 | $ | 57,044,255 | $ | (79,898,060 | ) | $ | (22,841,093 | ) | |||||||||
| F-82 |
BRUSHY RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
| Years Ended December 31, | 2015 | 2014 | ||||||
| Cash flows from operating activities | ||||||||
| Net loss | $ | (65,764,766 | ) | $ | (2,760,920 | ) | ||
| Adjustments to reconcile net loss to net cash provided by operating activities: | ||||||||
| Depreciation and depletion | 22,510,290 | 10,140,152 | ||||||
| Impairment of oil and gas properties | 55,753,481 | 4,428,378 | ||||||
| Deferred income taxes | (14,039,742 | ) | (1,506,168 | ) | ||||
| Stock-based compensation | 1,124,700 | 1,473,800 | ||||||
| Accretion of asset retirement obligation | 187,183 | 319,703 | ||||||
| Change in fair value of derivative contracts | 1,032,955 | (1,880,107 | ) | |||||
| Accretion of debt issuance costs | 438,535 | 192,739 | ||||||
| Write off deferred offering costs | 537,927 | - | ||||||
| Gain on asset sale | (2,375,333 | ) | (2,115,916 | ) | ||||
| Increase (decrease) in cash attributable to changes in operating assets and liabilities: | ||||||||
| Trade receivable | 759,132 | (82,079 | ) | |||||
| Joint interest receivable | 336,500 | (447,627 | ) | |||||
| Prepaid expenses and other assets | 100,776 | 71,808 | ||||||
| Accounts payable and accrued liabilities | 37,345 | (1,134,686 | ) | |||||
| Joint interest revenues payable | 188,899 | (138,856 | ) | |||||
| Net cash provided by operating activities | 827,882 | 6,560,221 | ||||||
| Cash flows from investing activities | ||||||||
| Development of oil and natural gas properties | (5,101,544 | ) | (16,492,626 | ) | ||||
| Acquisition of oil and natural gas properties | - | (16,803,448 | ) | |||||
| Proceeds from sale of oil and natural gas properties | 7,083,778 | 1,891,743 | ||||||
| Acquisition of other property and equipment | - | (9,495 | ) | |||||
| Oil and natural gas abandonment costs | - | (27,345 | ) | |||||
| Net cash provided by / (used in) investing activities | 1,982,234 | (31,441,171 | ) | |||||
| Cash flows from financing activities | ||||||||
| Proceeds from notes payable | 9,750,000 | 24,060,170 | ||||||
| Debt issuance costs | (229,937 | ) | (210,612 | ) | ||||
| Deferred offering costs | (7,310 | ) | (86,231 | ) | ||||
| Repayments of notes payable | (13,058,030 | ) | (1,102,367 | ) | ||||
| Net cash (used in) / provided by financing activities | (3,545,277 | ) | 22,660,960 | |||||
| Net (decrease) in cash | (735,161 | ) | (2,219,990 | ) | ||||
| Cash, beginning of year | 3,574,427 | 5,794,417 | ||||||
| Cash, end of year | $ | 2,839,266 | $ | 3,574,427 | ||||
| F-83 |
BRUSHY RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
| Years Ended December 31, | 2015 | 2014 | ||||||
| Supplemental disclosure of cash flow information | ||||||||
| Cash paid during the period for taxes | $ | 12,766 | $ | 3,835 | ||||
| Cash paid during the period for interest | $ | 829,153 | $ | 2,231,137 | ||||
| Supplemental disclosure of non-cash investing transactions | ||||||||
| Payables related to oil and natural gas capitalized expenditures | $ | 3,131,917 | $ | 1,537,638 | ||||
| Capitalized asset retirement cost | $ | (41,574 | ) | $ | 849,181 | |||
| Payable settled through asset sales | $ | - | $ | 3,872,674 | ||||
| F-84 |
BRUSHY RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - NATURE OF OPERATIONS
Brushy was originally formed as Starboard Resources LLC in Delaware on June 2, 2011 as a limited liability company to acquire, own, operate, produce, and develop oil and natural gas properties primarily in Texas and Oklahoma. On June 28, 2012, Starboard converted from a Delaware limited liability company to a Delaware C-Corporation and was named Starboard Resources, Inc. The membership units of Starboard Resources LLC were exchanged on a 1:1 basis for common shares of the Company. On July 31, 2015 Brushy sold substantially all of its Oklahoma producing properties and is primarily now focused on its Texas and New Mexico properties. On August 25, 2015 Starboard changed its name to Brushy Resources, Inc. (the “Company”).
NOTE 2 - GOING CONCERN
Our independent registered public accounting firm for the year ended December 31, 2015 issued their report dated April 20, 2016, that included an explanatory paragraph describing the existence of conditions that raise substantial doubt about our ability to continue as a going concern due to our significant accumulated deficit, working capital deficit, significant net losses and need to raise additional funds to meet our obligations and sustain our operations.
Given the precipitous decline in oil and natural gas prices during 2015 and into 2016, we expect to continue to face liquidity constraints. Our cash flows are negatively impacted by lower realized oil and natural gas sales prices and the significant decline in oil and natural gas prices also increases the uncertainty as to the impact of commodity prices on our estimated proved reserves. As a result, we have been in default under the 2013 Credit Agreement between us and Independent Bank, acting for itself and as administrative agent for the other lenders (as amended, the “IB Credit Agreement”) since November 2015. As a result of these defaults, we are no longer permitted to make further draws on the IB Credit Agreement and have been subject to a forbearance agreement with the lenders (the “IB Forbearance Agreement”) pursuant to which the lenders agreed to forbear exercising any of its remedies for the existing covenant defaults for a period of time (the “Forbearance Period”) to permit us to seek refinancing of the indebtedness owed under the IB Credit Agreement in the approximate amount of $11,000,000, which is referred to as the IB Indebtedness or a sale of sufficient assets to repay the IB Indebtedness. During the Forbearance Period we are not permitted to drill new oil or gas wells or make distributions to equity holders. Furthermore, this also cross defaulted the SOSventures Credit Agreement, however, the Forbearance Period began with the execution of the IB Forbearance Agreement on November 24, 2015 and ended on January 31, 2016, but was subsequently extended to March 31, 2016. We are currently in discussions with the lender under the IB Credit Agreement regarding a further extension of the Forbearance Period. If we do not obtain a further extension of the Forbearance Period, the lenders under the IB Credit Agreement will be able to accelerate the repayment of debt under the IB Credit Agreement. For more information see Note 9 - Notes Payable.
| F-85 |
Proposed Merger with Lilis
On December 29, 2015, we agreed to combine our business with Lilis pursuant to the Agreement and Plan of Merger (the “merger agreement”). Pursuant to the merger agreement, Lilis Merger Sub, Inc. (“Merger Sub”) will merge with and into Brushy, with Brushy surviving the merger as a wholly-owned subsidiary of Lilis (the “merger”). Upon completion of the merger, each share of our common stock issued and outstanding immediately prior to the effective time will be converted into the right to receive an amount of shares of Lilis’s common stock such that our former shareholders will represent approximately 50% of the then-outstanding shares of Lilis’s common stock after the closing of the merger (without taking into account outstanding restricted stock units or options or warrants to purchase shares of Lilis’s common stock). In connection with the merger, we are obligated to convey Giddings Field and the Bigfoot Area, to SOSventures, LLC ("SOSventures"), in exchange for a release of our obligations under its subordinated credit agreement with SOSventures, dated March 29, 2013, as amended. We expect the closing of the merger to occur in the first half of 2016. However, the merger is subject to the satisfaction or waiver of other conditions, and it is possible that factors outside our control could result in the merger being completed at an earlier time, a later time or not at all. If the merger has not been completed on or before May 31, 2016, either Lilis or Brushy may terminate the merger agreement unless the failure to complete the merger by that date is due to the failure of the party seeking to terminate the merger agreement to fulfill any material obligations under the merger agreement or a material breach of the merger agreement by such party.
Collectively, these matters raise substantial doubt about the Company’s ability to continue as a going concern. The Company’s Board of Directors and management team continue to take steps to try to strengthen the Company’s balance sheet. We intend to execute the merger (which is subject to usual and customary closing conditions beyond our control) and, in the event the merger is not consummated, we intend to refinance our existing debt, sell non-core properties and seek private financings to fund our cash needs. Any decision regarding the merger or financing transaction, and our ability to complete such a transaction, will depend on prevailing market conditions and other factors. No assurances can be given that such transactions can be consummated on terms that are acceptable to the Company, or at all. If we are unable to restructure our current obligations under our existing outstanding debt and preferred stock instruments, and address near-term liquidity needs, we may need to seek relief under the U.S. Bankruptcy Code. This relief may include: (i) seeking bankruptcy court approval for the sale or sales of some, most or substantially all of the Company’s assets pursuant to section 363(b) of the U.S. Bankruptcy Code and a subsequent liquidation of the remaining assets in the bankruptcy case; (ii) pursuing a plan of reorganization (where votes for the plan may be solicited from certain classes of creditors prior to a bankruptcy filing) that the Company would seek to confirm (or “cram down”) despite any classes of creditors who reject or are deemed to have rejected such plan; or (iii) seeking another form of bankruptcy relief, all of which involve uncertainties, potential delays and litigation risks.
NOTE 3 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
The consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”).
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of Brushy and its wholly owned subsidiaries, ImPetro Resources, LLC (“ImPetro”) and ImPetro Operating (“Operating”) (Collectively the “Company”). All intercompany transactions and balances have been eliminated in consolidation.
| F-86 |
Oil and Gas Natural Gas Properties
The Company uses the successful efforts method of accounting for oil and natural gas producing activities, as further defined under ASC 932, Extractive Activities - Oil and Natural Gas. Under these provisions, costs to acquire mineral interests in oil and natural gas properties, to drill exploratory wells that find proved reserves, and to drill and equip development wells are capitalized.
Exploratory drilling costs are capitalized when incurred pending the determination of whether a well has found proved reserves. A determination of whether a well has found proved reserves is made shortly after drilling is completed. The determination is based on a process that relies on interpretations of available geologic, geophysic and engineering data. If a well is determined to be successful, the capitalized drilling costs will be reclassified as part of the cost of the well. Capitalized costs of producing oil and natural gas interests are depleted on a unit-of-production basis at the field level.
If an exploratory well is determined to be unsuccessful, the capitalized drilling costs will be charged to expense in the period the determination is made. If a determination cannot be made as to whether the reserves that have been found can be classified as proved, the cost of drilling the exploratory well is not carried as an asset for more than one year following completion of drilling. If, after that year has passed, a determination that proved reserves exist cannot be made, the well is assumed to be impaired and its costs are charged to expense. Its cost can, however, continue to be capitalized if a sufficient quantity of reserves is discovered in the well to justify its completion as a producing well and the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project.
The carrying value of oil and gas properties is assessed for possible impairment on a field by field basis and on at least an annual basis, or as circumstances warrant, based on geological analysis or changes in proved reserve estimates. When impairment occurs, an adjustment is recorded as a reduction of the asset carrying value. For the years ended December 31, 2015 and 2014, the Company's impairment charge was approximately $55,753,481 and $4,428,378, respectively.
Other Property and Equipment
Other property and equipment, which includes field equipment, vehicles, and office equipment, is stated at cost less accumulated depreciation and amortization. Depreciation and amortization is computed using the straight-line method over the estimated useful lives of the assets. Vehicles and office equipment are generally depreciated over a useful life of five years and field equipment is generally depreciated over a useful life of twenty years.
| F-87 |
Goodwill
Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. Goodwill is not amortized; rather, it is tested for impairment annually and when events or changes in circumstances indicate that fair value of a reporting unit with goodwill has been reduced below carrying value. The impairment test requires allocating goodwill and other assets and liabilities to reporting units. However, the Company only has one reporting unit. To assess impairment, the Company has the option to qualitatively assess if it is more likely than not that the fair value of the reporting unit is less than the book value. Absent a qualitative assessment, or, through the qualitative assessment, if the Company determines it is more likely than not that the fair value of the reporting unit is less than the book value, a quantitative assessment is prepared to calculate the fair market value of the reporting unit. If it is determined that the fair value of the reporting unit is less than the book value, the recorded goodwill is impaired to its implied fair value with a charge to operating expenses. As of December 31, 2015 and 2014 and the years then ended there was no impairment of goodwill. Goodwill of $959,681 was from the acquisition of ImPetro Resources LLC on June 13, 2011.
Deferred Offering Costs
The Company complies with the requirements of the Securities and Exchange Commission (“SEC”) Staff Accounting Bulletin (SAB) Topic 5A “Expenses of Offering”. Deferred offering costs consist principally of accounting, legal and other fees incurred through the consolidated balance sheet dates that are related to a proposed initial public offering and that will be charged to stockholders’ equity upon the receipt of the offering proceeds or charged to expense if the offering is not completed. For the years ended December 31, 2015 and 2014, the Company incurred deferred offering costs of approximately $7,310 and $86,231, respectively, relating to expenses connected with the proposed offering. The deferred offering costs are included in other assets in the consolidated balance sheets. For the years ended December 31, 2015 and 2014, the Company had a write off of approximately $537,927 and $0, respectively.
Asset Retirement Obligations
The Company follows the provisions of ASC 410-20, Asset Retirement Obligations. ASC 410-20 requires entities to record the fair value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depleted as part of the oil and natural gas property. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The Company’s asset retirement obligations relate to the plugging, dismantlement, removal, site reclamation and similar activities of its oil and natural gas properties.
Asset retirement obligations are estimated at the present value of expected future net cash flows and are discounted using the Company’s credit adjusted risk free rate. The Company uses unobservable inputs in the estimation of asset retirement obligations that include, but are not limited to, costs of labor, costs of materials, profits on costs of labor and materials, the effect of inflation on estimated costs, and the discount rate. Accordingly, asset retirement obligations are considered a Level 3 measurement under ASC 820. Additionally, because of the subjectivity of assumptions and the relatively long lives of the Company’s wells, the costs to ultimately retire the Company’s wells may vary significantly from prior estimates.
| F-88 |
Revenue Recognition and Natural Gas Imbalances
The Company utilizes the accrual method of accounting for natural gas and crude oil revenues, whereby revenues are recognized based on the Company’s net revenue interest in the wells upon delivery to third parties. The Company will also enter into physical contract sale agreements through its normal operations.
Gas imbalances are accounted for using the sales method. Under this method, revenues are recognized based on actual volumes of oil and gas sold to purchasers. However, the Company has no history of significant gas imbalances.
Cash
The Company considers all highly-liquid debt instruments with original maturities of three months or less when purchased to be cash equivalents. As of December 31, 2015 and 2014, the Company did not hold any cash equivalents.
The Company maintains its cash balances in financial institutions which are insured by the Federal Deposit Insurance Corporation (“FDIC”). From time to time, the Company will maintain cash balances in a financial institution that may exceed the FDIC coverage of $250,000. The Company has not experienced any losses in such accounts and believes it is not subject to any significant credit risk on cash.
Trade Receivable and Joint Interest Receivable
Trade receivable is comprised of accrued natural gas and crude oil sales and joint interest receivable is comprised of amounts owed to the Company from joint interest owners for their proportionate share of expenses. Generally, operators of natural gas and crude oil properties have the right to offset joint interest receivables with revenue payables. Accordingly, any joint interest owner that has a joint interest receivable and joint interest revenue payable as of December 31, 2015 and 2014 are shown at net in the accompanying consolidated balance sheets.
The Company performs ongoing credit evaluations of its customers’ and extends credit to virtually all of its customers. Credit losses to date have not been significant and have been within management’s expectations. In the event of complete non-performance by the Company’s customers and joint interest owners, the maximum exposure to the Company is the outstanding trade and joint interest receivable balance at the date of nonperformance. For the years ended December 31, 2015 and 2014, the Company had minimal bad debt expense.
Derivative Activities
The Company utilized oil and natural gas derivative contracts to mitigate its exposure to commodity price risk associated with its future oil and natural gas production. These derivative contracts have historically consisted of options, in the form of price floors or collars. The Company’s derivative financial instruments are recorded on the consolidated balance sheets as either an asset or a liability measured at fair value. The Company does not apply hedge accounting to its oil and natural gas derivative contracts and accordingly the changes in the fair value of these instruments are recognized in the statement of operations in the period of change.
| F-89 |
The Company’s derivative instruments are issued to manage the price risk attributable to our expected natural gas and oil production. While there is risk that the financial benefit of rising natural gas and oil prices may not be captured, Company management believes the benefits of stable and predictable cash flow are more important. Every unsettled derivative instrument is recorded on the accompanying consolidated balance sheets as either an asset or a liability measured at its fair value. Changes in a derivative’s fair value are recognized in earnings unless specific hedge accounting criteria are met. Cash flows from natural gas and oil derivative contract settlements are reflected in operating activities in the accompanying consolidated statements of cash flows.
Realized and unrealized gains and losses on derivatives are accounted for using the mark-to-market accounting method. The Company recognizes all unrealized and realized gains and losses related to these contracts in each period in gain (loss) from derivative contracts in the accompanying consolidated statements of operations.
Lease Operating Expenses
Lease operating expenses represent, pumpers’ salaries, saltwater disposal, ad valorem taxes, repairs and maintenance, expensed workovers and other operating expenses. Lease operating expenses are expensed as incurred.
Sales-Based Taxes
The Company incurs severance tax on the sale of its production which is generated in Texas, New Mexico and Oklahoma. These taxes are reported on a gross basis and are included in production taxes within the accompanying consolidated statements of operations.
Stock-Based Compensation and Equity Incentive Plans
The Company accounts for stock-based compensation in accordance with ASC 718, Compensation - Stock Compensation. The standard requires the measurement and recognition of compensation expense in the Company’s consolidated statements of operations for all share-based payment awards made to the Company’s employees, directors and consultants including employee stock options, non-vested equity stock and equity stock units, and employee stock purchase grants. Stock-based compensation expense is measured at the grant date, based on the estimated fair value of the award, reduced by an estimate of the annualized rate of expected forfeitures, and is recognized as an expense over the employees’ expected requisite service period, generally using the straight-line method. In addition, ASC 718 requires the benefits of tax deductions in excess of recognized compensation expense to be reported as a financing cash flow, rather than as an operating cash flow as prescribed under previous accounting rules.
The Company’s forfeiture rate represents the historical rate at which the Company’s stock-based awards were surrendered prior to vesting. ASC 718 requires forfeitures to be estimated at the time of grant and revised on a cumulative basis, if necessary, in subsequent periods if actual forfeitures differ from those estimates.
During the years ended December 31, 2015 and 2014, the Company incurred a stock based compensation expense of approximately $1,125,000 and $1,474,000, respectively, and is included in the accompanying consolidated statements of operations in general and administrative expenses.
| F-90 |
Income Taxes
Deferred income tax assets and liabilities are computed for differences between the financial statement and tax basis of assets and liabilities that will result in future taxable or deductible amounts, based on enacted tax laws and rates applicable to the periods in which the differences are expected to affect taxable income. Valuation allowances are established, when necessary, to reduce deferred income tax assets to the amount expected to be realized.
The Company is required to determine whether its tax positions are more likely than not to be sustained upon examination by the applicable taxing authority, including resolution of any related appeals or litigation processes, based on the technical merits of the position. The tax benefit recognized is measured as the largest amount of benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement with the relevant taxing authority. De-recognition of a tax benefit previously recognized results in the Company recording a tax liability that increases expense in that period. Based on its analysis, the Company has determined that it has not incurred any liability for unrecognized tax benefits as of December 31, 2015. The Company’s conclusions may be subject to review and adjustment at a later date based on factors including, but not limited to, on-going analyses of and changes to tax laws, regulations and interpretations thereof.
The Company recognizes interest and penalties related to unrecognized tax benefits in interest expense and other expenses, respectively. No interest expense or penalties have been recognized as of December 31, 2015.
Long-Lived Assets
The Company accounts for long-lived assets (other than oil and gas properties) at cost. Other long-lived assets consist principally of property and equipment and identifiable intangible assets with finite useful lives (subject to amortization, depletion, and depreciation). The Company may impair these assets whenever events or changes in circumstances indicate that the carrying amount of such assets may not be fully recoverable. Recoverability is measured by comparing the carrying amount of an asset to the expected undiscounted future net cash flows generated by the asset. If it is determined that the asset may not be recoverable, and if the carrying amount of an asset exceeds its estimated fair value, an impairment charge is recognized to the extent of the difference.
Net Loss Per Common Share
Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to stockholders by the weighted average number of common shares outstanding during the period. Diluted net income (loss) per common share is calculated in the same manner, but also considers the impact to common shares for the potential dilution from stock options, non-vested share appreciation rights and non-vested restricted shares. For the year ended December 31, 2015, there were 900,000 potentially dilutive non-vested and vested stock options and 2,542,397 stock warrants. For the year ended December 31, 2014, there were 1,249,650 potentially dilutive non-vested restricted shares and stock options. The potentially dilutive shares, for the December 31, 2015 and 2014, are considered antidilutive since the Company is in a net loss position and thus result in the basic net loss per common share equaling the diluted net loss per common share.
| F-91 |
Use of Estimates
The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
The Company’s estimates of oil and natural gas reserves are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable natural gas and oil reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future natural gas and oil prices, future operating costs, severance taxes, development costs and workover costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to the extent that these reserves are later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of expected natural gas and oil attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity of the reserves, which could affect the carrying value of the Company’s oil and natural gas properties and/or the rate of depletion related to the oil and natural gas properties.
The most significant financial estimates are associated with the Company’s estimated volumes of proved oil and natural gas reserves, asset retirement obligations, assessments of impairment imbedded in the carrying value of undeveloped acreages undeveloped properties and developed properties, fair value of financial instruments, including derivative liabilities, depreciation and accretion, income taxes and contingencies.
New Accounting Pronouncement
In May 2014, the FASB issued ASU No. 2014-09 (“ASU 2014-09”), “Revenue from Contracts with Customers,” which requires an entity to recognize revenue representing the transfer of promised goods or services to customers in an amount that reflects the consideration which the company expects to receive in exchange for those goods or services. ASU 2014-09 is intended to establish principles for reporting useful information to users of financial statements about the nature, amount, timing and uncertainty of revenues and cash flows arising from the entity’s contracts with customers. ASU 2014-09 will replace most existing revenue recognition guidance in GAAP when it becomes effective. The new standard is effective for us on January 1, 2018. Early application is only permitted as of January 1, 2017. The Company is currently evaluating the effect that ASU 2014-09 will have on its financial statements and related disclosures.
In June 2014, the FASB issued ASU No. 2014-12 (“ASU 2014-12”), “Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period,” which requires a performance target that affects vesting, and that could be achieved after the requisite service period, be treated as a performance condition. ASU 2014-12 states that the performance target should not be reflected in estimating the grant date fair value of the award. ASU 2014-12 clarifies that compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent the periods for which the requisite service has already been rendered. The new standard is effective for us on January 1, 2016. The Company does not expect adoption of ASU 2014-12 to have a significant impact on its financial statements.
| F-92 |
In August 2014, the FASB issued ASU No. 2014–15 (“ASU 2014-15”), “Presentation of Financial Statements – Going Concern.” ASU 2014-15 provides GAAP guidance on management’s responsibility in evaluating whether there is substantial doubt about a company’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, management will be required to evaluate whether there are conditions or events that raise substantial doubt about a company’s ability to continue as a going concern within one year from the date the financial statements are issued. The new standard is effective for us on January 1, 2017. The Company does not expect the adoption of ASU 2014–15 to have a significant impact on its financial statements.
In November 2014, the FASB issued ASU No. 2014-16 (“ASU 2014-16”), “Derivative and Hedging (Topic 815).” ASU 2014-16 addresses whether the host contract in a hybrid financial instrument issued in the form of share should be accounted for as debt or equity. ASU 2014-16 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. The Company does not expect the adoption of ASU 2014–16 to have a significant impact on its financial statements.
In April 2015, the FASB issued ASU No. 2015-03 (“ASU 2015-03”), “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs.” ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, consistent with debt discounts, instead of being presented as an asset. ASU 2015-03 is effective for us on January 1, 2016. Once adopted, entities are required to apply the new guidance retrospectively to all prior periods presented. The retrospective application represents a change in accounting principle. Early adoption is permitted for financial statements that have not been previously issued. The Company is currently evaluating the effect that ASU 2015-03 will have on its financial statements and related disclosures.
In May 2015, the FASB issued ASU No. 2015-07 (“2015-07”), “Fair Value Measurement.” ASU 2015-07 removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. The amendments also remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient. ASU 2015-07 is effective for us on January 1, 2016. Early adoption is permitted. The Company does not expect the adoption of ASU 2015–07 to have a significant impact on its financial statements.
In September 2015, the FASB issued ASU No. 2015-16 (“ASU 2015-16”), “Business Combinations (Topic 805), Simplifying the Accounting for Measurement-Period Adjustments”. The update requires that the acquirer in a business combination recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined (not retrospectively as with prior guidance). Additionally, the acquirer must record in the same period’s financial statements the effect on earnings of changes in depreciation, amortization or other income effects as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the time of acquisition. The acquiring entity is required to disclose, on the face of the financial statements or in the footnotes to the financial statements, the portion of the amount recorded in current period earnings, by financial statement line item, that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. ASU 2015-16 is effective for us on January 1, 2016. The adoption of this standard is not expected to have a material impact on the Company’s financial statements.
In November 2015, the FASB has issued an update to ASU No. 2015-17 (“ASU 2015-17”) “Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes.” The update requires a company to classify all deferred tax assets and liabilities as noncurrent. The update of ASU 2015-17 is effective for us on January 1, 2018. The Company does not expect the adoption of the update of ASU 2015–17 to have a significant impact on its financial statements.
| F-93 |
In January 2016, the FASB issued ASU No. 2016-01 (“ASU 2016-01”), “Financial Instruments – Overall (Subtopic 825-10)”. ASU 2016-01 updates certain aspects of recognition, measurement, presentation and disclosure of financial instruments. The new guidance is effective for us on January 1, 2018. The Company does not expect the adoption of ASU 2016–01 to have a significant impact on its financial statements.
In February 2016, the FASB issued ASU No. 2016-02 (“ASU 2016-02), “Leases (Topic 842).” ASU 2016-02 requires a lessee to recognize a lease liability for the obligation to make lease payments and a right-to-use asset for the right to use the underlying asset for the lease term. ASU 2016-02 is effective for us on January 1, 2019. Early adoption is permitted. The Company is currently evaluating the effect that ASU 2016-02 will have on its financial statements and related disclosures.
In March 2016, the FASB issued ASU No. 2016-06 (“ASU 2016-06”), “Contingent Put and Call Option in Debt Instruments”. ASU 2016-06 is intended to simplify the analysis of embedded derivatives for debt instruments that contain contingent put or call options. The amendments in ASU 2016-06 clarify that an entity is required to assess the embedded call or put options solely in accordance with the four-step decision sequence. Consequently, when a call (put) option is contingently exercisable, an entity does not have to initially assess whether the event that triggers the ability to exercise a call (put) option is related to interest rates or credit risks. The amendments in ASU 2016-06 take effect for public business entities for financial statements issued for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The Company does not expect the adoption of ASU 2016–01 to have a significant impact on its financial statements.
NOTE 4 - FAIR VALUE MEASUREMENTS
As defined by ASC 820, the fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced or liquidation sale, which was further clarified as the price that would be received to sell an asset or paid to transfer a liability (“an exit price”) in an orderly transaction between market participants at the measurement date. The carrying amounts of the Company’s financial assets and liabilities, such as cash, trade receivable, joint interest receivable, joint interest revenues payable, accounts payable and accrued liabilities and related party payable, approximate their fair values because of the short maturity of these instruments. The carrying amount of the notes payable in long-term debt also approximates fair value due to its variable-rate characteristics.
The following tables present information about the Company’s financial assets and liabilities measured at fair value as of December 31, 2015 and December 31, 2014:
| ($ in thousands) | Level 1 | Level 2 | Level 3 | Balance as of December 31, 2015 | ||||||||||||
| Assets (at fair value): | ||||||||||||||||
| Derivative assets (oil collar and put options) | $ | - | $ | 733 | $ | - | $ | 733 | ||||||||
| Liabilities (at fair value): | ||||||||||||||||
| Asset Retirement Obligations | $ | - | $ | - | $ | 3,597 | $ | 3,597 | ||||||||
| F-94 |
| ($ in thousands) | Level 1 | Level 2 | Level 3 | Balance as of December 31, 2014 | ||||||||||||
| Assets (at fair value): | ||||||||||||||||
| Derivative assets (oil collar and put options) | $ | - | $ | 1,766 | $ | - | $ | 1,766 | ||||||||
| Liabilities (at fair value): | ||||||||||||||||
| Asset Retirement Obligations | $ | - | $ | - | $ | 3,606 | $ | 3,606 | ||||||||
The Company's derivative contracts consist of NYMEX-based fixed price commodity swaps and NYMEX collars. The NYMEX-based fixed price derivative contracts are indexed to NYMEX futures contracts, which are actively traded, for the underlying commodity and are commonly used in the energy industry. A number of financial institutions and large energy companies act as counter-parties to these type of derivative contracts. As the fair value of these derivative contracts is based on a number of inputs, including contractual volumes and prices stated in each derivative contract, current and future NYMEX commodity prices, and quantitative models that are based upon readily observable market parameters that are actively quoted and can be validated through external sources, we have characterized these derivative contracts as Level 2.
The asset retirement liability is measured using primarily Level 3 inputs./ The significant unobservable inputs to this fair value measurement include estimates of plugging costs, remediation costs, inflation rate and well life. The inputs are calculated based on historical data as well as current estimated costs. See Note 7 - Asset Retirement Obligations.
The Company estimates the expected undiscounted future cash flows of its oil and natural gas properties and compares such amounts to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates or proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. These assumptions represent Level 3 inputs. Impairment of oil and gas assets for the year ended December 31, 2015 and 2014 was $55,753 thousand and $4,428 thousand, respectively.
NOTE 5 - PROPERTY ACQUISITION AND DIVESTITURE
On March 26, 2014 (the “Acquisition Date”), the Company completed the purchase of oil and natural gas leases and leasehold interests (the “Oil and Natural Gas Properties”) from White Oak Resources VI, LLC and Permian Atlantis LLC (collectively the “Seller”) for the purpose of increasing the Company’s oil and natural gas operations in the Permian Basin. The assets acquired are: (a) oil and natural gas leases and leasehold interests in Winkler and Loving Counties in Texas and Lea County, New Mexico; (b) twenty-nine wellbores; and (c) any contracts or agreements related to the foregoing lands, leases and wells. The Oil and Natural Gas Properties include total acreage held by production of 5,160 gross developed acres (1,983.61 net developed acres). Additionally, producing wells and surrounding acreage have been unitized under Texas Railroad Commission regulations. Under the terms of the agreement, the Company purchased the Oil and Natural Gas Properties for $16,803,000 in cash, including before purchase price adjustments. For the year ended December 31, 2014, the Company recognized $1,932 thousand of oil, natural gas and products sales and $725 thousand of net operating income related to properties acquired from White Oak Resources VI, LLC and Permian Atlantis LLC and transaction cost of $45 thousand in profession fees.
| F-95 |
Unaudited Pro Forma Condensed Combined Financial Statements
The following unaudited pro forma financial statements give effect to the acquisition of the Oil and Natural Gas Properties. The unaudited pro forma statement of operations for the year ended December 31, 2014, reflects the acquisition of the Oil and Natural Gas Properties as if it had occurred on January 1, 2014.
It is not intended to be indicative of the Company's results of operations or financial position that might have been achieved had the acquisition been completed as of the dates presented, or the Company's future results of operations or financial position.
| in thousands, except share data | Year Ended December 31, 2014 | |||
| Oil, natural gas, and related product sales | $ | 20,855 | ||
| Net loss | $ | 2,442 | ||
| Net loss per basic and diluted common share | $ | 0.20 | ||
| Weighted average basic and diluted common shares outstanding | 12,362,336 | |||
Financial Statement Presentation and Purchase Price Allocation
The following table summarizes the purchase price and values of assets acquired and liabilities assumed:
| Fair value of assets acquired and liabilities assumed (in thousands) | ||||
| Proved oil and natural gas properties (1) | $ | 17,662 | ||
| Revenue payable | (27 | ) | ||
| Asset retirement obligations | (832 | ) | ||
| Total fair value of assets acquired and liabilities assumed, net | $ | 16,803 | ||
| Cash consideration transferred | $ | 16,803 |
(1) Amount includes asset retirement costs of approximately $832.
On July 31, 2015, the Company sold all of its Oklahoma properties, which were located in Logan and Kingfisher Counties, Oklahoma, to Remora Petroleum, LP (Austin, TX) for $7,249,390. The purchaser is not affiliated with any Company officers, directors or material stockholders.
The following table summarized the results of operation from the properties sold:
| ($ in thousands) | Year Ended December 31, 2015 | Year Ended December 31, 2014 | ||||||
| Oil, natural gas, and related product sales | $ | 1,368 | $ | 6,720 | ||||
| Expenses | 269 | 782 | ||||||
| Operating income | $ | 1,099 | $ | 5,938 | ||||
| F-96 |
As part of this transaction, the Company entered into the Fifth Amendment to its Credit Agreement with Independent Bank (“Amendment”). The Amendment provides that $4,000,000 of the purchase price was paid to Independent Bank to pay down its credit facility with Independent Bank.
NOTE 6 - OIL AND NATURAL GAS PROPERTIES
The following table presents a summary of the Company’s oil and natural gas properties at December 31, 2015 and December 31, 2014:
| ($ in thousands) | December 31, 2015 | December 31, 2014 | ||||||
| Oil and natural gas properties | ||||||||
| Proved-developed producing properties | $ | 43,912 | $ | 96,691 | ||||
| Proved-developed non-producing properties | 5,865 | 2,880 | ||||||
| Proved-undeveloped properties | - | 13,330 | ||||||
| Unproved properties | 2,389 | 1,996 | ||||||
| Less: Accumulated depletion | (35,282 | ) | (23,131 | ) | ||||
| Total oil and natural gas properties, net of accumulated depletion and impairment | $ | 16,884 | $ | 91,766 | ||||
As of December 31, 2015 and December 31, 2014, the accumulated impairment was $55,985 thousand and $3,955 thousand, respectively.
NOTE 7 - ASSET RETIREMENT OBLIGATIONS
The Company has recognized the fair value of its asset retirement obligations related to the future costs of plugging, abandonment, and remediation of oil and natural gas producing properties. The present value of the estimated asset retirement obligations has been capitalized as part of the carrying amount of the related oil and natural gas properties. The liability has been accreted to its present value as of the end of each period. At December 31, 2015 and December 31, 2014, the Company evaluated 147 and 169 wells, respectively, and has determined a range of abandonment dates between January 2016 and October 2044. The following table represents a reconciliation of the asset retirement obligations for the year ended December 31, 2015 and December 31, 2014:
Year Ended December 31, 2015 | Year Ended December 31, 2014 | |||||||
| ($ in thousands) | ||||||||
| Asset retirement obligations, beginning of period | $ | 3,606 | $ | 2,437 | ||||
| Additions to asset retirement obligation | 0 | 859 | ||||||
| Liabilities settled during the period | (155 | ) | 0 | |||||
| Accretion of discount | 187 | 320 | ||||||
| Revision of estimate | (41 | ) | (10 | ) | ||||
| Asset retirement obligations, end of period | $ | 3,597 | $ | 3,606 | ||||
As of December 31, 2015 and 2014, the current asset retirement obligation was approximately $392 thousand and $428 thousand respectively, and the long term asset retirement obligation was approximately $3,204 thousand and $3,177 thousand respectively.
See Note 4 - Fair Value Measurements.
| F-97 |
NOTE 8 – DERIVATIVES
We use derivatives to hedge our oil production. Our current hedge position consists put options, of some which have deferred premiums paid at settlement. These contracts and any future hedging arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. In addition, these arrangements may limit the benefit to us of increases in the price of oil. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instrument, which we utilize entirely to hedge our production and do not enter into for speculative purposes. We have not designated the derivative contracts as hedges for accounting purposes, and accordingly, we record the derivative contracts at fair value and recognize changes in fair value in earnings as they occur.
At January 1, 2016, we had the following open crude oil derivative contracts:
| January 1, 2016 | ||||||||||||||||||||
| Instrument | Commodity | Volume (bbl / month) | Floor Price | Ceilings Price | Purchased Put Option Price | |||||||||||||||
| January 2016 – March 2016 | Put | Crude Oil | 1,500 | 75.00 | ||||||||||||||||
| January 2016 – December 2016 | Put | Crude Oil | 3,000 | 50.00 | ||||||||||||||||
| January 2016 – December 2016 | Collar | Crude Oil | 3,000 | 54.00 | 79.30 | |||||||||||||||
The following tables identify the fair value amounts of derivative instruments included in the accompanying consolidated balance sheets as derivative contracts, categorized by primary underlying risk. Balances are presented on a gross basis, prior to the application of the impact of counterparty and collateral netting. The following tables also identify the net gain (loss) amounts included in the accompanying consolidated statements of operations as gain (loss) from derivative contracts.
Fair Value of Derivative Financial Instruments
| ($ in thousands) | December 31, 2015 | December 31, 2014 | ||||||
| Derivative financial instruments - Current asset | $ | 733 | $ | 1,699 | ||||
| Derivative financial instruments - Long-term assets | - | 67 | ||||||
| Net derivative financial instruments | $ | 733 | $ | 1,766 | ||||
Effect of Derivative Financial Instruments
| ($ in thousands) | December 31, 2015 | December 31, 2014 | ||||||
| Realized gain/(loss) on settlement of derivative contracts | $ | 2,303 | $ | 186 | ||||
| Change in fair value of derivative contracts | (1,033 | ) | 1,880 | |||||
| Realized/Unrealized gain/(loss) from derivative contracts | $ | 1,270 | 2,066 | |||||
| F-98 |
NOTE 9 - NOTES PAYABLE
On June 27, 2013, the Company entered into a credit agreement (“Credit Agreement”) with Independent Bank to borrow up to $100,000,000 at a current rate of 4.00% annum. The Credit Agreement was obtained to fund the development of the Company’s oil and natural gas properties and refinance the prior bank facility. At December 31, 2015 and December 31, 2014, the Company had approximately $12,600,000 and $22,500,000 in borrowings outstanding under the Credit Agreement, respectively.
Loans under the Credit Agreement bear interest at the greater of: (1) the prime rate, the annual rate of interest announced by the Wall Street Journal as its “prime rate”, or (2) the floor rate of 4.00%.
In November 2015 counsel for Independent Bank had notified us of the following defaults under IB Credit Agreement: i) the interest coverage ratio covenant set forth in Section 7.15.1 of the IB Credit Agreement for the fiscal quarter ended June 30, 2015, (ii) the current ratio covenant set forth in Section 7.15.2 of the IB Credit Agreement for the fiscal quarter ended June 30, 2015, (iii) the leverage ratio covenant set forth in Section 7.15.3 of the IB Credit Agreement for the fiscal quarter ended June 30, 2015, and (iv) the Company is not currently maintaining the minimum Commodity Hedging Transactions (as defined in the IB Credit Agreement) required by Section 7.21 of the IB Credit Agreement. The letter further stated that the bank was contemplating its course of action.
On November 24, 2015, we entered into the Forbearance Agreement and the Third Amendment to the Amended and Restated Credit Agreement with Independent Bank under which Independent Bank, acting for itself and as administrative agent for other lenders, agreed to forbear exercising any of its remedies for the existing covenant defaults for period of time to permit us to seek refinancing of the indebtedness owed to Independent Bank in the approximate amount of $11,000,000, which is referred to as the IB Indebtedness or a sale of sufficient assets to repay the IB Indebtedness. The Forbearance Period began with the execution of the IB Forbearance Agreement on November 24, 2015 and ended on January 31, 2016. The Forbearance Period was subsequently extended to March 31, 2016.
In connection with IB Forbearance Agreement, we provided certain additional collateral protections to Independent Bank. The Company granted a first lien mortgage on a newly completed well in New Mexico. We also delivered certain written directives to Independent Bank. In the event of default on the IB Forbearance Agreement or any IB Non-Forbearance Default, Independent Bank is authorized to send the written directives to Cargill, the counterparty to certain hedging contracts with the Company. These written directives instruct Cargill to pay over to Independent Bank “all hedge settlement proceeds, all hedge liquidation proceeds, and all amount otherwise payable by such hedge providers to Brushy.” We also executed and delivered to Independent Bank certain letters in lieu of transfer orders, whereby we instructed first purchasers of oil and gas production to pay directly to Independent Bank all production revenues attributable to our interest in such oil and gas assets. Independent Bank agrees not to send such letters provided that the IB Indebtedness is paid in full on or before the end of the Forbearance Period. At the time of the extension of the Forbearance Period to March 31, 2016, we agreed to unwind the remaining existing hedge contract with Cargill and permit Cargill to pay to Independent Bank all hedge settlement proceeds, all hedge liquidation proceeds, and all amounts otherwise payable by Cargill to us. Such payments satisfied outstanding interest and default interest owing to Independent Bank as well as certain other expenses. In addition, such payments reduced the principal due Independent Bank by $406,720.
During the Forbearance Period, we are not permitted to drill new oil or gas wells or to make any distributions to equity holders. Furthermore, this also cross defaulted the SOSVentures Credit Agreement, however the maturity of the second lien note to SOSventures was extended to August 1, 2016.
| F-99 |
We are currently in discussions with the lenders under the IB Credit Agreement regarding a further extension of the Forbearance Period. We are also in discussions with Lilis and other financings parties regarding possible refinance options for the amount outstanding under the IB Credit Agreement
NOTE 10 - STOCK BASED COMPENSATION AND CONDITIONAL PERFORMANCE AWARDS
On April 1, 2012, the Company entered into employment agreements (the “Employment Agreement”) which provided a restricted stock grant and a conditional performance award to key members of management.
The restricted stock grant of 349,650 shares had a grant date fair value of $10.00 per share as approved by the Company's compensation committee and vests in full upon the earlier of an initial public offering (“IPO”) which includes the sale of shares to the public, a business combination whereas 50% or more of the voting power is transferred to the new owners, or March 1, 2015. Those 349,650 shares were earned by the employee recipients and issued to them during the three month period ending March 31, 2015.
During the twelve months ended December 31, 2015 and 2014, the Company incurred a stock-based compensation expense of approximately $300,000 and $1,199,000, respectively, related to the restricted stock grant, which is included in the accompanying consolidated statements of operations in general and administrative expenses.
Additionally, the Employment Agreement provides for a conditional performance award where if an IPO occurs, the employee will receive: (1) a cash payment of 1% of the difference between the Company market capital and the book value at the time of the IPO, (2) common stock options to purchase 1.0% of the fully-diluted capital stock as of the IPO date and IPO price which will vest over a four year period and contain a cashless exercise, (3) common stock options to purchase 1.0% of the fully-diluted capital stock as of the 2nd anniversary of the IPO date at the closing price of the common stock on the 2nd anniversary date of the IPO and will vest six years after the grant and contain a cashless exercise. As of the twelve months months ended December 31, 2015 and 2014, the conditional performance feature is not probable and as such, no compensation expense related to the conditional performance feature has been recognized.
On August 30, 2014, the Company amended and restated the Employment Agreement which provided for additional stock options.
The equity award of options to purchase 900,000 shares at the exercise price of $4.75 per share and vesting over three years from September 4, 2014 with a one-year cliff (in respect of 300,000 shares) and monthly vesting thereafter of 25,000 shares over the remaining two years. During the twelve months ended December 31, 2015 and 2014, the Company incurred a stock-based compensation expense of approximately $825,000 and $275,000, respectively, related to stock option, which is included in the accompanying consolidated statements of operations in general and administrative expenses. As of December 31 2015, there was approximately $1,375,000 of unrecognized stock-based compensation related to the non-vested stock options to be recognized over 1.67 years.
| F-100 |
The assumptions used in the Black-Scholes Option Pricing Model for the stock options granted were as follows:
| 2014 | ||||
| Risk-free interest rate | 1.87 | % | ||
| Expected volatility of common stock | 92 | % | ||
| Dividend yield | $ | 0.00 | ||
| Expected life of options | 5.72 years | |||
There was no new option granted in 2015. On December 31, 2015, there were 900,000 stock options outstanding and the intrinsic value of the associated options was zero. The weighted average exercise of $4.75/share, weighted average grant date fair value of $2.75/share and the weighted average remaining contractual life of 8.55 years. On December 31, 2015, 425,000 stock options were exercisable.
NOTE 11 - RELATED PARTY TRANSACTIONS
Subordinated Credit Facility with SOSVentures
The Chairman of the Company’s Board of Directors, Bill Liao, works for SOSventures. Further, a group composed of SOSventures, Sean O’Sullivan Revocable Living Trust and Bradford R. Higgins constitute a group owning 4,863,720 or 39.34% of the Company’s common stock shares.
On June 3, 2014 the Company agreed to amend its credit agreement with SOSventures, originally entered into on July 25, 2013, providing for a term loan through February 16, 2016 in an amount up to $20,000,000 at an 18.00% interest rate. The loan under this agreement is secured by a second lien on the Company’s assets.
The SOSventures credit agreement requires the Company to maintain certain financial ratios. First, the Company must maintain an interest coverage ratio of 3:1 at the end of each quarter so that its consolidated net income less the Company’s fees under the credit facility, lender expenses, non-cash charges relating to the hedge agreements, interest, income taxes, depreciation, depletion, amortization, exploration expenditures and costs and other non-cash charges (netted for noncash income) (“EBITDAX”) is greater than 3 times the Company’s interest expense under the credit facility. Second, the Company must maintain a debt to EBITDAX ratio of less than 3.5:1 at the end of each quarter. Third, the Company must maintain a current ratio of at greater than 1:1 at the end of each quarter, meaning that the Company’s consolidated current assets (including the unused amount of the credit facility by excluding non-cash assets under ASC 410 and 815) must be greater than the Company’s consolidated current liabilities (excluding non-cash obligations under ASC 410 and 815 and current maturities under the credit facility.)
The credit agreement prevents the Company from incurring indebtedness to banks or lenders, other than Independent Bank, without the consent of SOSventures. It also prevents the Company from incurring most contingent obligations or liens (other than to Independent Bank). It also restricts the Company’s ability to pay dividends, issue options and warrants and repurchase the Company’s common stock shares. The limitation on options and warrants does not apply to equity compensation plans.
This credit facility is currently in default due to the default under the IB Credit Agreement.
| F-101 |
As of March 16, 2016, with accrued and unpaid interest the Company has $21.6 million drawn against the SOSventures credit facility. In light of the December 19, 2014 notice from Independent Bank relating to the payment of interest to SOSventures, pursuant to the Intercreditors Agreement, the Company is are accruing interest payments to SOSventures since the date of that notice.
NOTE 12 - LEGAL PROCEEDINGS
From time-to-time, the Company may become subject to proceedings, lawsuits and other claims in the ordinary course of business including proceedings related to environmental and other matters. Such matters are subject to many uncertainties, and outcomes are not predictable with assurance.
The Company is subject to various possible contingencies that arise primarily from interpretation of federal and state laws and regulations affecting the oil and natural gas industry. Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Although management believes that it has complied with the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued. In addition, environmental matters are subject to regulation by various federal and state agencies.
Lawsuit Relating to 17.23% of our Common Stock Shares
Approximately 17.23% of the Company common stock was interpleaded into Connecticut Superior Court for the Judicial District of Stamford/Norwalk at Stamford, Cause No. FST-CV12-6015112-S (“Interpleader Action”). These are the residual shares of common stock that belonged to the Partnerships after the distribution of the partnerships shares. Claims related to the Interpleader Action were heard in an American Arbitration Association arbitration in 2015. The claimants were Gregory Imbruce; Giddings Investments LLC; Giddings Genpar LLC, Hunton Oil Genpar LLC, ASYM Capital Ill LLC, Glenrose Holdings LLC; ASYM Energy Investments LLC. “Certain” respondents and counterclaimants were Charles Henry, Ahmed Ammar; John P. Vaile, as Trustee of John P. Vaile Living Trust, John Paul Otieno, SOSventures, Bradford Higgins, William Mahoney, Edward M. Conrads, Robert J. Conrads, and the Partnerships. “PKG Respondents” and cross claimants were William F. Pettinati, Jr., Sigma Gas Barbastella Fund, Sigma Gas Antrozous Fund, Nicholas P. Garofolo (the plaintiffs in the above-referenced stockholder litigation) who made claims against Charles S. Henry, III, Bradford Higgins and SOSventures. The relief respondents were Rubicon Resources LLC, Sean O’Sullivan, King Lee, Michael Rihner, Scott Decker, Andrew Gillick, Briana Gillick, Steve Heinemann, Stanley Goldstein, Sidney Orbach, James P. Ashman, and Patricia R. Ashman. The claims, counterclaims and cross claims relate to the governance, control and termination of the Partnerships, including the distribution by the Partnerships of our shares of common stock to the limited partners in the Partnerships in a liquidating distribution in February 2014 as part of a “monetization” event, and other matters.
On September 10, 2015, the American Arbitration Association issued an arbitration award in the Interpleader Action, which is referred to as the Award. The Award states as follows:
| 1) | All claims asserted by Claimants, including Gregory Imbruce and various business entities controlled by Mr. Imbruce against all Respondents were denied and award was made in favor of the “Certain” respondents, including the Company director, Charles S. Henry, III, as well as SOSventures, Bradford Higgins, John Paul Otieno, Estate of William Mahoney, Ahmed Ammar, John P. Vaile, as Trustee of John P. Vaile Living Trust, Edward M. Conrads, Robert J. Conrads, Giddings Oil & Gas LP, Asym Energy Fund III LP and Hunton Oil Partners LP. |
| F-102 |
| 2) | All claims asserted by Claimants, Gregory Imbruce and various business entities controlled by Mr. Imbruce against Relief Respondents, including Rubicon Resources LLC, Sean O’Sullivan Revocable Living Trust, King Lee, Michael Rihner, Scott Decker, Andrew Gillick, Briana Gillick, Steve Heinemann, Stanly Goldstein, Sidney Orbach, James P. Ashman and Patricia R. Ashman, were denied. |
| 3) | An award was made in favor of the “Certain” respondents, including the Company director, Charles S. Henry, III, as well as SOSventures, Bradford Higgins, John Paul Otieno, Estate of William Mahoney, Ahmad Ammar, John P. Vaile, as Trustee of John P. Vaile Living Trust, Edward M. Conrads, Robert J. Conrads, Giddings Oil & Gas LP, Asym Energy Fund III LP and Hunton Oil Partners LP against Mr. Imbruce and his entities on the following claims: |
| a) | breach of fiduciary duty; |
| b) | breach of implied covenant of good faith and fair dealing; |
| c) | partnership dissolution; |
| d) | unjust enrichment; |
| e) | breach of contract; |
| f) | accounting; |
| g) | violation of Connecticut Unfair Trade Practices Act; |
| h) | civil theft; and |
| i) | piercing the corporate veil. |
| 4) | All claims asserted by William F. Pettinati, Jr. Sigma Gas Barbastella Fund, Sigma Gas Antrozous Fund and Nicholas P. Garofolo against the Company's director, Charles S. Henry III, as well as SOSventures and Bradford Higgins were denied. |
| 5) | A declaratory award was entered declaring that the removal of Hunton Oil Genpar LLC, Giddings Genpar LLC and Asym Capital III LLC and/or Gregory Imbruce as the General Partner(s) of the Partnerships was lawful and in compliance with all legal and contractual requirements, and thus was effective; |
| 6) | A declaratory award that the distribution of our -issued common stock made in February 2014 to limited partners in the Partnerships with remaining shares of common stock ultimately being interpleaded into Court in Connecticut was lawful, met all legal requirements and is effective in that the distribution was the result of a “monetization” event under the Partnership agreements; |
| F-103 |
| 7) | A declaratory award that the Partnerships were effectively dissolved at the time of the distribution of the above-referenced shares of common stock issued by the Company from the Partnerships to the limited partners in the Partnerships; |
| 8) | A denial of any and all fees and expenses claimed by Mr. Imbruce and his entities due to “multiple and repeated violations of the Connecticut Uniform Securities Act;” |
| 9) | A denial of fees and expenses claimed by Mr. Imbruce and his entities for the time periods subsequent to the 2011 rollup that formed us; |
| 10) | An award of damages in favor of the “Certain” respondents, in the amount of $1,602,235, subject to trebling under a Civil Theft finding to $4,806,705, plus attorney and expert fees of $2,998,839 for a total award of $7,805,544, payable by Claimants, including Mr. Imbruce and his business entities; |
| 11) | Injunctive relief ordering an accounting of the sources and uses of all funds and other assets of the Partnerships during the time that Mr. Imbruce and his entities served as general partners of the Partnerships; |
| 12) | Post-judgment interest at 10 percent per year payable by Mr. Imbruce and his business entities; and |
| 13) | Arbitration administrative fees, expenses and compensation of the Arbitrator totaling $122,200 to be paid by Gregory Imbruce et al, and William F. Pettinati, Jr., Sigma Gas Barbastella Fund, Sigma Gas Antrozous Fund and Nicholas P. Garofolo. |
The “Certain” respondents filed in Connecticut Superior Court seeking to confirm the Award. Likewise, Claimants have filed in Connecticut Superior Court to vacate the Award. If the Connecticut Superior Court confirms the Award, we anticipate that the Court will subsequently issue a related order as to ownership of the 2,190,891 common stock of the Company, which may result in modifying the Company ownership structure.
Bexar County Proceedings
On April 17, 2015,the Company was served with a lawsuit filed in Bexar County, Texas by William F. Pettinati, Jr., Nicholas Garofolo, Sigma Gas Barbastella Fund and Sigma Gas Antrozous Fund against Starboard (now Brushy), its directors, its Chief Operating Officer, Edward Shaw, its former Chief Financial Officer, Eric Alfuth, our stockholder, Bradford Higgins, and Sean O’Sullivan, the managing director of our stockholder, SOSventures (the “Bexar County Proceedings”). Mr. Pettinati, Mr. Garofolo and the Sigma Gas Antrozous Fund are stockholders. Mr. Pettinati owns 145,112 shares, Mr. Garofolo owns 226,680 shares of common stock and Sigma Gas Antrozous Fund owns 44,610 shares of common stock. Combined these stockholders account for approximately 3.3% of the Company's outstanding common stock. These parties became stockholders in February 2014.
| F-104 |
The Plaintiffs allege several derivative and direct causes of action. These derivative claims include, breach of fiduciary duty, waste of corporate assets, concerted action and conspiracy, joint enterprise, agency, alter ego, exemplary damages, and unjust enrichment. The direct claims include, breach of fiduciary duty, conversion, shareholder oppression, concerted action and conspiracy, declaratory judgment that the distribution of stock to the plaintiffs was invalid, joint enterprise, agency, alter ego, exemplary damages, concerted action and conspiracy and failure to allow for inspection of books and records. Many of the allegations relate to events that allegedly happened before the Plaintiffs became stockholders, including the distributions from the Partnerships that led to the Plaintiffs becoming stockholders in February 2014. Some similar claims involving these Plaintiffs (including the legality of the Partnerships’ liquidating distribution) were previously heard in the arbitration relating to the Partnerships referenced above. Plaintiffs were parties to that arbitration. For actions after February 2014, Plaintiffs complain that the Company's common stock still lacks a trading venue, that a books and records request was not honored, that we “delayed” a public offering, that SOSventures had allegedly taken steps to “foreclose” on the Company's assets under the SOSventures Credit Agreement and that we filed for an extension to the filing date for the Company's annual report on Form 10-K for the year ending December 31, 2014. On October 6, 2015 Plaintiffs withdrew the claim about not honoring a books and records request.
The matter is styled Sigma Barbastella Fund et al v. Charles S. Henry, III et al. and it is Cause No. 20105-CI-05672 in the 224th District Court in Bexar County, Texas.
The Company's directors and officers are subject to indemnification under the Company's bylaws.
Settlement of Interpleader Action and Bexar County Proceedings
On February 17, 2016, the various parties to the Interpleader Action and the Bexar County Proceedings entered into a global settlement agreement (the “Settlement Agreement”) under which the parties to the proceedings issued mutual releases and the plaintiffs in all proceedings agreed to withdraw their claims. In return, the plaintiffs received a cash settlement, the majority of which was covered by the Company's insurance.
NOTE 13 - STOCKHOLDER’S EQUITY
Preferred Shares
The Company is authorized to issue up to 10,000,000 preferred shares, par value $0.001 per share, with such designations, voting and other rights and preferences as may be determined from time to time by the Company’s board of directors. No preferred shares were issued and outstanding as of December 31, 2015 and 2014.
Common Shares
The Company has a single class of common shares that have the same rights, preferences, limitations, and qualifications. The Company is authorized to issue up to 150,000,000 shares, par value $0.001 per share, in the aggregate and from time to time may increase the number of shares authorized.
| F-105 |
Warrants
Upon entering into the Second Amendment to the First Amended and Restated Credit Agreement with SOSVentures, SOSVentures received warrants to purchase 2,542,397 of the Company’s common shares for $1.00 per share with a two-year term. The intrinsic value associated with the outstanding warrants was zero at December 31, 2015, as the strike price of all warrants exceeded the implied market price for Common Stock. The remaining contract life was 1.29 years. The implied value of the warrants were based on our peer group, which included Company’s owning assets in the same areas and of similar size. This valuation determined that the value of the warrants were zero. As such, the Company has placed no value on the warrants issued.
NOTE 14 - INCOME TAXES
For the years ended December 31, 2015 and 2014, the Company estimated that its current and deferred tax provision was as follows:
| 2015 | 2014 | |||||||
| Current taxes: | ||||||||
| Federal | $ | - | $ | - | ||||
| State | 17,157 | (15,465 | ) | |||||
| Total current tax benefit / (expense) | 17,157 | (15,465 | ) | |||||
| Deferred taxes: | ||||||||
| Federal | 27,984,379 | 1,449,296 | ||||||
| State | 133,932 | 53,375 | ||||||
| Total deferred tax benefit | 28,118,311 | 1,502,671 | ||||||
| Change in valuation allowance | (14,078,569 | ) | - | |||||
| Total deferred income tax expense | 14,039,742 | 1,502,671 | ||||||
| Total current and deferred tax expenses | $ | 14,056,899 | $ | 1,487,206 | ||||
A reconciliation of income tax expense (benefit) computed by applying the U.S. federal statutory income tax rate and the reported effective tax rate on income for the years ended December 31, 2015 and 2014 are as follows:
| 2015 | 2014 | |||||||
| Income tax provision calculated using the federal statutory income tax rate | $ | (27,139,366 | ) | $ | 1,444,432 | |||
| State income taxes, net of federal income taxes | (25,205 | ) | 37,910 | |||||
| Permanent differences, rate changes and other | 3,932 | 4,864 | ||||||
| Adjustment of previous deferred tax amounts | (974,829 | ) | - | |||||
| Change in valuation allowance | 14,078,569 | - | ||||||
| Total income tax expense | $ | (14,056,899 | ) | $ | (1,487,206 | ) | ||
Deferred income taxes arise from temporary differences in the recognition of certain items for income tax and financial reporting purposes. The approximate tax effects of significant temporary differences which comprise the deferred tax assets and liabilities at December 31, 2015 and 2014 are as follows:
| F-106 |
| December 31, | ||||||||
| 2015 | 2014 | |||||||
| Deferred tax assets | ||||||||
| Federal and state net operating loss carryforwards | $ | 9,380,168 | $ | 6,864,241 | ||||
| Oil and natural gas properties and other equipment | 2,122,275 | - | ||||||
| Stock-based compensation | 1,596,776 | 1,214,378 | ||||||
| Asset retirement obligations | 1,222,830 | 1,225,887 | ||||||
| Other | 5,784 | 5,784 | ||||||
| Total deferred tax assets | 14,327,833 | 9,310,290 | ||||||
| Deferred tax liabilities: | ||||||||
| Oil and natural gas properties and other equipment | - | (22,749,563 | ) | |||||
| Derivatives | (249,264 | ) | (600,469 | ) | ||||
| Total deferred tax liabilities | (249,264 | ) | (23,350,032 | ) | ||||
| Total net deferred tax (liability) | 14,078,569 | (14,039,742 | ) | |||||
| Valuation allowance | (14,078,569 | ) | - | |||||
| Deferred tax asset (liability), net of valuation allowance | $ | - | $ | (14,039,742 | ) | |||
At December 31, 2015, the Company has net operating losses as follows:
| Amount | Expiration | |||||
| Net operating losses: | ||||||
| Federal | $ | 26,846,276 | Dec. 2032 to 2035 | |||
| State | 6,562,922 | Dec. 2032 to 2035 | ||||
In assessing the need for a valuation allowance on our deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon whether future book income is sufficient to reverse existing temporary differences that give rise to deferred tax assets, as well as whether future taxable income is sufficient to utilize net operating loss and credit carryforwards. Assessing the need for, or the sufficiency of, a valuation allowance requires the evaluation of all available evidence, both positive and negative. Management had no positive evidence to consider. Negative evidence considered by management includes cumulative book and tax losses in recent years, forecasted book and tax losses, no taxable income in available carryback years, and no tax planning strategies contemplated to realize the valued deferred tax assets.
As of December 31, 2015 and 2014, management assessed the available positive and negative evidence to estimate if sufficient future taxable income would be generated to use the Company’s deferred tax assets and determined that it is not more-likely-than-not that the deferred tax assets would be realized in the near future. Therefore, the Company recorded a full valuation allowance of approximately $14,078,569 and $0 on its deferred tax assets as of December 31, 2015 and 2014, respectively.
| F-107 |
NOTE 15 - SUBSEQUENT EVENTS
Credit Facilities and Forbearance Agreement.
The maturity of our second lien note to SOSventures was extended to August 1, 2016. The Forbearance Period began with the execution of the IB Forbearance Agreement on November 24, 2015 and ended on January 31, 2016, but was subsequently extended to March 31, 2016. We are currently in discussions with the lender under the IB Credit Agreement regarding a further extension of the Forbearance Period.
On January 20, 2016, the Company, Lilis and Merger Sub entered into an amendment to the merger agreement (the “Amendment”). Pursuant to the Amendment: (i) the amount of the refundable deposit was increased by $1 million to a total of $2 million and (ii) the scope of the refundable deposit was broadened such that it now covers the amount paid by Lilis to Independent Bank on December 29, 2015 in addition to certain other matters, such as payments towards accounts payable, transactions costs and other operating costs of the Company.
On March 24, 2016, the Company, Lilis and Merger Sub entered into a second amendment to the Merger Agreement (the “Second Amendment”). Pursuant to the Second Amendment: (i) the definition of refundable deposit was modified to include such further increases as may be mutually agreed upon between the parties, (ii) the amount and treatment of restricted stock units of the Company with respect to the Merger Agreement was clarified, the definition of “Stock Exchange Ratio” was fixed at 4.550916 to account for certain grants of restricted stock to members of the Board of Directors of the Company pursuant to existing service agreements and (iv) the definition of “Termination Date” was changed from April 30, 2016 to May 31, 2016.
| F-108 |
Presented in accordance with
FASB ASC Topic 932, Extractive Activities - Oil and Gas
| F-109 |
BRUSHY RESOURCES, INC. AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION
Supplemental Oil and Natural Gas Disclosures (Unaudited)
The following tables set forth supplementary disclosures for oil and gas producing activities in accordance with FASB ASC Topic 932, Extractive Activities - Oil and Gas.
Capitalized Costs
The following table presents a summary of the Company’s oil and natural gas properties at December 31, 2015 and 2014:
| 2015 | 2014 | |||||||
| Oil and natural gas properties | ||||||||
| Proved-developed producing properties | $ | 43,912 | $ | 96,691 | ||||
| Proved-developed non-producing properties | 5,865 | 2,880 | ||||||
| Proved-undeveloped properties | - | 13,330 | ||||||
| Unproved properties | 2,389 | 1,996 | ||||||
| Less: Accumulated depletion | (35,282 | ) | (23,131 | ) | ||||
| Total oil and natural gas properties, net of accumulated depletion | $ | 16,884 | $ | 91,766 | ||||
The following table summarizes costs incurred in oil and natural gas property acquisition, exploration, and development activities. Property acquisition costs as those incurred to purchase lease or otherwise acquire property, including both undeveloped leasehold and the purchase of reserves in place. Exploration costs include costs of identifying areas that may warrant examination and examining specific areas that are considered to have prospects containing oil and natural gas reserves, including costs of drilling exploratory wells, geological and geophysical costs, and carrying costs on undeveloped properties. Development costs are incurred to obtain access to proved reserves, including the cost of drilling development wells, and to provide facilities for extracting, treating, gathering and storing oil and natural gas. Additionally, costs incurred also include new asset retirement obligations established. Asset retirement obligations included in the tables below in the as reported columns for the years ended December 31, 2015 and 2014 were approximately $(42,000) and $849,000, respectively
Costs incurred (capitalized and charged to expense) in oil and natural gas activities for the years ended December 31, 2015 and 2014 were as follows:
| 2015 | 2014 | |||||||
| Acquisitions of proved properties | $ | - | $ | 16,803,448 | ||||
| Exploration | 73,496 | 785,314 | ||||||
| Development | 8,118,390 | 17,244,950 | ||||||
| Total costs incurred | $ | 8,191,886 | $ | 34,749,337 | ||||
| F-110 |
BRUSHY RESOURCES, INC. AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION
Supplemental Oil and Natural Gas Disclosures (Unaudited) (continued)
Results of operations from oil and natural gas producing activities for the years ended December 31, 2015 and 2014, excluding Company overhead and interest costs, were as follows:
| 2015 | 2014 | |||||||
| Oil, natural gas and related product sales | $ | 8,606,606 | $ | 20,172,792 | ||||
| Lease operating costs | (3,677,845 | ) | (5,457,471 | ) | ||||
| Production taxes | (369,317 | ) | (695,693 | ) | ||||
| Exploration costs | (49,531 | ) | (80,533 | ) | ||||
| Depletion | (22,510,290 | ) | (10,140,152 | ) | ||||
| Impairment | (55,753,481 | ) | (4,428,378 | ) | ||||
| Results of operations from oil and natural gas producing activities | $ | (73,753,858 | ) | $ | (629,435 | ) | ||
Proved Reserves Methodology
The Company’s estimated proved reserves, as of December 31, 2014 and 2013, are made in accordance with the SEC’s final rule, Modernization of Oil and Gas Reporting, which amended Rule 4-10 of Regulation S-X (the “Final Rule”). As defined by the Final Rule, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future years from known reservoirs under existing economic conditions, operating methods, and government regulations. Projects to extract the hydrocarbons must have commenced or an operator must be reasonably certain that it will commence the projects within a reasonable time. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the projects. Further requirements for assignment of estimated proved reserves include the following:
The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by natural gas, oil, and/or water contacts, if any; and (B) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons and highest known oil seen in well penetrations unless geoscience, engineering, or performance data and reliable technology establishes a lower or higher contact with reasonable certainty. Reliable technologies are any grouping of one or more technologies (including computational methods) that have been field-tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
Reserves which can be produced economically through applications of improved recovery techniques (including, but not limited to fluid injections) are included in the proved classification when successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, and other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based.
| F-111 |
BRUSHY RESOURCES, INC. AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION
Supplemental Oil and Natural Gas Disclosures (Unaudited) (continued)
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The prices used are the average crude oil and natural gas prices during the twelve month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Reserves engineering is a subjective process of estimating underground accumulations of crude oil, condensate, natural gas, and natural gas liquids that cannot be measured in an exact manner. The accuracy of any reserves estimate is a function of the quality of available date and of engineering and geological interpretation and judgment. The reserves actually recovered, the timing of production of those reserves, as well as operating costs and the amount and timing of development expenditures may be substantially different from original estimates. Revisions result primarily from new information obtained from development drilling, production history, field tests, and data analysis and from changes in economic factors including expectation and assumptions as to availability of financing for development projects.
Reserve Quantity Information
The following table presents the Company’s estimate of its proved oil and gas reserves all of which are located in the United States. The estimates have been prepared with the assistance of Forrest A. Garb & Associates, Inc., an independent petroleum reservoir engineering firm. Oil reserves, which include condensate and natural gas liquids, are stated in barrels and gas reserves are stated in thousands of cubic feet.
| PROVED-DEVELOPED AND UNDEVELOPED RESERVES | Crude Oil (Bbl) | Natural Gas (Mcf) | ||||||
| December 31, 2013 | 3,650,910 | 8,639,620 | ||||||
| Revisions of previous estimates | (772,982 | ) | (758,638 | ) | ||||
| Extensions and discoveries | 558,000 | 333,230 | ||||||
| Acquisitions of reserves | 797,360 | 3,811,000 | ||||||
| Sales of reserves | (59,370 | ) | (474,930 | ) | ||||
| Production | (180,898 | ) | (779,012 | ) | ||||
| December 31, 2014 | 3,993,020 | 10,771,270 | ||||||
| Revisions of previous estimates | (3,334,352 | ) | (7,207,552 | ) | ||||
| Extensions and discoveries | 327,865 | 1,313,149 | ||||||
| Acquisitions of reserves | - | - | ||||||
| Sales of reserves | (165,430 | ) | (1,430,690 | ) | ||||
| Production | (152,273 | ) | (676,847 | ) | ||||
| December 31, 2015 | 668,830 | 2,769,330 | ||||||
| PROVED DEVELOPED RESERVES | ||||||||
| December 31, 2015 | 668,830 | 2,769,330 | ||||||
| December 31, 2014 | 853,560 | 4,324,760 | ||||||
| F-112 |
BRUSHY RESOURCES, INC. AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION
Supplemental Oil and Natural Gas Disclosures (Unaudited) (continued)
The following table presents the Company’s changes in proved undeveloped reserves.
PROVED UNDEVELOPED RESERVES
Crude Oil (Bbl) | Natural Gas (Mcf) | |||||||
| December 31, 2013 | 3,166,300 | 6,539,420 | ||||||
| Revisions of previous estimates | (704,790 | ) | (921,280 | ) | ||||
| Extensions and discoveries | 540,150 | 237,800 | ||||||
| Acquisitions of reserves | 531,350 | 1,887,730 | ||||||
| Sales of reserves | (59,370 | ) | (474,930 | ) | ||||
| Transfer to developed | (334,170 | ) | (822,240 | ) | ||||
| December 31, 2014 | 3,139,470 | 6,446,500 | ||||||
| Revisions of previous estimates | (3,099,750 | ) | (6,128,780 | ) | ||||
| Extensions and discoveries | 0 | 0 | ||||||
| Acquisitions of reserves | 0 | 0 | ||||||
| Sales of reserves | (39,720 | ) | (317,720 | ) | ||||
| Transfer to developed | 0 | 0 | ||||||
| December 31, 2015 | 0 | 0 | ||||||
Due to the lack of available capital required to drill the proved undeveloped locations, all proven undeveloped reserves were removed during 2015.
Future cash flows are computed by applying a first-day-of-the-month 12-month average price of natural gas (Henry Hub) and oil (West Texas Intermediate) to year end quantities of proved natural gas and oil reserves. Future operating expenses and development costs are computed primarily by the Company's petroleum engineers by estimating the expenditures to be incurred in developing and producing the Company’s proved natural gas and oil reserves at the end of the year, based on year end costs and assuming continuation of existing economic conditions. For the year ended December 31, 2015, the oil and natural gas prices were applied at $47.03/Bbl and $2.23/Mcf, respectively, in the standardized measure. For the year ended December 31, 2014, the oil and natural gas prices were applied at $91.42/Bbl and $6.53Mcf, respectively, in the standardized measure.
Standardized Measure of Discounted Future Net Cash Flow and Changes Therein Relating to Proved Oil and Gas Reserves
The following tables, which presents a standardized measure of discounted future cash flows and changes therein relating to proved oil and gas reserves as of December 31, 2015 and 2014, for the years ended December 31, 2015 and 2014, is presented pursuant to ASC 932. In computing this data, assumptions other than those required by the Financial Accounting Standards Board could produce different results. Accordingly, the data should not be construed as being representative of the fair market value of the Company’s proved oil and gas reserves.
| F-113 |
BRUSHY RESOURCES, INC. AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION
Supplemental Oil and Natural Gas Disclosures (Unaudited) (continued)
A discount factor of 10 percent was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement costs or fair value of the Company's natural gas and oil properties. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of time value of money and the risks inherent in reserve estimates of natural gas and oil producing operations. There have been no estimates for future plugging and abandonment costs
Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2015
| Future cash inflows | 37,611,800 | |||
| Less: Future production costs | (16,468,590 | ) | ||
| Future development costs | - | |||
| Future income tax expense | - | |||
| Future net cash flows | 21,143,210 | |||
| 10% discount factor | (6,300,765 | ) | ||
| Strandardized measure of discounted future net cash inflows | 14,842,445 |
Changes in Standardized Measure of Discounted Future Net Cash Flows for the Year Ended December 31, 2015
| Standardized measure - beginning of year | 90,116,131 | |||
| Sales of oil and natural gas, net of production costs | (4,559,444 | ) | ||
| Net changes in prices and production costs | (134,395,658 | ) | ||
| Development costs incurred during the year | 457,344 | |||
| Changes in future development costs | 71,777,018 | |||
| Extensions, discoveries, and improved recoveries | 9,321,938 | |||
| Revisions/timing of previous quantity estimates | (69,250,616 | ) | ||
| Accretion of discount | 13,199,248 | |||
| Net change in income taxes | 39,332,749 | |||
| Purchases and sale of mineral interests | (1,156,265 | ) | ||
| End of year | 14,842,445 |
Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2014
| Future cash inflows | 435,341,260 | |||
| Less: Future production costs | (104,680,910 | ) | ||
| Future development costs | (92,010,030 | ) | ||
| Future income tax expense | (72,379,134 | ) | ||
| Future net cash flows | 166,271,186 | |||
| 10% discount factor | (76,155,055 | ) | ||
| Standardized measure of discounted future net cash inflows | 90,116,131 |
| F-114 |
BRUSHY RESOURCES, INC. AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION
Supplemental Oil and Natural Gas Disclosures (Unaudited) (continued)
Changes in Standardized Measure of Discounted Future Net Cash Flows for the Year Ended December 31, 2015
Net Changes in Prices and Production Costs: For the year ended December 31, 2015, the oil and natural gas prices were applied at $47.03/Bbl and $2.23/Mcf, respectively, in the standardized measure. At December 31, 2014, the oil and natural gas prices were applied at $91.42/Bbl and $6.53/Mcf, respectively, in the standardized measure. The decrease in oil and natural gas prices resulted in a significant decrease in future expected cash flows and reserves.
Extensions, Discoveries, and Improved Recoveries: During the year ended December 31, 2015, the Company had extensions and discoveries of 327,870 Bbl of crude oil and 1,313,150 Mcf of natural gas from primarily newly identified horizontal drilling opportunities in the Delaware Basin, located in the Crittendon field.
Revisions of Previous Quantity Estimates: During the year ended December 31, 2015, the Company adjusted its previous estimates by (3,460,067) Bbl of crude oil and (8,320,523) Mcf of natural gas from primarily removal of proven undeveloped reserves that the Company currently has interests in due to lack of available capital.
Purchases and sales of mineral interests: During the year ended December 31, 2015, the Company sold its Oklahoma properties in Logan and Kingfisher counties.
Accretion of Discount: Accretion during the year ended December 31, 2014 was the result of accretion of the future net revenues at a standard rate of 10% due to the passage of time.
Significant Changes in Reserves for the Year Ended December 31, 2013
Net Changes in Prices and Production Costs: For the year ended December 31, 2014, the oil and natural gas prices were applied at $95.28/Bbl and $4.36/MMBtu, respectively, in the standardized measure. At December 31, 2013, the oil and natural gas prices were applied at $96.90/Bbl and $3.67/MMBtu, respectively, in the standardized measure. The increase in oil and natural gas prices resulted in a significant increase in future expected cash flows and reserves. Each of the reference prices for oil and natural gas were adjusted for quality factors and regional differences.
Extensions, Discoveries, and Improved Recoveries: During the year ended December 31, 2014, the Company had extensions and discoveries of 558,000 Bbl of crude oil and 333,230 Mcf of natural gas from primarily newly identified drilling opportunities in the Eaglebine oil and natural gas reservoirs as well as new drills in Oklahoma.
Revisions of Previous Quantity Estimates: During the year ended December 31, 2014, the Company adjusted its previous estimates by (772,982) Bbl of crude oil and (758,638) Mcf of natural gas from primarily revisions of proved undeveloped reserves that the Company currently has interests in due to increases in estimated production costs and the requirement that a development plan for the undeveloped oil and gas reserves must be adopted indicating that such reserves are scheduled to be drilled within five years under SEC Regulation S-X Rule 4-10(a)(31)(ii).
| F-115 |
BRUSHY RESOURCES, INC. AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION
Supplemental Oil and Natural Gas Disclosures (Unaudited) (continued)
Purchases and sales of mineral interests: During the year ended December 31, 2014, the Company purchased the Crittendon Field.
Accretion of Discount: Accretion during the year ended December 31, 2014 was the result of accretion of the future net revenues at a standard rate of 10% due to the passage of time.
| F-116 |
Up to 22,865,487 Shares of Common Stock
LILIS ENERGY, INC.
PROSPECTUS
, 2017
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
| Item 13. | Other Expenses of Issuance and Distribution. |
The following table sets forth all costs and expenses incurred in connection with the offering described in this registration statement, all of which will be paid by us, other than any underwriting discounts and commissions payable by the selling stockholders in connection with any sale and distribution of the securities being registered. All amounts shown are estimates except for the SEC registration fee.
| Amount | ||||
| Securities and Exchange Commission Registration Fee | $ | 12,274.86 | ||
| Printing Expenses | 11,000 | |||
| Legal Fees and Expenses | 1,000,000 | |||
| Accounting Fees and Expenses | 55,000 | |||
| Transfer Agent and Registrar Fees and Expenses | 4,000 | |||
| Miscellaneous Expenses | 3,000 | |||
| Total | $ | 1,085,274.86 | ||
| Item 14. | Indemnification of Directors and Officers. |
Section 78.7502(1) of the Nevada Revised Statutes, which is referred to as the NRS, provides that a corporation may indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending, or completed action, suit, or proceeding, whether civil, criminal, administrative, or investigative, except an action by or in the right of the corporation, by reason of the fact that the person is or was a director, officer, employee, or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee, or agent of another corporation, partnership, joint venture, trust, or other enterprise, against expenses, including attorneys’ fees, judgments, fines, and amounts paid in settlement actually and reasonably incurred by the person in connection with the action, suit, or proceeding if the person acted in good faith and in a manner he or she reasonably believed to be in or not opposed to the best interests of the corporation, and, with respect to any criminal action or proceeding, had no reasonable cause to believe his conduct was unlawful.
Section 78.7502(2) of the NRS provides that a corporation may similarly indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending, or completed action or suit by or in the right of the corporation to procure a judgment in its favor by reason of the fact that the person is or was a director, officer, employee, or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee, or agent of another corporation, partnership, joint venture, trust, or other enterprise, against expenses, including amounts paid in settlement and attorneys’ fees actually and reasonably incurred by the person in connection with the defense or settlement of the action or suit if the person acted in good faith and in a manner he or she reasonably believed to be in or not opposed to the best interests of the corporation and except that no indemnification shall be made in respect of any claim, issue, or matter as to which such a person has been adjudged by a court of competent jurisdiction, after exhaustion of all appeals therefrom, to be liable to the corporation or for amounts paid in settlement to the corporation, unless and only to the extent that the court in which the action or suit was brought or other court of competent jurisdiction determines upon application that in view of all the circumstances of the case, the person is fairly and reasonably entitled to indemnity for such expenses as the court deems proper.
Section 78.7502(3) of the NRS provides that to the extent a director, officer, employee, or agent of a corporation has been successful on the merits or otherwise in defense of any action, suit, or proceeding referred to in subsections (1) and (2), or in defense of any claim, issue, or matter therein, the corporation shall indemnify such person against expenses, including attorneys’ fees, actually and reasonably incurred by him or her in connection with the defense.
II-1
Section 78.751(1) of the NRS provides that any discretionary indemnification under Section 78.7502, unless ordered by a court or advanced pursuant to subsection 2 of Section 78.751, may be made by the corporation only as authorized in the specific case upon determination that indemnification of such director, officer, employee, or agent is proper in the circumstances. The determination must be made (a) by the stockholders; (b) by the board of directors by a majority vote of a quorum consisting of directors who were not parties to the action, suit, or proceeding; (c) if a majority vote of a quorum consisting of directors who were not parties to the action, suit, or proceeding so orders, by independent legal counsel in a written opinion; or (d) if a quorum consisting of directors who were not parties to the action, suit, or proceeding cannot be obtained, by independent legal counsel in a written opinion.
Section 78.751(2) of the NRS provides that the articles of incorporation, bylaws, or an agreement made by the corporation may provide that the expenses of officers and directors incurred in defending a civil or criminal action, suit, or proceeding must be paid by the corporation as they are incurred and in advance of the final disposition of the action, suit, or proceeding, upon receipt of an undertaking by or on behalf of the director or officer to repay the amount if it is ultimately determined by a court of competent jurisdiction that he or she is not entitled to be indemnified by the corporation. Such provision does not affect any rights to advancement of expenses to which corporate personnel other than directors or officers may be entitled under any contract or otherwise by law.
Section 78.751(3) of the NRS provides that the indemnification pursuant to Section 78.7502 of the NRS and advancement of expenses authorized in, or ordered by, a court pursuant to Section 78.751, (a) does not exclude any other rights to which a person seeking indemnification or advancement of expenses may be entitled under the articles of incorporation or any bylaw, agreement, vote of stockholders or disinterested directors, or otherwise, for either an action in the person’s official capacity or an action in another capacity while holding office, except that indemnification, unless ordered by a court pursuant to Section 78.7502 of the NRS or for the advancement of expenses made pursuant to Section 78.751 (2), may not be made to or on behalf of any director or officer if a final adjudication establishes that the director’s or officer’s acts or omissions involved intentional misconduct, fraud, or a knowing violation of the law and was material to the cause of action; and (b) continues for a person who has ceased to be a director, officer, employee, or agent and inures to the benefit of the heirs, executors, and administrators of such a person.
Section 78.752 of the NRS provides that a Nevada corporation may purchase and maintain insurance or make other financial arrangements on behalf of any person who acted in any of the capacities set forth above for any liability asserted against such person for any liability asserted against him or her and liability and expenses incurred by him or her in any such capacity or arising out of his or her status as such, whether or not the corporation has the authority to indemnify him or her against such liabilities and expenses.
Lilis’s Articles of Incorporation provide for indemnification to the fullest extent permissible under Nevada law. They also provide for the payment of expenses of any person who is or was a director or officer, or, while a director or officer of Lilis, is or was serving at the request of the Lilis as a director or officer, employee or agent of another corporation, partnership, joint venture, trust, association or other enterprise, who is deemed to have acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the Corporation and, with respect to any criminal action or proceeding, had no reasonable cause to believe his conduct was unlawful.
Lilis’s Bylaws provide that Lilis shall indemnify any person who is a director or officer of Lilis, or, while a director or officer of Lilis, is or was serving at the request of the Lilis as a director, officer, employee or agent of another corporation, partnership, joint venture, trust, association or other enterprise, who is deemed to have acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of Lilis and, with respect to any criminal action or proceeding, had no reasonable cause to believe his conduct was unlawful. Expenses incurred in defending a civil or criminal action, suit, or proceeding may be paid by Lilis in advance of the final disposition of the action, suit, or proceeding, but only after receipt by Lilis of an undertaking by or on behalf of the officer or director to repay the expenses advanced if it is ultimately determined that the officer or director is not entitled to be indemnified by Lilis as authorized in Lilis’s Bylaws. No indemnification shall be made in respect of any claim, issue or matter as to which such person shall have been adjudged to be liable to Lilis unless and only to the extent that the court in which such action or suit was brought shall determine upon application that, despite the adjudication of liability but in view of all the circumstances of the case, such person is fairly and reasonably entitled to indemnity for such expenses which the court shall deem proper.
Lilis’s Bylaws also provide that the indemnification permitted in such Bylaws is intended to be to the fullest extent permissible under the laws of the State of Nevada.
II-2
The non-employee director agreements that Lilis has entered into with certain of its directors provide for indemnification of directors by Lilis to the fullest extent permitted by the laws of the State of Nevada and additionally permits advancing attorneys' fees and all other reasonable costs and expenses incurred by such director upon written demand to Lilis, generally in connection with the investigation, defense or other participation in any threatened, pending or completed action, suit or proceeding. If it is later determined that the director is or was not entitled to indemnification under applicable law, Lilis is entitled to reimbursement by the director.
Lilis maintains directors’ and officers’ insurance which, subject to certain exclusions, insures its directors and officers against certain losses which arise out of any neglect or breach of duty (including, but not limited to, any error, misstatement, act, or omission) by the directors or officers in the discharge of their duties, and insures them against amounts which Lilis has paid or may become obligated to pay as indemnification to its directors and/or officers to cover such losses.
| Item 15. | Recent Sales of Unregistered Securities. |
Set forth below is information regarding securities sold and issued by us since March 1, 2014 that were not registered under the Securities Act, as well as the consideration received by us for such securities and information relating to the section of the Securities Act, or rule of the Securities and Exchange Commission, under which exemption from registration was claimed.
All share figures and exercise prices noted in this Item 15 applicable to our Common Stock from transactions that occurred prior to the June 23, 2016 reverse split have been adjusted to reflect the 1-for-10 reverse split of our issued and outstanding Common Stock.
Consulting Warrants
In a series of transactions between 2013 and 2015, Lilis Energy, Inc. (the “Company”) issued warrants to purchase an aggregate amount of 70,000 shares of common stock to Market Development Group, Inc. for services rendered in connection with various consulting agreements that contained piggyback rights. The exercise prices on the warrants ranged from $42.50 to $20.00.
Debenture Conversion Agreement January 2014
On January 31, 2014, the Company entered into a debenture conversion agreement with all of the holders of its 8% Senior Secured Convertible Debentures (the “Debentures”). The terms of the agreement provided for an immediate conversion of $9 million of the approximately $15.6 million in outstanding Debentures. Pursuant to the terms of the agreement, the Debentures were converted at a price of $2.00. In addition, the Company issued warrants to the Debenture holders to purchase one share of Common Stock, at an exercise price equal to $25.00 per share equal to the number of Common Stock issued pursuant to the Debenture holder’s conversion elections.
The Company paid TRW a five percent (5%) fee on the conversion of the Debentures, payable in Common Stock at a price of $20.00 per share.
From the original date of issuance through October 25, 2016, 231,064 shares of Common Stock have been issued as interest payments on the Debentures.
In connection with the foregoing, the Company relied upon the exemption from securities registration provided by Section 4(a)(2) under the Securities Act of 1933, as amended for transactions not involving a public offering.
Series A 8% Preferred Stock May 2014
On May 30, 2014, the Company sold 7,500 shares of Series A Preferred Stock to accredited investors for an aggregate purchase price of $7.5 million with a conversion price of $24.10 and warrants to purchase an aggregate of 1,556,017 shares of Common Stock at an exercise price of $28.90. These securities were issued pursuant to Section 4(a)(2) of the Securities Act and Rule 506 promulgated thereunder.
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6% Redeemable Preferred Stock September 2014
On September 2, 2014, the Company into a settlement agreement with Hexagon, LLC (“Hexagon”), its former senior lender, to settle all amounts payable by the Company pursuant to which it issued to Hexagon $2.0 million in a new series of 6% Redeemable Preferred Stock (the “Redeemable Preferred”). The Redeemable Preferred bears a 6% dividend per annum, payable quarterly, and is redeemable at face value (plus any accrued and unpaid dividends) at any time at the Company’s option, or at Hexagon’s option upon the Company’s achievement of certain production and reserves thresholds. The Redeemable Preferred is not convertible into common stock or any other securities of the Company.
The Redeemable Preferred were issued pursuant to Section 4(a)(2) of the Securities Act and Rule 506 promulgated thereunder.
Equity Compensation September 2014 through January 2016
Between September of 2014 and January of 2016, the Company issued 114,501 shares of restricted stock, options to purchase 525,000 shares of Common Stock and warrants to purchase 225,000 shares of Common Stock to employees, directors and consultants as equity compensation pursuant to its 2012 Equity Incentive Plan under Section 4(a)(2) of the Securities Act.
Heartland Credit Agreement January 2015
On January 8, 2015, the Company entered into a credit agreement with Heartland Bank pursuant to which it issued Heartland a warrant to purchase up to 22,500 shares of Common Stock at an exercise price of $25.00 pursuant to Section 4(a)(2) of the Securities Act, subject to certain anti-dilution adjustments. The warrant entitled the holder to piggyback rights.
12% Convertible Subordinated Notes
In a series of transactions from December 29, 2015 to May 6, 2016, the Company issued an aggregate of approximately $5.8 million Convertible Notes maturing on June 30, 2016 and April 1, 2017, at a conversion price of $5.00 and warrants to purchase an aggregate of approximately 2.3 million shares of Common Stock with an exercise price of $2.50 (post-split) for warrants issued between December 2015 and March 2016 and $0.10 for the warrants issued in May 2016. 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 the Company 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, the Company reduced the exercise price on warrants to purchase a total of 416,454 shares of Common Stock ranging from $42.50 to $25.00 per share to $0.10 per share, of which a total of 315,990 were subsequently exercised, resulting in the issuance of an aggregate amount of 300,706 shares of Common Stock due to certain cashless exercises. On August 3, 2016, the Company entered into the first amendment to the Convertible Notes with the remaining holders of approximately $1.8 million of Convertible Notes. In exchange for the holders’ willingness to enter into the first amendment, the Company issued to the holders warrants to purchase up to approximately 1.7 million shares of Common Stock. The warrants have an exercise price of $2.50 per share, and are immediately exercisable from the issuance date for a period of three years, subject to certain circumstances. On September 29, 2016, in connection with the Company’s entry into the Credit and Guarantee Agreement, the remaining outstanding principal on Convertible Notes along with the accrued interest thereunder was converted in full resulting in the issuance of 1,772,456 shares of Common Stock.
These securities were issued pursuant to Section 4(a)(2) of the Securities Act.
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Series B 6% Preferred Stock June 2016
On June 15, 2016, the Company entered into a securities purchase agreement to sell 20,000 shares of Series B Preferred Stock (the “Series B Preferred Stock”) with a conversion price of $1.10 to certain institutional and accredited investors for an aggregate purchase price of $20 million. In connection with the Series B Preferred Stock offering, the Company also issued to each investor a warrant to purchase a number of shares of the Company’s common stock equal to one-half of the number of shares of Common Stock into which the Preferred Stock is convertible, which is an aggregate of approximately 9.1 million shares of Common Stock. The warrants were originally issued with an exercise price of $2.50 per share. In connection with the Company’s entry into the Credit and Guarantee Agreement and as partial consideration the Company reduced the exercise price on approximately 2.85 million warrants from $2.50 to $0.01 per share. For a more detailed description of the terms of the Credit and Guarantee Agreement and the warrant reprice see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”
As discussed in “—12% Convertible Subordinated Notes,” above, TRW also converted a portion of its advisory fee on the Convertible Notes transactions into shares of Series B Preferred Stock and the related warrants. The warrants referred to in this paragraph, as well as the warrant issued to TRW to purchase 227,273 shares of common stock, discussed immediately below, are collectively referred to throughout this prospectus as the Series B Warrants.
In connection with the Series B Preferred Stock offering, TRW acted as co-broker dealers along with KES 7 Capital Inc. (KES 7), and as administrative agent. In addition to cash fees, TRW and KES 7 received broker warrants to purchase up to 452,724 and 820,000 shares of Common Stock, respectively, at an exercise price of $1.30, exercisable on or after September 17, 2016, for a period of two years. The broker warrant issued to KES that is referred to in the foregoing sentence is referred to throughout this prospectus as the Fee Warrant.
These securities were issued pursuant to Section 4(a)(2) of the Securities Act and Rule 506 promulgated thereunder.
March 2017 Private Placement
On February 28, 2017, we entered into a securities subscription agreement with certain institutional and accredited investors in connection with a private placement to sell approximately 5.2 million units, consisting of approximately 5.2 million shares of common stock and warrants to purchase approximately an additional 2.6 million shares of common stock, for an aggregate purchase price of approximately $20 million. Each unit consists of one share of common stock and a warrant to purchase 0.50 shares of common stock, at a price per unit of $3.85. Each warrant has an exercise price of $4.50 and, after the second anniversary, may be subject to redemption by the Company, upon prior written notice, if the price of the Company’s common stock closes at or above $6.30 for twenty trading days during a consecutive thirty trading day period. Johnson Rice & Company L.L.C. (JR) and T.R. Winston & Company, LLC (TRW), served as placement agents in connection with this offering, and KES 7 Capital Inc. (KES 7) acted as advisor to the Company.
These securities were issued pursuant to Section 4(a)(2) of the Securities Act and Rule 506 promulgated thereunder.
No underwriters were involved in the foregoing sales of securities described in this section (a) of Item 15, and all securities were issued to investors in reliance upon the exemption from the registration requirements of the Securities Act, as set forth in Section 3(a)(9) and/or Section 4(a)(2) under the Securities Act and Regulation D promulgated thereunder relative to transactions by an issuer not involving any public offering, to the extent an exemption from such registration was required. All purchasers described above represented to us in connection with their purchase that they were accredited investors and were acquiring the shares for their own account for investment purposes only and not with a view to, or for sale in connection with, any distribution thereof and that they could bear the risks of the investment and could hold the securities for an indefinite period of time. The purchasers received written disclosures that the securities had not been registered under the Securities Act and that any resale must be made pursuant to a registration statement or an available exemption from such registration. We did not engage in any general solicitation or advertising in connection with the foregoing issuances.
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Second Lien Term Loan
On April 26, 2017, we entered into the Second Lien Term Loan, between the Company, the Guarantors, Wilmington Trust, National Association, as administrative agent, and the lenders party thereto (the “Lenders”). The Second Lien Term Loan and any Delayed Draws thereunder are convertible into common stock at $5.50 subject to certain anti-dilution adjustments. For more information on the Second Lien Term Loan see Management’s Discussion and Analysis—Recent Developments —Second Lien Credit Agreement.
All of the foregoing securities are deemed restricted securities for purposes of the Securities Act. All certificates representing the issued shares of capital stock described in this Item 15 included appropriate legends setting forth that the securities had not been registered and the applicable restrictions on transfer.
| Item 16. | Exhibits and Financial Statement Schedules |
| (a) | Exhibits |
See Exhibit Index immediately following the signature page to this registration statement.
| (b) | Financial Statement Schedules |
All other schedules are omitted because they are not required, are not applicable, or the information is included in the consolidated financial statements or the related notes to consolidated financial statements thereto.
| Item 17. | Undertakings. |
| (a) | The undersigned registrant hereby undertakes: |
(1) To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:
(i) To include any prospectus required by Section 10(a)(3) of the Securities Act;
(ii) To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than 20 percent change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement;
(iii) To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement.
(2) That, for the purpose of determining any liability under the Securities Act, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.
(3) To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.
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(4) That, for the purpose of determining liability under the Securities Act to any purchaser, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.
(5) That, for the purpose of determining liability under the Securities Act of 1933 to any purchaser in the initial distribution of the securities: the undersigned registrant undertakes that in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser: (i) any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424; (ii) any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant; (iii) the portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and (iv) any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.
(b) Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.
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SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this Pre-Effective Amendment No. 1 to the Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of New York, State of New York, on this 16th day of June, 2017.
| LILIS ENERGY, INC. | ||
| By: | /s/ Abraham Mirman | |
| Abraham Mirman | ||
| Chief Executive Officer | ||
Pursuant to the requirements of the Securities Act, this Pre-Effective Amendment No. 1 to the Registration Statement has been signed by the following persons in the capacities indicated below on this 16th day of June, 2017.
| Signature | Title | Date | ||
| /s/ Abraham Mirman | Chief Executive Officer and Director | June 16, 2017 | ||
| Abraham Mirman | (Principal Executive Officer) | |||
| * | Executive Vice President and Chief Financial Officer | June 16, 2017 | ||
| Joseph C. Daches | (Principal Financial Officer and Principal Accounting Officer) | |||
| * | Executive Chairman of the Board and Director | June 16, 2017 | ||
| Ronald D. Ormand | ||||
| * | Director | June 16, 2017 | ||
| Nuno Brandolini | ||||
| * | Director | June 16, 2017 | ||
| General Merrill McPeak | ||||
| * | Director | June 16, 2017 | ||
| R. Glenn Dawson | ||||
| * | Director | June 16, 2017 | ||
| Peter Benz |
* Abraham Mirman hereby signs this Pre-Effective Amendment No. 1 to the Registration Statement on behalf of each of the indicated persons for whom he is attorney-in-fact on June 16, 2017.
| By: | /s/ Abraham Mirman | |
| Abraham Mirman | ||
| Attorney-in-Fact |
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INDEX TO EXHIBITS
The following exhibits are either filed herewith or incorporated herein by reference
| 2.1 | Agreement and Plan of Merger, dated as of December 29, 2015, among Lilis Energy, Inc., Lilis Merger Sub, Inc. and Brushy Resources, Inc. (incorporated herein by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on January 5, 2016). |
| 2.2 | First Amendment to Agreement and Plan of Merger, dated as of January 20, 2016, among Lilis Energy, Inc., Lilis Merger Sub, Inc. and Brushy Resources, Inc. (incorporated herein by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on January 20, 2016). |
| 2.3 | Second Amendment to Agreement and Plan of Merger, dated as of March 24, 2016, among Lilis Energy, Inc., Lilis Merger Sub, Inc. and Brushy Resources, Inc. (incorporated herein by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on March 24, 2016). |
| 2.4 | Third Amendment to Agreement and Plan of Merger, dated as of June 22, 2016, among Lilis Energy, Inc., Lilis Merger Sub, Inc. and Brushy Resources, Inc. (incorporated herein by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on June 28, 2016). |
| 3.1 | Amended and Restated Articles of Incorporation of Recovery Energy, Inc., dated as of October 10, 2011 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on October 20, 2011). |
| 3.2 | Certificate of Amendment to the Amended and Restated Articles of Incorporation of Recovery Energy, Inc., dated as of November 18, 2013 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on November 19, 2013). |
| 3.3 | Certificate of Designation of Preferences, Rights, and Limitations of Series A 8% Convertible Preferred Stock, dated as of May 30, 2014 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 4, 2014). |
| 3.4 | Amendment to Certificate of Designation of Preferences, Rights, and Limitations of Series A 8% Convertible Preferred Stock, dated as of June 12, 2014 (incorporated herein by reference to Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, filed on June 17, 2014). |
| 3.5 | Certificate of Designation of Preferences, Rights and Limitations of 6% Redeemable Preferred Stock, dated as of August 29, 2014 (incorporated herein by reference to Exhibit 3.3 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2014, filed on November 26, 2014). |
| 3.6 | Certificate of Designation of Preferences, Rights and Limitations of Series B 6% Convertible Preferred Stock, dated as of June 15, 2016 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 16, 2016). |
| 3.7 | Certificate of Change of Lilis Energy, Inc., dated as of June 21, 2016 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 28, 2016). |
| 3.8 | Amended and Restated Bylaws (incorporated herein by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed on June 18, 2010). |
| 3.9 | Amended and Restated Certificate of Designations of Preferences, Rights and Limitations of Series B 6% Convertible Preferred Stock, dated April 25, 2017 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on April 27, 2017). |
| 4.1 | Form of Warrant (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on January 28, 2014). |
| 4.2 | Form of Warrant (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on February 6, 2014). |
| 4.3 | Five Year Warrant to David Castaneda dated January 17, 2014 (incorporated herein by reference to Exhibit 4.1 to the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2014, filed on June 17, 2014). |
| 4.4 | Five Year Warrant (Anniversary Warrant) to David Castaneda dated January 17, 2014 (incorporated herein by reference to Exhibit 4.2 to the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2014, filed on June 17, 2014). |
| 4.5 | Form of Warrant dated May 30, 2014 (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on June 4, 2014). |
| 4.6 | Warrant to Purchase Common Stock issued to Bristol Capital (incorporated herein by reference to Exhibit 4.3 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2014, filed on November 26, 2014). |
| 4.7 | Warrant to Purchase Common Stock issued to Heartland Bank (incorporated herein by reference to Exhibit 4.3 to the Company’s Quarterly Report on Form 10-Q, filed on February 26, 2015). |
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| 4.8 | Form of Convertible Note (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on January 5, 2016). |
| 4.9 | Form of Warrant (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on January 5, 2016). |
| 4.10 | Form of Common Stock Purchase Warrant (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on June 16, 2016). |
| 4.11 | Common Stock Purchase Warrant issued to SOSV Investments, LLC on June 23, 2016. (incorporated herein by reference to Exhibit 4.3 to the Company’s Quarterly Report on Form 10-Q filed on August 25, 2016). |
| 4.12 | Form of Warrant (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on February 28, 2017). |
| 4.13 | Form of Common Stock Certificate (incorporated herein by reference to Exhibit 4.1 to the Company’s Registration Statement on Form S-1 filed on September 16, 2016). |
| 4.14 | Form of Warrant (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on March 2, 2017). |
| 4.15† | Lilis Energy, Inc. 2016 Omnibus Incentive Plan and forms of agreement thereunder (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on June 28, 2016). |
| 4.16† | First Amendment to the Lilis Energy, Inc. 2016 Omnibus Incentive Plan, approved on November 3, 2016 (incorporated herein by reference to Annex C to the Company’s Definitive Proxy filed on September 30, 2016). |
| 5.1* | Opinion of Fennemore Craig, P.C. as to the validity of the securities being registered. |
| 10.1† | Employment Agreement with Kevin Nanke, dated as of March 6, 2015 (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on March 12, 2015). |
| 10.2† | Employment Agreement with Ariella Fuchs, dated as of March 16, 2015 (incorporated herein by reference to Exhibit 10.84 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2014, filed on April 15, 2015). |
| 10.3† | Amended and Restated Employment Agreement between the Company and Abraham Mirman, dated as of March 30, 2015 (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 2, 2015). |
| 10.4 | Recovery Energy, Inc. 2012 Equity Incentive Plan dated August 31, 2012, as amended (incorporated herein by reference to Annex A to the Company’s definitive proxy filed on December 15, 2015). |
| 10.5 | Voting Agreement, dated as of December 29, 2015, among Lilis Energy, Inc., Lilis Merger Sub, Inc., Brushy Resources, Inc. and SOSventures, LLC (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 5, 2016). |
| 10.6 | Voting Agreement, dated as of December 29, 2015, among Lilis Energy, Inc., Lilis Merger Sub, Inc., Brushy Resources, Inc. and Longview Marquis Fund LP, LMIF Investments LLC and SMF investments, LLC (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on January 5, 2016). |
| 10.7 | Debenture Conversion Agreement, dated as of December 29, 2015, among Lilis Energy, Inc., T.R. Winston & Company, acting as placement agent, and each Debenture holder (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on January 5, 2016). |
| 10.8 | Form of Convertible Note Purchase Agreement (incorporated herein by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K filed on January 5, 2016). |
| 10.9 | Form of Note Exchange Agreement (incorporated herein by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K filed on January 5, 2016). |
| 10.10 | Form of Securities Purchase Agreement (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on June 16, 2016). |
| 10.11 | Form of Registration Rights Agreement (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on June 16, 2016). |
| 10.12 | Convertible Subordinated Promissory Note Conversion Agreement, dated as of June 23, 2016, among Lilis Energy, Inc. and the parties signatory thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on June 28, 2016). |
| 10.13 | First Amendment to the Convertible Subordinated Promissory Notes, dated as of August 3, 2016, among Lilis Energy, Inc. and the parties signatory thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on August 5, 2016). |
| 10.14† | Employment Agreement with Michael Pawelek, dated as of July 5, 2016 (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on July 8, 2016). |
| 10.15† | Employment Agreement with Edward Shaw, dated as of July 5, 2016 (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on July 8, 2016). |
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| 10.16† | Employment Agreement with Abraham Mirman, dated as of July 5, 2016 (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on July 8, 2016). |
| 10.17† | Employment Agreement with Kevin Nanke, dated as of July 5, 2016 (incorporated herein by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on July 8, 2016). |
| 10.18† | Employment Agreement with Ariella Fuchs, dated as of July 5, 2016 (incorporated herein by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K filed on July 8, 2016). |
| 10.19† | Employment Agreement with Ronald Ormand, dated as of July 5, 2016 (incorporated herein by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K filed on July 8, 2016). |
| 10.20 | Transaction Fee Agreement, dated as of June 6, 2016, between Lilis Energy, Inc. and T.R. Winston & Company, LLC (incorporated herein by reference to Exhibit 10.12 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2016 filed on August 25, 2016). |
| 10.21 | First Amendment to Transaction Fee Agreement, dated as of June 8, 2016, between Lilis Energy, Inc. and T.R. Winston & Company, LLC (incorporated herein by reference to Exhibit 10.13 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2016 filed on August 25, 2016). |
| 10.22 | Escrow Deposit Agreement, dated as of May 26, 2016, by and among Lilis Energy, Inc., T.R. Winston & Company, LLC and Signature Bank (incorporated herein by reference to Exhibit 10.15 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2016 filed on August 25, 2016). |
| 10.23 | Texican Crude & Hydrocarbon LLC Purchase Contract, dated as of February 3, 2016, between Texican Crude & Hydrocarbon, LLC and Impetro Operating LLC (incorporated herein by reference to Exhibit 10.65 to Brushy Resources, Inc.’s Registration Statement on Form S-1 filed on September 16, 2016). |
| 10.24 | DCP Midstream, LP Gas Purchase Agreement (incorporated herein by reference to Exhibit 10.8 to Brushy Resources, Inc.’s Form 10/A filed on July 26, 2013, which became effective August 6, 2013). |
| 10.25 | Credit and Guarantee Agreement, dated as of September 29, 2016 by and among Lilis Energy, Inc., Brushy Resources, Inc., ImPetro Operating, LLC, ImPetro Resources, LLC, the Lenders party thereto and T.R. Winston & Company, LLC acting as collateral agent (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K/A filed on October 26, 2016). |
| 10.26† | Employment Agreement with Joseph C. Daches, dated as of January 23, 2017 (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 25, 2017). |
| 10.27† | Employment Agreement with Brennan Short, dated as of January 27, 2017 (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 31, 2017). |
| 10.28† | Employment Agreement with Seth Blackwell, dated as of December 1, 2016 (incorporated herein by reference to Exhibit 10.28 to the Company’s Annual Report on Form 10-K filed on March 3, 2017). |
| 10.29† | Separation and Release Agreement, dated February 13, 2017, between Kevin Nanke and Lilis Energy, Inc. (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 17, 2017). |
| 10.30 | Securities Subscription Agreement, dated February 28, 2017, by and among the Company and the Purchasers thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on March 2, 2017). |
| 10.31 | Registration Rights Agreement, dated February 28, 2017, by and among the Company and the Purchasers thereto (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on March 2, 2017). |
| 10.32† | First Amendment to Employment Agreement with Abraham Mirman, dated as of March 9, 2017 (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on March 10, 2017). |
| 10.33† | First Amendment to Employment Agreement with Ronald D. Ormand, dated as of March 9, 2017 (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on March 10, 2017). |
| 10.34† | First Amendment to Employment Agreement with Ariella Fuchs, dated as of March 9, 2017 (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on March 10, 2017). |
| 10.35 | First Amendment to Credit and Guarantee Agreement, dated April 24, 2017 by and among Lilis Energy, Inc., Brushy Resources, Inc., ImPetro Operating, LLC, ImPetro Resources, LLC, the Lenders party thereto and T.R. Winston & Company, LLC acting as collateral agent (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed April 27, 2017). |
| 10.36 | Second Amendment to Credit and Guarantee Agreement, dated April 26, 2017 by and among Lilis Energy, Inc., Brushy Resources, Inc., ImPetro Operating, LLC, ImPetro Resources, LLC, the Lenders party thereto and T.R. Winston & Company, LLC acting as collateral agent (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed April 27, 2017). |
| 10.37 | Credit Agreement, dated April 26, 2017 by and among Lilis Energy, Inc., the Guarantors party thereto, the Lenders party thereto and Wilmington Trust, National Association acting as administrative agent (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed April 27, 2017). |
| 10.38 | Registration Rights Agreement, dated April 26, 2017 by and among the Lender party thereto (incorporated herein by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed April 27, 2017). |
| 10.39 | Series B 6.0% Convertible Preferred Stock Conversion Agreement, dated April 25, 2017, by and among the Holders party thereto (incorporated herein by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K filed April 27, 2017). |
| 10.41† | Second Amendment to Employment Agreement with Abraham Mirman, dated as of May 5, 2017 (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 8, 2017) | |
| 10.42† | First Amendment to Employment Agreement with Joseph Daches, dated as of May 5, 2017 (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on May 8, 2017) | |
| 10.43† | Second Amendment to Employment Agreement with Ariella Fuchs, dated as of May 5, 2017 (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on May 8, 2017) |
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| 21.1 | List of Subsidiaries of the Company (incorporated herein by reference to Exhibit 21.1 to the Company’s Annual Report on Form 10-K filed on March 3, 2017). |
| 23.1* | Consent of Marcum LLP, for the Company. |
| 23.2* | Consent of Marcum LLP, for Brushy Resources, Inc. |
| 23.3* | Consent of KPMG, LLP for Brushy Resources, Inc. |
| 23.4* | Consent of Cawley, Gillespie & Associates, Inc., independent petroleum engineers for the Company. |
| 23.5* | Consent of Fennemore Craig, P.C. (included in the opinion filed as Exhibit 5.1). |
| 24.1* | Powers of Attorney (included on the signature page hereto). |
| 99.1 | Report of Cawley, Gillespie & Associates, Inc., dated January 12, 2016, for the Company (incorporated herein by reference to Exhibit 99.1 to the Company’s Annual Report on Form 10-K filed on March 3, 2017). |
| 101.INS* | XBRL Instance Document |
| 101.SCH* | XBRL Taxonomy Extension Schema Document |
| 101.CAL* | XBRL Taxonomy Extension Calculation Linkbase Document |
| 101.DEF* | XBRL Taxonomy Extension Definition Linkbase Document |
| 101.LAB* | XBRL Taxonomy Extension Label Linkbase Document |
| 101.PRE* | XBRL Taxonomy Extension Presentation Linkbase Document |
| * | Filed herewith. |
| † | Indicates management contract or compensatory plan. |
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