UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-Q

 

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

 

 For the quarterly period ended March 31, 2018

 

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

 

Commission file number: 001-35330

 

Lilis Energy, Inc.

(Name of registrant as specified in its charter)

 

Nevada   74-3231613

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

 

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

(Address of principal executive offices, including zip code)

 

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

 

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

  

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

 

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

 

Large accelerated filer ¨ Accelerated filer x Non-accelerated filer      ¨
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 13(a) of the Exchange Act. ¨

 

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

 

As of May 7, 2018, 60,436,927 shares of the registrant’s common stock were issued and outstanding.

 

 

 

 

 

 

Lilis Energy, Inc.

 

INDEX

 

PART I - FINANCIAL INFORMATION  
     
Item 1. Financial Statements (Unaudited)  
  Condensed Consolidated Balance Sheets as of March 31, 2018 and December 31, 2017 4
  Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2018 and 2017 5
  Condensed Consolidated Statement of Changes in Stockholders’ Equity (Deficit) for the Three Months Ended March 31, 2018 6
  Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2018 and 2017 7
  Notes to the Condensed Consolidated Financial Statements 8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations 30
Item 3. Quantitative and Qualitative Disclosures About Market Risk 35
Item 4. Controls and Procedures 36
     
PART II - OTHER INFORMATION  
     
Item 1. Legal Proceedings 37
Item 1A. Risk Factors 37
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 37
Item 4. Mine Safety Disclosures 37
Item 5. Other Information 37
Item 6.  Exhibits 38
     
SIGNATURES 39

 

2

 

 

Forward-Looking Statements

 

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. The statements contained in this report that are not historical facts are forward-looking statements that represent management’s beliefs and assumptions based on currently available information. Forward-looking statements include information concerning our possible or assumed future results of operations, business strategies, need for financing, competitive position, and potential growth opportunities. Our forward-looking statements do not consider the effects of future legislation or regulations. Forward-looking statements include all statements that are not historical facts and can be identified by the use of forward-looking terminology such as the words “believes,” “intends,” “may,” “should,” “anticipates,” “expects,” “could,” “plans,” “estimates,” “projects,” “targets,” or comparable terminology or by discussions of strategy or trends. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we cannot give any assurances that these expectations will prove to be correct. Such statements by their nature involve risks and uncertainties that could significantly affect expected results, and actual future results could differ materially from those described in such forward-looking statements.

 

Among the factors that could cause actual future results to differ materially are the risks and uncertainties discussed in this report and in our annual report on Form 10-K for the year ended December 31, 2017. Should our underlying assumptions prove incorrect or the consequences of the aforementioned risks worsen, actual results could differ materially from those expected. There may also be other risks and uncertainties that we are unable to predict at this time or that we do not now expect to have a material adverse impact on our business.

 

3

 

 

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements.

Lilis Energy, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

 

(In thousands, except share and per share data)   March 31,
2018
    December 31,
2017
 
    (Unaudited)        
ASSETS                
Current assets:                
Cash and cash equivalents   $ 35,634     $ 17,462  
Accounts receivables, net of allowance of $39, respectively     14,671       7,426  
Prepaid expenses and other current assets     428       584  
Total current assets     50,733       25,472  
Oil and natural gas properties, full cost method of accounting                
Unproved     165,751       101,771  
Proved     206,191       141,717  
Less: accumulated depreciation, depletion, amortization and impairment     (77,755 )     (73,183 )
Total oil and natural gas properties, net     294,187       170,305  
Other assets     364       167  
Total assets   $ 345,284     $ 195,944  
                 
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)                
Current liabilities:                
Accounts payable   $ 11,799     $ 10,488  
Accrued liabilities     28,454       13,857  
Dividends payable     1,652       -  
Derivative instruments     1,991       853  
Asset retirement obligations     742       226  
Current portion of long-term debt     7       11  
Total current liabilities     44,645       25,435  
Asset retirement obligations     691       726  
Long-term debt     151,068       127,794  
Derivative instruments     44,326       72,937  
Total liabilities     240,730       226,892  
Commitments and contingencies (Note 16)                
Redeemable Preferred Stock:                
Series C convertible preferred stock, $0.0001 par value; stated value of $1,000; 100,000 shares authorized, 100,000 issued and outstanding with a liquidation preference of $121,950 at March 31, 2018     97,506       -  
Stockholders’ equity (deficit):                
Common stock, $0.0001 par value per share; 150,000,000 shares authorized, 60,218,176 and 53,368,331 shares issued and outstanding as of March 31, 2018 and December 31, 2017, respectively, of which 68,798 are being held as treasury stock     6       5  
Additional paid-in capital     298,351       272,335  
Accumulated deficit     (291,042 )     (303,288 )
Treasury stock (68,798 shares at cost)     (267 )     -  
Total stockholders’ equity (deficit)     7,048       (30,948 )
Total liabilities and stockholders’ equity (deficit)   $ 345,284     $ 195,944  

 

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

 

4

 

 

Lilis Energy, Inc. and Subsidiaries

Condensed Consolidated Statements of Operations (Unaudited)

 

   Three Months Ended March 31, 
(In thousands, except share and per share data)  2018   2017 
Revenues:          
Oil sales  $12,589   $2,496 
Natural gas sales   890    501 
Natural gas liquid sales   916    86 
    14,395    3,083 
           
Operating expenses:          
Production costs   3,090    829 
Gathering, processing and transportation   462    99 
Production taxes   1,023    142 
General and administrative   10,464    9,162 
Depreciation, depletion, accretion and amortization   4,641    1,146 
Total operating expenses   19,680    11,378 
Operating loss   (5,285)   (8,295)
Other income (expense):          
Other income   1    8 
Loss from commodity derivatives, net   (1,769)   - 
Gain from fair value changes of debt conversion and warrant derivatives   28,388    346 
Loss from fair value changes of conditionally redeemable 6% preferred stock   -    (41)
Interest expense   (9,089)   (774)
Total other income (expense)   17,531    (461)
Net income (loss) before income taxes   12,246    (8,756)
Income tax expense   -    - 
Net income (loss)   12,246    (8,756)
Less:          
Dividends on redeemable preferred stock   -    (30)
Dividends and deemed dividends on Series B convertible preferred stock   -    (213)
Dividends on Series C convertible preferred stock   (1,652)   - 
Net income (loss)  $10,594   $(8,999)
Less:  net income attributable to participating Series C preferred stockholders   (2,819)   - 
Net income (loss) attributable to common stockholders  $7,775   $(8,999)
           
Net income (loss) per common share-basic and diluted: (Note 13)          
   Basic  $0.14   $(0.32)
   Diluted  $(0.17)  $(0.32)
           
Weighted average common shares outstanding:          
   Basic   54,702,617    27,847,651 
   Diluted   78,502,197    27,847,651 

 

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

 

5

 

 

Lilis Energy, Inc. and Subsidiaries

Condensed Consolidated Statements of Changes in Stockholders’ Equity (Deficit)

(in thousands, except share data)

(Unaudited)

 

   Common Shares  

Additional

Paid In

   Treasury   Accumulated     
   Shares   Amount   Capital   Stock   Deficit   Total 
                         
Balance, December 31, 2017   53,368,331   $5   $272,335   $-   $(303,288)  $(30,948)
Stock based compensation   -    -    3,031    -    -    3,031 
Common stock for restricted stock   7,860    -    -    -    -    - 
Common stock withheld for taxes on stock-based compensation   (103,837)   -    (378)   -    -    (378)
Common stock for acquisition of oil and gas properties   6,940,722    1    24,777    -    -    24,778 
Reclassification of warrant derivative liabilities   -    -    223    -    -    223 
Purchase of treasury stock   (68,798)   -    -    (267)   -    (267)
Common stock for exercise of stock options   5,100    -    15    -    -    15 
Dividends on Series C convertible preferred stock   -    -    (1,652)   -    -    (1,652)
Net income   -    -    -    -    12,246    12,246 
Balance, March 31, 2018   (60,149,378)  $6   $298,351   $(267)  $(291,042)  $7,048 

 

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

 

6

 

 

Lilis Energy, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (Unaudited)

 

   Three Months Ended March 31, 
(In thousands)  2018   2017 
Cash flows from operating activities:          
Net income (loss)  $12,246   $(8,756)
Adjustments to reconcile net loss to net cash used in operating activities:          
Stock based compensation   3,031    2,779 
Amortization of debt issuance cost and debt discount   4,459    242 
Payable in-kind interest   3,168    - 
Loss from commodity derivatives, net   1,769    - 
Net cash settlement paid for commodity derivative contracts   (515)   - 
Gain in fair value of debt conversion and warrant derivatives   (28,388)   (346)
Loss in fair value of conditionally redeemable 6% preferred stock   -    41 
Depreciation, depletion, amortization and accretion of asset retirement obligation   4,641    1,146 
Changes in operating assets and liabilities:          
Accounts receivable   (7,245)   (3,671)
Prepaid expenses and other assets   76    (216)
Accounts payable and accrued liabilities   2,700    3,527 
Net cash used in operating activities   (4,058)   (5,254)
           
Cash flows from investing activities:          
Net proceeds from sale of DJ Basin properties   -    1,082 
Acquisition of oil and natural gas properties   (51,718)   - 
Capital expenditures   (38,571)   (11,360)
Net cash used in investing activities   (90,289)   (10,278)
           
Cash flows from financing activities:          
Proceeds from issuance of Series C Preferred Stock   100,000    - 
Proceeds from private placement, net of financing costs   -    19,454 
Equity financing costs   (2,494)   (1,600)
Proceeds from exercise of accordion feature of the First Lien Term Loan   -    7,100 
Proceeds from issuance of Riverstone Term Loans   50,000    - 
Debt issuance costs   (2,546)   (394)
Repayment of debt   (31,811)   (4)
Repurchase of common stock   (267)   - 
Proceeds from exercise of warrants and stock options   15    299 
Payment for tax withholding on stock-based compensation   (378)   - 
Net cash provided by financing activities   112,519    24,855 
Net increase in cash, cash equivalents and restricted cash   18,172    9,323 
Cash, cash equivalents and restricted cash at beginning of period   17,462    11,738 
Cash, cash equivalents and restricted cash at end of period  $35,634   $21,061 
Supplemental disclosure:          
Cash paid for interest  $1,461   $926 

  

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

 

7

 

 

Lilis Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

(Unaudited)

 

NOTE 1 - ORGANIZATION

  

Lilis Energy, Inc. (“Lilis”, “Lilis Energy” and the “Company”) is an independent oil and natural gas exploration and production company focused on the Delaware Basin in Winkler, Loving, and Reeves Counties, Texas and Lea County, New Mexico.

 

NOTE 2 - 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 which includes Brushy Resources, ImPetro Operating, LLC (“ImPetro Operating”), ImPetro Resources, LLC (“ImPetro”), Lilis Operating Company, LLC (“Lilis Operating”), and Hurricane Resources LLC (“Hurricane”). All significant intercompany accounts and transactions have been eliminated in consolidation.

   

Use of Estimates

 

The accompanying consolidated financial statements are prepared in conformity with generally accepted accounting principles in the United States (“U.S. GAAP”) which 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 natural gas liquid (“NGL”) reserves used in calculating depletion and assessing impairment of its oil and natural gas properties. The most significant estimates pertain to the evaluation of unproved properties for impairment, proved oil and natural gas reserves and related cash flow estimates used in the depletion and impairment of oil and natural gas properties, the timing and amount of transfers of our unevaluated properties into our amortizable full cost pool, the fair value of embedded derivatives and commodity derivative contracts, accrued oil and natural gas revenues and expenses valuation of options and warrants, inducement transactions and common stock, and the allocation of general administrative expenses. Actual results could differ significantly from these estimates.

 

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. Following reclassifications have been made to the three months ended March 31, 2017: (i) the income from operator’s overhead recovery of approximately $0.15 million has been reclassified from revenue to operating expense as an offset against general and administrative expenses in the consolidated statement of operations; and (ii) $0.6 million of the escrow on a drilling rig has been reclassified from investing activities to cash, cash equivalents and restricted cash in the consolidated statement of cash flows.

 

Recently Adopted Accounting Standards

 

On January 1, 2018, the Company adopted the new accounting standard, ASC 606, Revenue from Contracts with Customers and all the related amendments (the “New Revenue Standard”) using the modified retrospective method. In accordance with the modified retrospective method, comparative information is not restated and continues to be reported under the accounting standards in effect for those periods. The cumulative effect of initially adopting the New Revenue Standard, if any, is recorded as an adjustment to the opening balance of retained earnings. The Company’s revenues from customers is derived from production and sales of crude oil, natural gas and natural gas liquids and recognized when control is transferred to the customer. As operator, the Company may market production on behalf of joint interest partners and various royalty owners. Under the terms of our joint operating agreements, the Company does not take control of the production attributable to our joint interest partners and the various royalty and consequently, the Company recognizes revenues only for our share of the production. In accordance with the New Revenue Standard requirements, the impact of adoption on our condensed consolidated statement of operations and condensed balance sheet was as follows:

 

8

 

 

For three months ended March 31, 2018  As Reported   Balances
without
Adoption of
ASC 606
   Increase
(decrease)
 
Consolidated Statements of Operations:               
Revenues  $14,395   $14,445   $(50)
Operating expenses  $(462)  $(512)  $50 
As of March 31, 2018               
Consolidated Balance Sheets:               
Accounts receivable  $7,886   $7,936   $(50)
Accrued liabilities  $(115)  $(165)  $(50)

  

As shown in this comparison table, there is no net bottom line impact from the ASC 606 adoption and, therefore, no adjustment to the opening balance of retained earnings. Prior to the adoption of ASC 606, the revenue line included the value of our natural gas gatherer’s contractual volume retainage fee, with an offsetting cost included in the gathering, processing and marketing costs line. In accordance with ASC 606 the Company will only recognize revenues for our share of the production, resulting in removal of the retainage fee totaled approximately $50,000 from both revenues and operating expenses during the three months ended March 31, 2018.

 

On July 13, 2017, the Financial Accounting Standards Board (“FASB”) issued a two-part ASU 2017-11, (Part I) Accounting for Certain Financial Instruments with Down Round Features, (Part II) Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Redeemable Noncontrolling Interests with a Scope Exception. Part I of the ASU simplifies the accounting for certain financial instruments with down round features by requiring companies to disregard the down round feature when assessing whether the instrument is indexed to its own stock, for purposes of determining liability or equity classification. Companies that provide earnings per share (EPS) data will adjust their basic EPS calculation for the effect of the feature when triggered (that is, when the exercise price of the related equity-linked financial instrument is adjusted downward because of the down round feature) and will also recognize the effect of the trigger within equity. Part II of the ASU is not applicable to the Company since it addresses concerns relating to an indefinite deferral available to private companies with mandatorily redeemable financial instruments and certain noncontrolling interests. The provisions of this new ASU related to down rounds are effective for public business entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. Early adoption is permitted for all organizations. The Company elected to adopt this ASU on January 1, 2018. The Company’s SOS Warrant Liability (as described in Note 6) was account for as a derivative instrument solely because of its down round feature. Any outstanding SOS Warrants as of the date of adoption was reclassified to equity and the Company will no longer recognize any gain or loss based on the fair value of the SOS warrants. No other derivatives instruments outstanding as of January 1, 2018 were affected by the adoption of this ASU.

 

On January 5, 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, 2018. On March 15, 2018, the Company completed an acquisition of proved and unproved properties from OneEnergy Partners, LLC (“OEP”) (See Note 5-Acquisitions and Divestitures). As a result of the adoption of ASU 2017-01, the company accounted for the acquisition as an asset purchase instead of a business combination. As a result, acquisition costs of approximately $1.1 million were capitalized as part of the acquisition and the purchase price was allocated to unproved and proved properties based on relative fair value.

 

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 25, 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 natural gas leases are scoped out of the new ASU. As of December 31, 2017, the Company currently has only one operating lease within the scope of this standard that expires in less than 2 years. The Company is currently gathering all lease agreements to evaluate the impact that this ASU would have on the Company’s consolidated financial statements. The Company anticipates that the adoption of ASU 2016-02 will likely increase the Company’s recorded assets and liabilities, increase its depreciation, depletion and amortization expense, increase interest expense and decrease rent expense. As of March 31, 2018, the Company has not yet determined the aggregate amount of change expected for each category.

 

Accrued Liabilities

 

At March 31, 2018 and December 31, 2017, the Company’s accrued liabilities consisted of the following:

 

  

March 31,

2018

   December 31,
2017
 
   ($ in thousands) 
Accrued bonus  $1,234   $3,000 
Accrued drilling costs   15,445    3,615 
Revenue payable   6,380    6,460 
Other accrued liabilities   5,395    782 
   $28,454   $13,857 

 

NOTE 3 – REVENUE

 

Revenue is recognized when control passes to the purchaser which generally occurs when production is transferred to the purchaser. Revenue is measured as the amount of consideration we expect to receive in exchange for the commodities transferred. All of the Company’s revenues from contracts with customers represent products transferred at a point in time as control is transferred to the customer.

 

Revenue is recorded based on consideration specified in the customer’s contract. The amounts collected on behalf of third parties are recorded in revenue payable. The Company recognizes revenue in the amount that reflects the consideration it expects to be entitled in exchange for transferring control of those goods to the customer. The contract consideration in the Company’s variable price contracts are typically allocated to specific performance obligations in the contract according to the price stated in the contract. Payment is generally received one or two months after the sale has occurred.

 

10

 

 

Crude oil revenues

 

Crude oil from our operated properties is produced and stored in field tanks. The Company recognizes crude oil revenue when control passes to the purchaser. Crude oil is sold under a single short-term contract which converted to a month-to-month contract on April 30, 2018. The contract is cancellable on 30 days’ notice. The purchaser’s commitment includes all quantities of crude oil from the leases that are covered by the contract, with no quantity-based restrictions or variable terms. Pricing is based on posted field prices for crude oil of similar quality, less a differential. The differential is subject to negotiation and is currently $2.50 per barrel. Posted field prices reset on a daily basis and generally track quoted market prices for West Texas Intermediate crude oil.

 

Natural gas and NGL revenues

 

Natural gas is produced and transported via pipelines to gas processing facilities. NGLs are extracted from the natural gas at the processing facilities and processed natural gas and NGLs are marketed and sold separately on the Company’s behalf after processing. All of our operated natural gas production is sold under one of three natural gas contracts which are long-term in nature but one contract includes 30 day cancelation provisions which we classify as short-term. The processor’s commitment to sell on the Company’s behalf includes all quantities of natural gas and NGL produced on specific wellbores or dedicated acreage as defined in the contract, with no quantity-based restrictions or variable terms. The gas contracts are generally market based pricing less adjustments for transportation and processing fees. A portion of natural gas delivered to the processing plants is used as fuel at the processing plant without reimbursement. We recognize revenue for natural gas and NGLs when control passes at the tailgate of the processing plant.

 

Gathering, processing and transportation

 

Natural gas must be transported to a gas processing plant facility for treating and to extract NGLs, then the final residue gas and liquid products are marketed for sale to end users at the tailgate of the plant. These activities incur costs that are contractually passed to us from the gatherer per customary industry practice. Such costs include fees for gathering the gas and moving it from wellhead to plant inlet, plant electricity usage, inlet compression, carbon dioxide and hydrogen sulfide treatments, processing tax, fuel usage, and marketing at the tailgate. Gathering, process and marketing costs are presented as operating expenses in the condensed consolidated statement of operations.

 

Imbalances

 

Natural gas imbalances occur when the Company sells more or less than its entitled ownership percentage of total natural gas production. Any amount received in excess of its share is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable. The Company did not have any significant natural gas imbalance positions as of December 31, 2017 and 2016.

 

Contract balances and Prior Period Performance Obligations

 

The Company is entitled to payment from purchasers once its performance obligations have been satisfied upon delivery of the product, at which point payment is unconditional, and the Company records these invoiced amounts as Accounts receivable in its consolidated balance sheet.

 

To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and also recorded as Accounts receivable in the accompanying consolidated balance sheets. In this scenario, payment is also unconditional, as the Company has satisfied its performance obligations through delivery of the relevant product. As a result, the Company has concluded that its product sales do not give rise to contract assets or liabilities under ASC 606.

 

The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and NGL sales may not be received for 30 to 60 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production that was delivered to the customer and the price that will be received for the sale of the product. Additionally, to the extent actual volumes and prices of oil, natural gas and NGLs are unavailable for a given reporting period because of timing or information not received from third party purchasers, the expected sales volumes and prices for those barrels of oil, cubic feet of gas and gallons of NGL are also estimated.

 

11

 

 

The Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls in place for its estimation process, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the three months ended March 31, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

 

Significant Judgements

 

The Company engages in various types of transactions in which midstream entities process its gas and subsequently market resulting NGLs and residue gas to third-party customers on the Company's behalf gas purchase contracts. These types of transactions require judgment to determine whether the Company is the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net. We maintain control of the natural gas and NGLs during processing and consider ourselves principals in these arrangements.

 

Practical Expedients

 

A significant number of the Company's product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient in ASC 606 that exempts it from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

 

For the Company's product sales that have a contract term greater than one year, the Company has utilized the practical expedient in ASC 606 that states that it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

 

The following table disaggregates our revenue by contract type (in thousands):

  

   Short term contract   Long-term contracts   Total 
Crude oil  $12,589    -   $12,589 
Natural gas   438    452    890 
NGLs   450    466    916 
                

  

NOTE 4 - OIL AND NATURAL GAS PROPERTIES

 

The Company uses the full cost method of accounting for oil and natural 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.

  

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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 natural 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.

 

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 sum of the present value, discounted at 10%, of estimated future net revenues from proved oil and natural 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. 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 natural 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 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 carrying value of an asset may no longer be appropriate. 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 the full cost pool which is subject to depletions.

 

The following table sets forth a summary of oil and natural gas property costs (net of divestitures) not being amortized at March 31, 2018 and December 31, 2017:

 

   March 31,   December 31, 
   2018   2017 
   (In thousands) 
Unproved unevaluated acreage:          
Beginning balance  $101,771   $24,461 
Lease purchases   75,085    78,110 
Transfer and other reclassification to proved properties   (11,105)   (800)
Total unproved acreage  $165,751   $101,771 
           
Wells in progress:          
Beginning balance  $-   $7,453 
Additions   733    - 
Reclassification to evaluated properties   -    (7,453)
Total wells in progress not subject to DD&A  $733   $- 

 

At March 31, 2018, the Company completed an assessment of its inventory of unproved acreage for impairment which resulted in $11.1 million being transferred from unproved properties to proved properties in the full cost pool due to defective titles on certain leases. During the three months ended March 31, 2017, no impairment was recorded on the Company’s unproved oil and natural gas properties. 

 

Depreciation, depletion and amortization expense related to proved properties was approximately $4.6 million and $1.1 million for the three months ended March 31, 2018 and 2017, respectively.

 

13

 

 

NOTE 5 – ACQUISITIONS AND DIVESTITURES

 

OEP Acquisition

 

On January 30, 2018, the Company entered into a Purchase and Sale Agreement (the “Purchase and Sale Agreement”) by and between the Company and OneEnergy Partners Operating, LLC (“OEP”), pursuant to which the Company agreed to purchase from OEP, and OEP agreed to sell to the Company, certain oil and natural gas properties and related assets for a purchase price of $70 million, subject to customary purchase price adjustments (the “OEP Acquisition”). The properties acquired by the Company pursuant to the Purchase and Sale Agreement consists of leasehold acreage in the Delaware Basin in Lea County, New Mexico. On March 15, 2018, the Company completed the OEP Acquisition whereby the Company paid $40.0 million in cash and issued 6,940,722 shares of the Company’s common stock valued at approximately $24.9 million for a total purchase price of approximately $64.9 million, before acquisition costs and customary purchase price adjustments. The value of the shares issued was determined using the closing price of the company’s stock on the date of closing.

 

The OEP Acquisition was accounted for as an asset purchase of proved properties and unproved properties using relative fair value of the assets acquired. The proved producing properties were valued based on internal estimates of future production using strip pricing and the present value discounted at 10%. Unproved properties acquired were valued using a market approach.

 

The purchase price and the value of the assets acquired was as follows:

 

(in thousands, except per share amount)    
Cash  $40,000 
Common stock issued (6,940,722 shares at $3.57)   24,778 
Transaction costs and purchase price adjustments   1,074 
Total purchase price  $65,852 
      
Proved properties  $4,168 
Unproved properties   61,684 
   $65,852 

 

VPD Acquisition

 

On February 28, 2018, the Company completed the acquisition of certain leasehold interests and other oil and gas assets in Loving and Winkler Counties, Texas from VPD Texas, L.P. for cash consideration of $10.6 million plus $0.5 million of related acquisition costs. The acquisition was recorded at fair value which was the total cash consideration of approximately $11.1 million. VPD is an affiliate of Värde Partners, Inc. (“Värde”). Värde participated as lead lender in the Company’s Second Lien Term Loan transaction in 2017 and as investor of the Company’s Series C Preferred Stock transaction in January 2018. As a result, the VPD acquisition is considered a related party transaction. See Note 10 - Related Party Transactions.

 

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The purchase price and the value of the assets acquired was as follows:

 

(in thousands, except per share amount)     
Cash purchase price  $10,611 
      
Proved properties  $3,185 
Unproved properties   7,426 
   $10,611 

 

KEW Acquisition

 

As of December 31, 2017, the Company completed the acquisition of unproved acreage in Winkler County, Texas from KEW Drilling, a Delaware limited partnership (“KEW”) for cash consideration of $48.9 million plus $0.8 million of related acquisition costs. The acquisition was recorded at fair value which was the total cash consideration of approximately $49.7 million.

 

DJ Basin Properties Divestiture

 

On March 31, 2017, the Company entered into a purchase and sale agreement with Nanke Energy LLC for the divestiture of all of its oil and natural gas properties located in the Denver-Julesburg Basin (the “DJ Basin”) for consideration of $2 million, subject to customary post-closing purchase price adjustments. The sale of the Company’s 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 the Company’s full cost pool with no gain or loss recognized. The DJ Basin assets were sold to an entity owned by the Company’s former chief financial officer and therefore the divestiture is considered a related party transaction. See Note10 - 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.

  

NOTE 6 - FAIR VALUE OF FINANCIAL INSTRUMENTS

 

The Company measures the 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.

 

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The determination of the fair values of our derivative contracts incorporates various factors, which include not only the impact of our non-performance risk on our liabilities but also the credit standing of the counterparties involved. The Company utilizes counterparty rate of default values to assess the impact of non- performance risk when evaluating both our liabilities to, and receivables from, counterparties.

 

Recurring Fair Value Measurements

 

   Fair Value Measurement Classification     
   Quoted Prices in
Active Markets for
Identical Assets or
Liabilities
   Significant
Other
Observable
Inputs
   Significant
Unobservable
Inputs
     
   (Level 1)   (Level 2)   (Level 3)   Total 
   (in thousands) 
As of March 31, 2018                    
Oil and natural gas derivative swap contracts  $      -   $(1,938)  $-   $(1,938)
Oil and natural gas derivative collar contracts   -    (53)   -    (53)
Second Lien Term Loan conversion features   -    -    (44,326)   (44,326)
Total  $-   $(1,991)  $(44,326)  $(46,317)
As of December 31, 2017                    
Oil and natural gas derivative swap contracts  $-   $(706)  $-   $(706)
Oil and natural gas derivative collar contracts   -    (147)   -    (147)
Warrant liabilities   -    -    (223)   (223)
Second Lien Term Loan conversion features   -    -    (72,714)   (72,714)
Total  $-   $(853)  $(72,937)  $(73,790)

 

The Company’s derivative liability associated with the Second Lien Term Loan and warrants are measured using Level 3 inputs as follows:

 

Second Lien Term Loan Conversion Features: Under the terms of the Company’s second lien credit agreement, dated as of April 26, 2017, by and among the Company, certain subsidiaries of the Company, as guarantors (the “Guarantors”), Wilmington Trust, National Association, as administrative agent (the “Agent”), and the lenders party thereto (the “Lenders”), including Värde Partners, Inc., as lead lender (the “Lead Lender”), as amended (the “Second Lien Credit Agreement”), the Lead Lender has the option to convert 70% of the principal amount of each tranche of the Second Lien Term Loan (the “Loan”) under the Second Lien Credit Agreement, together with accrued paid-in-kind interest and the make-whole premium on such principal amount (together, the “Conversion Sum”), into shares of common stock. The make-whole premium is the cash amount representing the excess of (a) the present value at such repayment, prepayment or acceleration date or the date the obligations otherwise become due and payable in full of (1) the sum of the principal amount repaid, prepaid or accelerated plus (2) the interest accruing on such principal amount from the date of such repayment, prepayment or acceleration through the maturity date (excluding accrued but unpaid paid-in-kind interest to the date of such repayment, prepayment or acceleration), such present value to be computed using a discount rate equal to the Treasury Rate plus 50 basis points discounted to the repayment, prepayment or acceleration date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months), over (b) the principal amount of the Loan repaid, prepaid or accelerated. The number of shares issued will be based on the division of 70% of the Conversion Sum by the conversion price then in effect.

 

16

 

 

The Company also has the option to cause the Loan to convert if, at the time of exercise of the Company’s conversion option, the closing price of the Company’s common stock has been at least 150% of the Conversion Price (as defined below) then in effect for at least 20 of the 30 immediately preceding trading days. The features of the make-whole premium in the Loan require the conversion features to be recorded as embedded derivatives and bifurcated from its host contracts, the Loan, and accounted for separately from the debt. The conversion features contained in the Loan are recorded as a derivative liability at fair value each reporting period based upon values determined through the use of discounted lattice models of the Loan under the Second Lien Credit Agreement. Change in fair value is accounted for in the consolidated statement operations. As of December 31, 2017, the fair value of the embedded derivative under the Second Lien Credit Agreement associated with the Loan conversion features was a liability of approximately $72.7 million. As of March 31, 2018, the fair value of the embedded derivative liability was $44.3 million. As a result, the Company recorded an unrealized gain of $28.4 million on the change in fair value of derivative liabilities associated with the Loan conversion features.

 

The fair value of the holder conversion features was determined using a binomial lattice model based on certain assumptions including (i) the Company’s stock price, (ii) risk-free rate, (iii) expected volatility, (iv) the Company’s implied credit rating, and (v) the implied credit yield of the Loan.

 

SOS Warrant Liability. On June 23, 2016, in conjunction with the merger with Brushy in June 2016, the Company issued to SOS a warrant to purchase up to 200,000 shares of the Company’s common stock at an exercise price of $25.00. The warrant contains a price protection 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. As of December 31, 2017, the fair value of the SOS warrant liability was approximately $0.2 million. As a result of the Company’s early adoption of ASU 2017-11, “Accounting for Financial Instruments with Down Round Features” on January 1, 2018, the $0.2 million on the SOS warrants were reclassified from current liabilities to stockholders’ equity at January 1, 2018. During the three months ended March 31, 2017, the Company recorded an unrealized gain of approximately $0.3 million on the SOS warrant liability.

 

NOTE 7 - ASSET RETIREMENT OBLIGATIONS (ARO)

 

The Company’s ARO represent the present value of the estimated cash flows expected to be incurred to plug, abandon and remediate producing properties, excluding salvage values, at the end of their productive lives in accordance with applicable laws. Revisions in estimated liabilities during the period relate primarily to changes in estimates of asset retirement costs. Revisions in estimated liabilities can also include, but are not limited to, revisions of estimated inflation rates, changes in property lives and expected timing of settlement.

 

The following table summarizes the changes in the Company’s asset retirement obligations for the three months ended March 31, 2018 and the year ended December 31, 2017: 

 

  

Three Months Ended

March 31, 2018

 
   (In thousands)  
ARO, beginning of period  $952 
Additional liabilities incurred   225 
Accretion expense   56 
Liabilities settled   - 
Revision in estimates   200 
    1,433 
Less: current portion of ARO   (742)
ARO, end of period  $691 

 

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NOTE 8 - DERIVATIVES

 

As discussed in Note 6, the Second Lien Term Loan contains conversion features that are exercisable at the option of the Lead Lender or the Company. The conversion features have been identified as embedded derivatives which (i) contain economic characteristics that are not clearly and closely related to the host contract, the Second Lien Term Loan, and (ii) separate, stand-alone instruments with similar terms would qualify as derivative instruments. As such, the conversion features were bifurcated and accounted for separately from the Second Lien Term Loan. The conversion features are recorded at fair value for each reporting period with changes in fair value included in the consolidated statement of operations for each reporting period. As of March 31, 2018 and December 31, 2017, the fair value of the derivative liability was approximately $44.3 million and $72.7 million, respectively. As a result, the Company recognized unrealized gain of approximately $28.4 million in its consolidated statement of operations for the three months ended March 31, 2018. There were no derivative liabilities associated with convertible debt instruments for the three months ended March 31, 2017.

 

To reduce the impact of fluctuations in oil and natural gas prices on the Company’s revenues, or to protect the economics of property acquisitions, the Company periodically enters into derivative contracts with respect to a portion of its projected oil and natural gas production through various transactions that fix or modify the future prices to be realized. The derivative contracts may include fixed-for-floating price swaps (whereby, on the settlement date, the Company will receive or pay an amount based on the difference between a pre-determined fixed price and a variable market price for a notional quantity of production), put options (whereby the Company pays a cash premium in order to establish a fixed floor price for a notional quantity of production and, on the settlement date, receives the excess, if any, of the fixed price floor over a variable market price), and costless collars (whereby, on the settlement date, the Company receives the excess, if any, of a variable market price over a fixed floor price up to a fixed ceiling price for a notional quantity of production).

  

These hedging activities, which are governed by the terms of our Second Lien Credit Agreement, are intended to support oil and natural gas prices at targeted levels and manage exposure to oil and natural gas price fluctuations. It is our policy to enter into derivative contracts only with counterparties that are creditworthy and competitive market makers. All of our derivatives are with non-lender counterparties and are designated as unsecured. Certain of our derivative counterparties may require the posting of cash collateral under certain conditions. It is never the Company’s intention to enter into derivative contracts for speculative trading purposes.

 

All of our derivatives are accounted for as mark-to-market activities. Under ASC Topic 815, “Derivatives and Hedging,” these instruments are recorded on the consolidated balance sheets at fair value as either short term or long-term assets or liabilities based on their anticipated settlement date. The Company nets derivative assets and liabilities by commodity for counterparties where a legal right to such offset exists. Changes in the derivatives’ fair values are recognized in current earnings since the Company has elected not to designate its current derivative contracts as cash flow hedges for accounting purposes.

  

The following table presents the volumes associated with the Company’s outstanding oil derivative contracts expiring during the nine months ending December 31, 2018 and the weighted average oil prices for those contracts:

 

18

 

 

  

April 1 –

December 31, 2018

  

January 1 –

December 31, 2019

 
Oil positions:          
Fixed-for-floating price swaps (NYMEX WTI):          
Notional Volume (Bbls/Day)   1,258    - 
Weighted average strike price ($/Bbl)  $56.65   $- 
           
Put Options (NYMEX WTI):          
Notional Volume (Bbls/Day)   1,490    500 
Weighted average strike price ($/Bbl)  $55.69   $50.00 
           
Call Options (NYMEX WTI):          
Notional Volume (Bbls/Day)   1,490    500 
Weighted average strike price ($/Bbl)  $64.16   $68.10 

 

   Three Months Ended
March 31, 2018
   Year Ended
December 31, 2017
 
   (in thousands) 
Beginning fair value of commodity derivatives  $(853)  $- 
Change in fair value of derivative instruments   (1,769)   (1,063)
Net settlements paid on crude oil derivative contracts   515    96 
Change in settlements accrued on crude oil derivative contracts   122    114 
Ending fair value of commodity derivatives, net  $(1,985)  $(853)

     

The following information summarizes the gross fair values of derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Company’s consolidated balance sheets:

  

   As of March 31, 2018 
   Gross Amount of
Recognized Assets
and Liabilities
   Gross Amounts
Offset in the
Consolidated
Balance Sheets
   Net Amounts
Presented in the
Consolidated
Balance Sheets
 
   (in thousands) 
Offsetting Derivative Assets:               
Current asset  $-   $    -   $- 
Long-term asset   6    -    6 
Total asset  $6   $-   $6 
Offsetting Derivative Liabilities:               
Current liability  $1,991   $-   $1,991 
Long-term liability   -    -    - 
Total liability  $1,991   $-   $1,991 

 

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   As of December 31, 2017 
   Gross Amount of
Recognized Assets
and Liabilities
   Gross Amounts
Offset in the
Consolidated
Balance Sheets
   Net Amounts
Presented in the
Consolidated
Balance Sheets
 
   (in thousands) 
Offsetting Derivative Assets:               
Current asset  $-   $    -   $- 
Long-term asset   -    -    - 
Total asset  $-   $-   $- 
Offsetting Derivative Liabilities:               
Current liability  $853   $-   $853 
Long-term liability   -    -    - 
Total liability  $853   $-   $853 

 

NOTE 9 – LONG-TERM DEBT

 

   March 31,   December 31, 
   2018   2017 
   (In thousands) 
Riverstone First Lien Loans associated with the Amended and Restated Senior Secured Term Loan Credit Agreement, due 2021, net of debt issuance costs and debt discount  $47,593   $- 
6% Bridge Loans associated with the amended First Lien Term Loan, due 2019, net of debt issuance costs   -    30,363 
8.25% Second Lien Term Loans, due 2021, net of debt issuance costs and debt discount   103,475    96,431 
6% note payable to SOS Investment, LLC, due 2019   -    1,000 
Other notes payable, due 2018   7    11 
Total long-term debt  $151,075   $127,805 
Less: current portion   (7)   (11)
Total long-term debt, net of current portion  $151,068   $127,794 

 

As of March 31, 2018 and December 31, 2017, the carrying amounts of the Term Loans were as follows: 

 

   Principal
Amount
   Paid-in-
kind
Interest
   Unamortized
Debt
Issuance
Costs & Debt
Discount
   Carrying
Amount
 
March 31, 2018:                    
Riverstone First Lien Loans associated with the Amended and Restated Senior Secured Term Loan Credit Agreement, due January 2021  $50,000   $-   $(2,407)  $47,593 
Second Lien Term Loans, due April 2021   150,000    8,920    (55,445)   103,475 
Total:  $200,000   $8,920   $(57,852)  $151,068 
                     
December 31, 2017:                    
Bridge Loans associated with the amended First Lien Term Loan, due September 2019  $30,000   $807   $(444)  $30,363 
Second Lien Term Loans, due April 2021   150,000    5,752    (59,321)   96,431 
Total:  $180,000   $6,559   $(59,765)  $126,794 

  

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Second Lien Credit Agreement

 

On April 26, 2017, the Company entered into the Second Lien Credit Agreement comprised of convertible loans in an aggregate initial principal amount of up to $125 million available in two separate 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 in delayed-draw term loans (the “Delayed Draw Term Loan” and, together with the Second Lien Term Loan, the “Second Lien Loans”) to be funded on or before February 28, 2019, at the request of the Company, subject to certain conditions, in a single draw or in multiple draws. Each tranche of Second Lien Loans will bear interest at a rate per annum of 8.25%, compounded quarterly in arrears and payable only in-kind by increasing the principal amount of the loan by the amount of the interest due on each interest payment date.

 

On October 3, 2017, the Company, certain subsidiaries of the Company, as guarantors (the “Guarantors”), Wilmington Trust, National Association, as administrative agent and the lenders party thereto, entered into Amendment No. 1 to the Second Lien Credit Agreement (“Amendment No. 1 to the Second Lien Credit Agreement”). The purpose of Amendment No. 1 to the Second Lien Credit Agreement is to waive certain conditions precedent to the drawing of the Delayed Draw Term Loan under the Second Lien Credit Agreement and to provide for the funding of such Delayed Draw Term Loan upon the signing of the lease acquisition agreement with KEW Drilling, a Delaware limited partnership. The Company borrowed the full $45.0 million of the availability under the Delayed Draw Term Loan on October 4, 2017.

 

On October 19, 2017, the Company entered into a second amendment to the Second Lien Credit Agreement (“Amendment No. 2 to the Second Lien Credit Agreement”), by and among the Company, the Guarantors, the Agent and the Lenders, including the Lead Lender. Amendment No. 2 to the Second Lien Credit Agreement permits the Company to incur the Incremental Bridge Loan under the First Lien Credit Agreement.

 

On November 10, 2017, the Company entered into a third amendment to the Second Lien Credit Agreement (“Amendment No. 3 to the Second Lien Credit Agreement”), by and among the Company, the Guarantors, the Agent and the Lenders, including the Lead Lender. Amendment No. 3 to the Second Lien Credit Agreement increased by $25.0 million the amount of delayed draw term loans available for borrowing under the Second Lien Credit Agreement. The additional $25.0 million of Delayed Draw Term Loan was drawn on November 10, 2017. The $25.0 million of proceeds from these loans may be used to fund oil and natural gas property acquisitions, subject to certain limitations, to fund drilling and completion costs or for other general corporate purposes.

 

On January 31, 2018, the Company entered into a fourth amendment to the Second Lien Credit Agreement, among the Company, the guarantors party thereto, the lenders party thereto, including Värde Partners, Inc., as lead lender, and Wilmington Trust, National Association, as administrative agent (“Amendment No. 4 to the Second Lien Credit Agreement”).

 

The purpose of Amendment No. 4 to the Second Lien Credit Agreement was to, among other matters:

  

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

 

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

 

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

  

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The Second Lien Loans are secured by second priority liens on substantially all of the Company’s and the Guarantors’ assets, including their oil and natural gas properties located in the Delaware Basin, and all of the obligations thereunder are unconditionally guaranteed by each of the Guarantors. The Second Lien 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 Loan. 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 make-whole premium in connection with any mandatory or voluntary prepayment of the Loans.

 

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

 

  · 70% of the principal amount of each tranche of Second Lien 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 certain customary adjustments, the “Conversion Price”); and

 

  · 30% of the principal amount of each tranche of Second Lien 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 Second Lien Loans, except that the Take Back Loans will not be convertible and will bear interest payable in cash at a rate of LIBOR plus 9% (subject to a 1% LIBOR floor).

 

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

  

The Second Lien Loans 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 Loans 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 Loans could be accelerated and be due and payable upon an event of default. As of March 31, 2018, the Company was in compliance with all restrictive covenants.

 

As discussed in Note 6, Fair Value of Financial Instruments, above and Note 8, Derivatives, below, the Company separately accounts for the embedded conversion features as a derivative instrument in accordance with accounting guidance relating to recording embedded derivatives at fair value. The initial fair value of the embedded derivatives is recorded as a debt discount to the convertible Second Lien Term Loan. The debt discount is amortized over the term of the Second Lien Loans using effective interest rate.

 

Riverstone First Lien Credit Agreement

 

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

 

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

 

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The Company used approximately $31.5 million of the proceeds of the Riverstone First Lien Loans to repay in full its obligations under and retire the First Lien Credit Agreement during the first quarter of 2018.

 

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

 

On February 20, 2018, the Company entered into the following amendments to its existing credit agreements (collectively, the “Amendments”): (i) Amendment No. 1 to the Riverstone First Lien Credit Agreement and (ii) Amendment No. 5 to the Second Lien Credit Agreement. Pursuant to the Amendments and a consent letter received from the Purchasers, in their capacity as the holders of all of the issued and outstanding shares of Series C Preferred Stock, the Company has been granted the right to repurchase shares of its Common Stock for an aggregate purchase price up to $10,000,000 (subject to certain exceptions and conditions).

 

The commencement of any repurchase of shares of Common Stock is subject to compliance with applicable law, Board approval, and market conditions

 

Interest Expense

 

The components of interest expense are as follows:

 

   Three Months Ended March 31, 
   2018   2017 
         
Interest on term loans  $1,457   $517 
Interest on notes payable   5    15 
Paid-in-kind interest on term loans   3,168    - 
Amortization of debt financing costs on term loans   618    127 
Amortization of discount on term loans   3,841    115 
Total:  $9,089   $774 

   

NOTE 10 - RELATED PARTY TRANSACTIONS

 

During the three months ended March 31, 2018 and 2017, the Company was engaged in the following transactions with a related party:

  

        Three Months Ended March 31,  
Related Party   Transactions   2018     2017  
        ($ in thousands)  
Directors and Officers:                    
Brennan Short (former Chief Operating Officer)   Consulting fees paid to MMZ Consulting, Inc. (“MMZ”) which is owned by Mr. Short.  Mr. Short is the sole member of MMZ.   $ -     $ 203  
    Total:   $ -     $ 203  
                     
Kevin Nanke (former Chief Financial Officer)   Purchased the DJ Basin properties from the Company through Nanke Energy, LLC   $ -     $ 2,000  
    Total:   $ -     $ 2,000  
                     
Värde Partners, Inc. (“Värde”)(1)   The Company acquired oil and natural gas interests from VPD, an affiliate of Värde   $ 10,611     $ -  
        $ 10,611     $ -  

   

(1) Värde is the lead lender in the Company’s Second Lien Loans (see Note 9 – Long-term Debts) and also participated in the issuance of Series C 9.75% Convertible Preferred Stock in January 2018 (see Note 11 – Shareholders’ Equity and Redeemable Preferred Stock).

  

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NOTE 11 - SHAREHOLDERS’ EQUITY AND REDEEMABLE PREFERRED STOCK

 

Preferred Stock Issuance

 

On January 30, 2018, the Company entered into a Securities Purchase Agreement (the “Securities Purchase Agreement”) by and among the Company and certain private funds affiliated with Värde Partners, Inc. (the “Purchasers”), pursuant to which the Company agreed to issue and sell to the Purchasers, and the Purchasers agreed to purchase from the Company, 100,000 shares of a newly created series of preferred stock of the Company, designated as “Series C 9.75% Convertible Participating Preferred Stock”(the Series C Preferred Stock”), for a purchase price of $1,000 per share, or an aggregate of $100,000,000. Värde Partners, Inc. is the lead lender, and certain private funds affiliated with Värde Partners, Inc. are lenders, under the Company’s Second Lien Credit Agreement (as defined above in Note 9 – Long Term Debt).

 

Closing of the issuance and sale of the shares of Series C Preferred Stock pursuant to the Securities Purchase Agreement occurred on January 31, 2018.

 

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

 

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

 

Dividends. Holders of shares of Series C Preferred Stock will be entitled to receive cumulative preferential dividends, payable and compounded quarterly in arrears on January 1, April 1, July 1 and October 1 of each year, commencing April 1, 2018, at an annual rate of 9.75% of the Stated Value until April 26, 2021, after which the annual dividend rate will increase to 12.00% if paid in full in cash or 15.00% if not paid in full in cash. Dividends are payable, at the Company’s option, (i) in cash, (ii) in kind by increasing the Stated Value by the amount per share of the dividend or (iii) in a combination thereof. The Company expects to pay dividends-in-kind for the foreseeable future. In addition to these preferential dividends, holders of shares of Series C Preferred Stock will be entitled to participate in any dividends paid on the Common Stock on an as-converted basis. As of March 31, 2018, the Company had $1.7 million of dividends in arrears on the Series C Preferred Stock. These dividends have not been declared by the Company’s Board of Directors.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

Common Stock Repurchase Program

 

In March 2018, the Company entered into a share-repurchase agreement (the “SRA”) with an investment brokerage company (“Broker”) to repurchase $1.0 million of the Company’s common stock as part of the Share Repurchase Plan (the “Plan”). Under the terms of the SRA, the Company paid cash directly to the Broker and received delivery of shares of the Company’s common stock. All of the shares acquired by Lilis under the SRA are as treasury stock. For the three months ended March 31, 2018, the Company purchased 68,798 shares of the Company’s common stock for approximately $0.3 million.

 

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Warrants

 

The following table provides a summary of warrant activity for the three months ended March 31, 2018:

 

   Warrants   Weighted-
Average
Exercise Price
 
Outstanding at January 1, 2018   11,882,800   $3.46 
Exercised   -   $- 
Expired   (45,187)  $(40.94)
Outstanding at March 31, 2018   11,837,613   $3.32 

  

NOTE 12 - SHARE BASED AND OTHER COMPENSATION

 

The Company’s stock-based compensation consisted of the following (dollars in thousands):

 

    Three Months Ended  
March 31, 2018
    Three Months Ended  
March 31, 2017
 
    Stock  
Options
    Restricted  
Stock
    Total     Stock  
Options
    Restricted  
Stock
    Total  
Stock-based compensation expensed   $ 837     $ 2,194     $ 3,031     $ 1,776     $ 1,003     $ 2,779  
Unrecognized stock-based compensation costs   $ 2,342     $ 4,990     $ 7,332     $ 5,114     $ 1,120     $ 6,234  
Weighted average amortization period remaining (in years)     0.56       0.67               1.31       1.08          

 

Restricted Stock

 

A summary of restricted stock grant activity pursuant to the Lilis Energy, Inc. 2012 Omnibus Incentive Plan (the “2012 Plan”) and the 2016 Omnibus Incentive Plan (the “2016 Plan”) for the three months ended March 31, 2018 is presented below:

 

   Number of
Shares
   Weighted
Average Grant
Date Price
 
Outstanding at January 1, 2018   2,475,266   $4.22 
Granted   289,944   $4.18 
Vested and issued   (336,057)  $(4.42)
Forfeited or cancelled   (772,187)  $(2.47)
Outstanding at March 31, 2018   1,656,966   $3.85 

  

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Restricted Stock Units

 

A summary of restricted stock unit grant activity pursuant to the 2012 Plan for the three months ended March 31, 2018 is presented below.

 

   Number of
Shares
   Weighted
 Average Grant
Date Price
 
Outstanding at January 1, 2018   9,999   $6.57 
Vested and issued   (6,666)  $(9.05)
Outstanding at March 31, 2018   3,333   $1.60 

 

Stock Options

 

A summary of stock option activity pursuant to the 2016 Plan for the three months ended March 31, 2018 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, 2018   7,305,000   $3.74    3,534,484    8.9 
Granted   205,000   $3.85           
Exercised   (5,000)  $(2.98)          
Forfeited or cancelled   (849,500)  $(4.44)          
Outstanding at March 31, 2018   6,655,500   $3.66    4,068,329    8.6 

 

During the three months ended March 31, 2018, options to purchase 205,000 shares of the Company’s common stock were granted under the 2016 Plan. The weighted average fair value of these options was $3.85. During the three months ended March 31, 2018, the Company received $15,198 from the exercise of vested stock options.

 

The fair value of stock option awards is determined using the Black-Sholes-Merton option-pricing model based on several assumptions. These assumptions are based on management’s best estimate at the time of grant. The Company used the following weighted average of each assumption based on the grants in each fiscal year:

 

   2018 
Expected Term in Years   6 
Expected Volatility   70.3%
Expected Dividends   0%
Risk-Free Interest Rate   2.63%

 

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NOTE 13: EARNINGS (LOSS) PER COMMON SHARE

 

Basic income or 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 earnings (loss) per share should include the potential dilutive impact of shares issuable upon the conversion of debt or preferred stock, warrants and options during the period using the treasury stock method, unless their effect is anti-dilutive.

 

The computation of basic and diluted earnings per share for the three months ended March 31, 2018 and 2017 is as follows: ($in thousands, except per share data)

 

   Three Months Ended March 31, 
   2018   2017 
Net income (loss)  $12,246   $(8,756)
Less: dividends on redeemable preferred stock   -    (30)
Less: dividends and deemed dividends on Series B convertible preferred stock   -    (213)
Less: dividends on Series C convertible preferred stock   (1,652)   - 
Unallocated net income (loss)  $10,594   $(8,999)
Numerator for basic earnings (loss) per share:          
Net income (loss) attributable to common stockholders   7,775    (8,999)
Net income attributable to preferred stockholders   4,471    - 
Allocated net income (loss)  $12,246   $(8,999)
Denominator for basic earnings (loss) per share:          
Basic weighted average number of common shares outstanding   54,702,617    27,847,651 
Basic weighted average number of common shares outstanding for if-converted participating preferred stock   19,829,268    - 
           
Net income (loss) per share:          
Basic attributable to common stockholders  $0.14   $(0.32)
Attributable to if-converted preferred stockholders  $0.22   $-
Numerator for diluted earnings (loss) per share:          
Net income (loss) attributable to common stockholders  $7,775   $(8,999)
Add: interest expense on convertible Second Lien Loans   7,045    - 
Less: gain on fair value change of embedded derivatives associated with convertible Second Lien Loan   (28,388)   - 
Net loss attributable to common stockholders  $(13,568)  $(8,999)
Denominator for diluted net loss per share:          
Basic weighted average number of common shares outstanding   54,702,617    27,847,651 
Dilution effect of if-converted Second Lien Loans   23,799,580    - 
Diluted weighted average number of common shares outstanding   78,502,197    27,847,651 
           
Net loss per share – diluted:          
Common shares (diluted)  $(0.17)  $(0.32)

 

The Company excluded the following shares from the diluted loss per share calculations because they were anti-dilutive at March 31, 2018 and 2017:

 

    Three Months Ended March 31,  
    2018     2017  
Stock Options     6,655,500       6,318,500  
Restricted Stock Units     3,333       9,999  
Series B Preferred Stock     -       13,071,818  
Series C Preferred Stock     19,829,268       -  
Stock Purchase Warrants     11,837,613       12,946,986  
      38,325,714       32,347,303  

 

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NOTE 14 - SUPPLEMENTAL NON-CASH TRANSACTIONS

 

The following table presents the supplemental disclosure of cash flow information for the three months ended March 31, 2018 and 2017:

 

   Three Months Ended March 31, 
   2018   2017 
   ($ in thousands) 
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 
Fair value of warrants issued and repriced as debt discount   -    1,031 
Common stock issued for acquisition of oil and gas properties   24,778    - 
Common stock issued for commitment fees associated with Private Placement   -    250 
Cashless exercise of warrants   -    370 
Change in capital expenditures for drilling costs in accrued liabilities   16,699    812 

 

NOTE 15 – SEGMENT INFORMATION

 

Operating segments are defined as components of an entity that engage in activities from which it may earn revenues and incur expenses for which separate operational financial information is available and are regularly evaluated by the chief operating decision maker for the purposes of allocating resources and assessing performance. The Company currently has only one reportable operating segment, which is oil and gas development, exploration and production for which the Company has a single management team that allocates capital resources to maximize profitability and measures financial performance as a single entity.

 

NOTE 16 - COMMITMENTS AND CONTINGENCIES

  

Environmental and Governmental Regulation

 

At March 31, 2018, 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 natural 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 natural gas industry legislation and administrative regulations are periodically changed for a variety of political, economic, and other reasons. As of March 31, 2018, 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.

 

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December 31, 2017, as well as the unaudited financial statements and notes thereto included in this Quarterly Report on Form 10-Q. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in these forward-looking statements as a result of various factors including those set forth under Item “1A. Risk Factors.” - in our Annual Report on Form 10-K for the year ended December 31, 2017.

 

Overview

 

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

 

Significant first quarter 2018 highlights include:

 

·First quarter 2018 production increased to 311,882 barrels of oil equivalent (“BOE”) as compared to 84,334 BOE for first quarter 2017;

 

  · Current production has exceeded 6,500 BOE/d;

 

  · The Company has placed several production hedges on approximately 2200 average WTI BOPD barrels that yield an average floor of $57.04 and a ceiling of $62.66 for the remainder of 2018 and the company has also placed several basis hedges on 1300 Midland-Cushing WTI BOPD barrels with an average cost differential of $5.617 for 2018.

 

·Closing of the acquisition of 2,798 net leasehold acres in the Delaware Basin in Lea County, New Mexico from OneEnergy Partners, LLC (“OEP”) for cash and stock consideration of approximately $66.0 million and the acquisition of oil and gas interests in Loving and Winkler Counties, Texas from VPD Texas L.P., for cash consideration of approximately $10.6 million. As a result of these acquisitions, our net acreage increased from 35,200 gross (15,700 net) acres to 39,200 gross (19,433 net) acres as of March 31, 2018;

 

·Entered into a Securities Purchase Agreement (the “SPA”) with certain private funds affiliated with Värde Partner, Inc. (the “Purchasers”) through the issuance of 100,000 shares of a newly created Series C 9.75% Convertible Participating Preferred Stock (the “Series C Preferred Stock”), for a purchase price of $1,000 per share, or an aggregate of $100 million to fund the OEP Acquisition and a portion of our 2018 capital expenditure budget;

 

·Entered into an Amended and Restated Senior Secured Term Loan Credit Agreement (the “Riverstone First Lien Credit Agreement”) for an aggregate principal amount of $50 million at an original issue discount of 1.0%. The proceeds were used to retire the First Lien Credit Agreement, for 2018 capital expenditures, acquisitions and other general corporate purposes, including payment of transaction expenses.

 

Drilling Program

 

We have a drilling program in 2018 of up to 16 gross (11 net) wells that is contingent upon our access to sufficient capital to fully execute our plans.

 

Results of Operations – For the Three Months Ended March 31, 2018 and 2017

 

During the three months ended March 31, 2018, we drilled or were in the process of drilling 8 gross (6.9 net) horizontal wells and completed or were in the process of completing 8 gross (7.3 net) horizontal wells. As of March 31, 2018, we have production flowing from our 13 horizontal wells and 13 legacy vertical wells with an estimated productive capacity of approximately 5,317 net BOE per day, on a combined equivalent oil, NGL and natural gas basis.

 

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Since March 31, 2017, we have placed eight net wells into production, resulting in a net increase of 227,549 BOE for the three months ended March 31, 2018 compared to the three months ended March 31, 2017.

 

The following sets forth selected revenue and production data for the three months ended March 31, 2018 and 2017:

 

   For the Three Months
Ended March 31,
     
   2018   2017   Change   % Change 
Net production:                    
Oil (Bbls)   208,439    51,491    156,948    305%
Natural gas (Mcf)   414,032    172,157    241,875    140%
NGL (Bbl)   34,438    4,150    30,288    730%
Total (BOE)   311,882    84,334    227,549    270%
Average daily production (BOE/d)   3,465    937    2,528    270%
                     
Average realized sales price:                    
Oil (Bbl)  $60.40   $48.47   $11.93    25%
Natural gas (Mcf)   2.15    2.91    (0.76)   -26%
NGL (Bbl)   26.60    20.96    5.63    27%
Total (BOE)  $46.16   $36.57   $9.59    26%
                     
Oil, natural gas and NGL revenues (in thousands):                    
Oil revenue  $12,589   $2,496   $10,093    404%
Natural gas revenue   890    501    389    78%
NGL revenue   916    87    829    953%
Total revenue  $14,395   $3,084   $11,311    367%

 

Oil, natural gas and NGL sales. For the three months ended March 31, 2018, oil, natural gas and NGL sales revenue increased $11.3 million to $14.4 million, compared to $3.1 million for the same period during 2017. Approximately $8.3 million of the increase was due to higher oil, natural gas and NGL production in the first three months of 2018 compared to the same period in 2017. Higher realized oil and NGL prices of $60.40 and $26.60 per BBL, respectively, partially by lower realized prices for natural gas of $2.15 per MCF, increased revenues by approximately $3.0 million for the quarter.

 

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

 

Our production during the three months ended March 31, 2018, increased by 227,549 BOE from 84,334 BOE in the 2017 three-month period to 311,882 BOE in the 2018 three-month period, an increase of 270%. This increase in production was primarily attributable to wells placed on production in the Delaware Basin after March 31, 2017.

 

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The following table shows a comparison of production costs for the three months ended March 31, 2018 and 2017:

 

    For the Three Months Ended
March 31,
       
    2018     2017     Change     %
Change
 
Production Costs per BOE:                                
Production costs   $ 9.91     $ 9.83     $ 0.08       1 %
Production taxes     3.28       1.68       1.60       95 %
Depreciation, depletion, amortization and accretion     14.88       13.59       1.29       10 %
Total (BOE)   $ 28.07     $ 25.10     $ 2.97       12 %
                                 
Operating Expenses:                                
Production costs   $ 3,090     $ 829     $ 2,261       273 %
Gathering, processing and transportation      462       99       363       366 %
Production taxes     1,023       142       881       620 %
General and administrative     10,464       9,162       1,302       14 %
Depreciation, depletion, amortization and accretion     4,641       1,146       3,495       305 %
Total Operating Expenses   $ 19,680     $ 11,378     $ 8,302       73 %

 

Production costs. Our lease operating expenses (LOE) increased from $0.8 million or $9.83 per BOE for the three months ended March 31, 2017, to $3.1 million or $9.91 per BOE for the three months ended March 31, 2018. The 273% increase in LOE is a result of the 270% increase in BOE production for the same comparison period.

 

Gathering, processing and transportation. Our gathering, processing and transportation costs increased $0.4 million to $0.5 million for the three months ended March 31, 2018 compared to $0.1 million during the same period in 2017. The increase was the result of higher production volumes and rate-related increases as compared to the same period in 2017.

 

Production taxes. Production taxes as a percentage of total revenue were 7.1% during the three months ended March 31, 2018 as compared to 4.6% for the three months ended March 31, 2017. The prior period tax was consistent with the Texas oil production tax rate of 4.6%. During the second half of 2017, first sales of oil occurred from two New Mexico oil wells, with a composite tax rate of roughly 8.4% due to state and county production, severance, and ad valorem taxes. In the first three months of 2018 the New Mexico oil sales were approximately one-third of all oil revenues, resulting in the higher overall tax rate versus the prior year period when sales were primarily from Texas.

 

Depreciation, depletion, amortization and accretion. Our depreciation, depletion and amortization expense increased by $3.5 million to $4.6 million for the three months ended March 31, 2018, compared to $1.1 million during the same period in 2017. The increase was the result of a higher depletion rate per BOE ($0.4 million) and higher production volumes ($3.1 million) as compared to the same period in 2017.

 

General and administrative expenses. General and administrative expenses (“G&A”) increased by $1.3 million to $10.5 million for the three months ended March 31, 2018, as compared to $9.2 for the three months ended March 31, 2017. The increase of $1.3 million was primarily attributed to an increase of $2.8 million in professional and legal fees offset by the decrease of $1.2 million in payroll and $0.3 million in other general and administrative expenses. For the three months ended March 31, 2018, the general and administrative expenses included approximately $4.8 million of recurring G&A, approximately $2.7 million of non-recurring G&A and approximately $3.0 million of stock based compensation compared to approximately $3.4 million of recurring G&A, approximately $3.0 million of non-recurring G&A and approximately $2.8 million of stock based compensation, respectively, for the three months ended March 31, 2017.

 

32

 

 

   Three Months Ended March 31,         
             
   2018   2017   Variance   % 
   (In Thousands)         
Other income (expense):                    
Other income (expense)  $1   $8   $(7)   -88%
Loss from commodity derivatives, net   (1,769)   -    (1,769)   100%
Gain from fair value changes of debt conversion and warrant derivatives   28,388    346    28,042    8105%
Loss in fair value changes of conditionally redeemable 6% preferred stock   -    (41)   41    100%
Interest expense   (9,089)   (774)   (8,315)   1074%
Total other income (expenses)  $17,531   $(461)  $17,992    3903%

 

Loss from Commodity Derivatives. During the fourth quarter of 2017 and the first quarter of 2018, oil price derivatives were entered into with counterparties. As a result of increases in oil prices since entering into the derivative transactions, we recorded a loss of $0.6 million on settlements and a loss of $1.1 million on the unsettled position as a result of the changes in fair value of the oil commodity derivatives. During the three months ended March 31, 2017, we did not participate in any commodity derivative transactions.

 

Gain from Fair Value Changes of Derivatives. During the three months ended March 31, 2018, the fair value change of $28.4 million included only the fair value change of embedded derivatives for the convertible Second Lien Credit Agreement while during the three months ended March 31, 2017, the $0.3 million fair value change included the fair value changes of various warrant derivatives that had since been exercised during 2017. The significant gain of $28.4 million recorded during the three months ended March 2018 was primarily attributed to the decrease in the Company stock price from $5.11 per share at December 31, 2017 to $3.97 per share at March 31, 2018 resulting approximately 39% decrease in the fair value of the embedded derivatives from $72.9 million to $44.3 million, respectively.

 

Interest Expense. Interest expense for the three months ended March 31, 2018 was $9.1 million compared to $0.8 million for the three months ended March 31, 2017. For the three months ended March 31, 2018, we incurred interest expense of $1.4 million for quarterly interest payments on notes payable and term loans, $3.2 million of paid-in-kind interest, $3.8 million related to amortized debt discount on our Second Lien Loans and $0.6 million of amortized debt issuance costs. For the three months ended March 31, 2017, we incurred $0.5 million of interest expense and $0.3 million of non-cash interest relating to amortized debt issuance costs on debentures, convertible notes and non-convertible notes.

 

Capital Resources and Liquidity

 

Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions and investors, the sale of equity and equity derivative securities and asset dispositions. Our primary uses of capital have been for the acquisition, development, exploration and exploitation of oil and natural gas properties, in addition to refinancing of debt instruments. We have a significant amount of derivative securities outstanding, which upon exercise or conversion, would result in substantial dilution of our common stock. Furthermore, if we sell additional equity or convertible debt securities, such sales could result in further dilution to our existing stockholders and cause the price of our outstanding securities to decline.

 

We believe our financial position is strong and provides the financial flexibility to fund our currently planned 2018 capital expenditures. During the first quarter of 2018, we raised $150 million in cash, with net proceeds to be used for 2018 capital expenditures, acquisitions, repayment of existing debt and other general corporate purposes. On January 31, 2018, we announced our entry into a new $50 million, three-year term loan with Riverstone Credit Partners, LLC, that refinanced our existing first-lien bridge loan. Approximately $31.8 million in proceeds were used to pay off and retire the First Lien Credit Agreement, and remaining proceeds have been and will be used to fund 2018 capital expenditures, acquisitions and other general corporate purposes, including payment of transaction expenses. In addition, on January 30, 2018, we entered into a Securities Purchase Agreement with Värde Partners, Inc to purchase from the Company 100,000 shares of a newly created series of preferred stock for an aggregate of $100 million in proceeds to the company.

 

33

 

 

Based upon current commodity price expectations for 2018 and 2019, we believe that our cash flow from operations, in addition to financing activity, will be sufficient to fund our drilling and completion operations over the next 12 months, 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 at least 90% of our 2018 operational capital program and, as a result, the amount and timing of a substantial portion of our capital expenditures is discretionary.  We expect that our 2018 capital program will also provide us with discretion in the pace and scale of spending.  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.

 

Information about our cash flows for the three months ended March 31, 2018 and 2017 are presented in the following table (amounts in thousands):

 

   Three Months Ended March 31, 
   2018   2017 
Cash provided by (used in):          
Operating activities  $(4,058)  $(5,254)
Investing activities   (90,289)   (10,278)
Financing activities   112,519    24,855 
Net change in cash, cash equivalents and restricted cash  $18,172   $9,323 

 

Operating activities. For the three months ended March 31, 2018, net cash used in operating activities was $4.1 million, compared to $5.3 million for the same period in 2017. The decrease of $1.2 million in cash used in operating activities was primarily attributable to expanding operational activities.

  

Investing activities. For the three months ended March 31, 2018, net cash used in investing activities was $90.3 million compared to $10.3 million for the same period in 2017. The $90.3 million in cash used in investing activities during the three months ended March 31, 2018 was primarily attributable to the following:

 

·approximately $38.6 million in drilling and completion costs;
·approximately $41.1 million cash consideration on the acquisition of leasehold acreage in the Delaware Basin in Lea County, New Mexico from OneEnergy Partners Operating, LLC; and,
·approximately $10.6 million cash consideration on the acquisition of proved and unproved oil and gas properties in Loving and Winkler Counties, Texas from VPD Texas, L.P.

 

Financing activities. For the three months ended March 31, 2018, net cash provided by financing activities was $112.5 million compared to cash provided by financing activities of $24.9 million during the same period in 2017. The $112.5 million in net cash provided by financing activities included the following:

 

·$97.5 million net proceeds from the issuance of 100,000 shares of Series C 9.75% Preferred Stock;
·$47.5 million net proceeds from the Riverstone First Lien Term Loan;
·Offset by the payments of $31.8 million to retire the First Lien bridge notes, $0.3 million for repurchase of the Company’s common stock and $0.4 million for tax withholding for employee stock-based compensation awards.

 

Off-Balance Sheet Arrangements

 

We do not have any material off-balance sheet arrangements.

 

34

 

 

Commitments and Contractual Obligations

 

There have been no material changes in our contractual obligations during the three months ended March 31, 2018.

 

Item 3. Quantitative and Qualitative Disclosures About Market Risk

 

We are exposed to a variety of market risks from changes in commodity prices and interest rates as discussed below.

 

Commodity Price Risk

 

Our major market risk exposure is in the pricing applicable to our oil and natural gas production. Market risk refers to the risk of loss from adverse changes in oil and natural gas prices. Realized pricing is primarily driven by the prevailing domestic price for crude oil and spot prices applicable to the region in which we produce natural gas. Historically, prices received for oil and natural gas production have been volatile and unpredictable. We expect pricing volatility to continue.

 

The prices we receive depend on many factors outside of our control. Oil prices we received during the three months ended March 31, 2018, ranged from a low of $59.67 per barrel to a high of $61.44 per barrel. Natural gas prices we received during the same period ranged from a low of $1.46 per Mcf to a high of $2.67 per Mcf. NGL prices we received during the period ranged from a low of $0.58 per gallon to a high of $0.67 per gallon. A significant decline in the prices of oil or natural gas could have a material adverse effect on our financial condition and results of operations. In order to reduce commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil and natural gas, we may enter into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production.

 

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. The amount we can borrow is subject to periodic redetermination based in part on changing expectations of future prices. Lower prices may also reduce the amount of oil and natural gas that we can economically produce. We currently sell all of our oil and natural gas production under price sensitive or market price contracts.

 

Interest Rate Risk

 

As of March 31, 2018, we have $50 million outstanding under our Amended and Restated Senior Secured Term Loan Credit Agreement with an applicable margin that varies from 5.75% to 6.75%. Our Second Lien Term Loan Credit Agreement bear a fixed interest rate of 8.25% per annum, compounded quarterly in arrears and payable only in-kind by increasing the principal amount of the loan by the amount of the interest due on each interest payment date. In addition, holders of our shares of Series C Preferred Stock are entitled to receive cumulative preferential dividends, payable and compounded quarterly in arrears at an annual rate of 9.785% of the Stated Value until maturity. We currently do not have any interest rate derivative contracts in place. If we incur significant debt with a risk of fluctuating interest rates in the future, we may enter into interest rate derivative contracts on a portion of our then outstanding debt to mitigate the risk of fluctuating interest rates.

 

35

 

 

Customer Credit Risk

 

Our principal exposures to credit risk is through receivables from the sale of our oil and natural gas production (approximately $7.9 million at March 31, 2018) and through receivables from our joint interest partners (approximately $6.7 million at March 31, 2018). We are subject to credit risk due to the concentration of our oil and natural gas receivables with our most significant customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. For the three months ended March 31, 2018, sales to three customers, Texican Crude & Hydrocarbons, LLC, Lucid Energy Delaware, LLC, and ETC Field Services LLC, accounted for approximately 87%, 7% and 6% of our revenue, respectively. For the three months ended March 31, 2017, sales to two customers, Texican Crude & Hydrocarbons, LLC and ETC Field Services LLC, accounted for approximately 71% and 29% of our revenue, respectively. Due to availability of other purchasers, we do not believe the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations.

 

Currency Exchange Rate Risk

 

We do not have any foreign sales and we accept payment for our commodity sales only in U.S. dollars. We are therefore not exposed to foreign currency exchange rate risk on these sales.

  

Item 4. Controls and Procedures

 

Evaluation of disclosure controls and procedures

 

As required by Rule 13a-15(b) under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), at the end of the period we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Our CEO and CFO have determined that disclosures controls and procedures were ineffective as of March 31, 2018 as the changes described below are still being evaluated.

 

Changes in internal control over financial reporting

 

During the three months ended March 31, 2018, we took following actions with respect to our full cost ceiling test calculation which constituted a material change in internal controls over financial reporting:

 

  (i) implemented procedures to perform enhanced detailed reviews and analytical analysis on our tax position and projected tax position with respect to the impact of projected income taxes on the ceiling test; and

 

  (ii) implemented procedures for additional reviews on the ceiling test calculation, including treatment of wells-in-process, future income tax effects, and future development cost and procedures to validate the ceiling test calculation with the reserve report.

 

Our management believes these changes should be sufficient to remediate the above identified material weakness. However, management is continuing to validate the operating effectiveness of these controls over an appropriate period of time prior to concluding that the material weakness has been remediated.

  

36

 

 

PART II – OTHER INFORMATION

 

Item 1. Legal Proceedings.

 

None.

 

Item 1A. Risk Factors.

 

Risk factors relating to us are contained in Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2017.  No material change to such risk factors has occurred during the three months ended March 31, 2018.

 

Item 2. Recent Sales of Unregistered Securities; Use of Proceeds from Registered Securities.

 

None

 

Item 3. Defaults Upon Senior Securities

 

None

 

Item 4. Mine Safety Disclosures

 

Not applicable

 

Item 5. Other Information

 

None

 

37

 

 

Item 6. Exhibits

 

EXHIBIT INDEX

 

2.1 Purchase and Sale Agreement, dated as of January 30, 2018, by and between Lilis Energy, Inc. and OneEnergy Partners Operating, LLC (incorporated herein by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on February 1, 2018).
3.1 Certificate of Designation of Preferences, Rights and Limitations of Series C 9.75% Convertible Participating Preferred Stock, dated January 31, 2018 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on February 1, 2018).
10.1 Securities Purchase Agreement, dated as of January 30, 2018, by and among Lilis Energy, Inc. and the Purchasers party thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 1, 2018).
10.2 Registration Rights Agreement, dated as of January 31, 2018, by and among Lilis Energy, Inc. and the Purchasers party thereto (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on February 1, 2018).
10.3 Amended and Restated Senior Secured Term Loan Credit Agreement, dated as of January 30, 2018, by and among Lilis Energy, Inc., the subsidiaries of the Company party thereto as guarantors, Riverstone Credit Management LLC, as administrative agent and collateral agent, and the lenders party thereto (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on February 1, 2018).
10.4 Amendment No. 4 to Second Lien Credit Agreement, dated as of January 31, 2018, by and among Lilis Energy, Inc., the guarantors party thereto, the lenders party thereto and Wilmington Trust, National Association, as administrative agent (incorporated herein by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on February 1, 2018).
10.5 Amendment No. 5 to Second Lien Credit Agreement, dated as of February 20, 2018, by and among Lilis Energy, Inc., the guarantors party thereto, the lenders party thereto and Wilmington Trust, National Association, as administrative agent. (incorporated herein by reference to Exhibit 10.58 to the Company’s Annual Report on Form 10-K filed on March 9, 2018).
10.6 Amendment No. 1 to the Amended and Restated Senior Secured Term Loan Credit Agreement, dated as of February 20, 2018, by and among Lilis Energy, Inc., the subsidiaries of the Company party thereto as guarantors, Riverstone Credit Management LLC, as administrative agent and collateral agent, and the lenders party thereto (incorporated herein by reference to Exhibit 10.59 to the Company’s Annual Report on Form 10-K filed on March 9, 2018).
31.1* Certification of the Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).
31.2* Certification of the Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act.
32.1* Certification of the Chief Executive Officer pursuant to Rule 13a-14(b)/15d-14(b) of the Exchange Act, and 18 U.S.C. Section 1350.
32.2* Certification of the Chief Financial Officer pursuant to Rule 13a-14(b)/15d-14(b) of the Exchange Act, and 18 U.S.C. Section 1350.
101.INS* XBRL Instance Document
101.SCH* XBRL Taxonomy Extension Schema Document
101.CAL* XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF* XBRL Taxonomy Extension Definition Linkbase Document
101.LAB* XBRL Taxonomy Extension Label Linkbase Document
101.PRE* XBRL Taxonomy Extension Presentation Linkbase Document
* Filed herewith.
Indicates management contract or compensatory plan.
+ To be filed by amendment.

 

38

 

 

SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

  Lilis Energy, Inc.
     
Date: May 10, 2018 By: /s/ Ronald D. Ormand
    Ronald D. Ormand
    Chief Executive Officer
    (Principal Executive Officer)
     
Date: May 10, 2018 By: /s/ Joseph C. Daches
    Joseph C. Daches
    Executive Vice President, Chief Financial Officer and Treasurer
    (Principal Financial and Accounting Officer)

 

39

 

 

Exhibit 31.1

 

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO RULE 13A-14(A) OF

THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

 

I, Ronald D. Ormand, certify that:

 

1.I have reviewed this report on Form 10-Q of Lilis Energy, Inc. ("Registrant");

 

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this report;

 

4.The Registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and have:

 

a.designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

b.designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 

c.evaluated the effectiveness of the Registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

d.disclosed in this report any change in the Registrant's internal control over financial reporting that occurred during the Registrant's most recent fiscal quarter (the Registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Registrant's internal control over financial reporting; and

 

5.The Registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant's auditors and the audit committee of Registrant's board of directors (or persons performing the equivalent functions):

 

a.all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant's ability to record, process, summarize and report financial information; and

 

b.any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant's internal control over financial reporting.

 

/s/ Ronald D. Ormand  
Ronald D. Ormand  

Executive Chairman of the Board and Chief Executive Officer

 

 

May 10, 2018

 

 

 

 

Exhibit 31.2

 

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO RULE 13A-14(A) OF

THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

 

I, Joseph C. Daches, certify that:

 

1.I have reviewed this report on Form 10-Q of Lilis Energy, Inc. ("Registrant");

 

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this report;

 

4.The Registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and have:

 

a.designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

b.designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 

c.evaluated the effectiveness of the Registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

d.disclosed in this report any change in the Registrant's internal control over financial reporting that occurred during the Registrant's most recent fiscal quarter (the Registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Registrant's internal control over financial reporting; and

 

5.The Registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant's auditors and the audit committee of Registrant's board of directors (or persons performing the equivalent functions):

 

a.all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant's ability to record, process, summarize and report financial information; and

 

b.any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant's internal control over financial reporting.

 

/s/ Joseph C. Daches  
Joseph C. Daches  
Executive Vice President, Chief Financial Officer and Treasurer  

 

May 10, 2018

 

 

 

 

Exhibit 32.1

 

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

RULE 13A-14(B)/15D-14(B) OF

THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

 

In connection with the Quarterly Report of Lilis Energy, Inc. (the "Company") on Form 10-Q for the period ended March 31, 2018, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), the undersigned hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

 

(1)   The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

 

(2)   The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

 

/s/ Ronald D. Ormand  
Ronald D. Ormand  

Executive Chairman of the Board and Chief Executive Officer

 

 

May 10, 2018 

 

 

 

 

Exhibit 32.2

 

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

RULE 13A-14(B)/15D-14(B) OF

THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

 

In connection with the Quarterly Report of Lilis Energy, Inc. (the "Company") on Form 10-Q for the period ended March 31, 2018, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), the undersigned hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

 

(1)   The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

 

(2)   The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

 

/s/ Joseph C. Daches  
Joseph C. Daches  
Executive Vice President, Chief Financial Officer and Treasurer  

 

May 10, 2018