UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-Q

 

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

 

For the quarterly period ended September 30, 2017

 

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

 

For the transition period from ______to______.

 

Commission file number: 001-35330

Lilis Energy, Inc.

(Name of registrant as specified in its charter)

 

Nevada   74-3231613

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

 

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

(Address of principal executive offices, including zip code)

 

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

 

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, as amended (the “Exchange Act”), 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, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Act.

 

Large accelerated filer ¨ Accelerated filer ¨
Non-accelerated filer  ¨ Smaller reporting company x
(Do not check if a 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 November 13, 2017, 53,300,332 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 September 30, 2017 and December 31, 2016 4
  Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2017 and 2016 6
  Condensed Consolidated Statement of Changes in Stockholders’ Equity (Deficit) for the Nine Months Ended September 30, 2017 7
  Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2017 and 2016 8
  Notes to the Condensed Consolidated Financial Statements 9
     
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations 31
Item 3. Quantitative and Qualitative Disclosures About Market Risk 43
Item 4. Controls and Procedures 43
     
PART II - OTHER INFORMATION  
     
Item 1. Legal Proceedings 43
Item 1A. Risk Factors 43
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 44
Item 4. Mine Safety Disclosures 44
Item 5. Other Information 44
Item 6.  Exhibits 44
     
SIGNATURES 47
     
EXHIBIT INDEX 48

 

 2 

 

 

FORWARD-LOOKING STATEMENTS

 

This Quarterly Report on Form 10-Q, including materials incorporated by reference herein, contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. All statements other than statements of historical fact are “forward-looking statements” for purposes of federal and state securities laws, including, but not limited to, any projections of earnings, revenue or other financial items; any statements of the plans, strategies and objectives of management for future operations; any statements concerning future production, reserves or other resource development opportunities; any projected well performance or economics, or potential joint ventures or strategic partnerships; any statements regarding future economic conditions or performance; any statements regarding future capital-raising activities; any statements of belief; and any statements of assumptions underlying any of the foregoing.

 

Forward-looking statements may include the words “may,” “should,” “could,” “estimate,” “intend,” “plan,” “project,” “continue,” “believe,” “expect” or “anticipate” or other similar words. These forward-looking statements present our estimates and assumptions only as of the date of this report.  Except as required by law, we undertake no obligation to update any forward-looking statement.

 

Although we believe that the expectations reflected in any of our forward-looking statements are reasonable, actual results could differ materially from those projected or assumed in any of our forward-looking statements. Our future financial condition and results of operations, as well as any forward-looking statements, are subject to change and inherent risks and uncertainties. The factors impacting these risks and uncertainties include, the risk factors discussed in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2016 and the following additional factors:

 

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

 

Many of these factors are beyond our ability to control or predict. These factors are not intended to represent a complete list of the general or specific factors that may affect us.

 

 3 

 

 

LILIS ENERGY, INC.

Condensed Consolidated Balance Sheets

(In thousands, except share and per share data)

(Unaudited)

 

   September 30,   December 31, 
   2017   2016 
         
ASSETS          
Current assets:          
Cash and cash equivalents  $17,820   $11,738 
Accounts receivable, net of allowance of $118 and $106, respectively   4,599    2,247 
Prepaid expenses and other current assets   654    767 
Total current assets   23,073    14,752 
Oil and natural gas properties, full cost method of accounting          
Unproved   47,546    24,461 
Proved   115,294    69,809 
Less: accumulated depreciation, depletion, amortization and impairment   (59,527)   (55,771)
Total oil and natural gas properties, net   103,313    38,499 
           
Other property and equipment, net   81    52 
Other assets   343    216 
Total other assets   424    268 
           
Total assets  $126,810   $53,519 

 

 

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

 

 4 

 

 

LILIS ENERGY, INC.

Condensed Consolidated Balance Sheets

(In thousands, except share and per share data)

(Unaudited)

 

   September 30,   December 31, 
   2017   2016 
         

LIABILITIES, REDEEMABLE PREFERRED STOCK AND
STOCKHOLDERS' EQUITY

          
Current liabilities:          
Accounts payable  $7,561   $5,166 
Accrued liabilities   13,958    2,706 
Dividends payable   -    808 
Asset retirement obligations   194    338 
Current portion of long-term debt   14    17 
Total current liabilities   21,727    9,035 
Asset retirement obligations   938    919 
Long-term debt, net of current portion   65,710    30,226 
Long-term derivative liabilities   33,475    1,400 
Total liabilities   121,850    41,580 
           
Commitments and contingencies (Note 11)          
           
Conditionally redeemable 6% preferred stock, $0.0001 par value, 7,000 shares authorized, 2,000 shares issued and outstanding with a liquidation preference of $2,240 at December 31, 2016   -    1,874 
           
Stockholders’ Equity:          
Series B convertible preferred stock, $0.0001 par value; stated value of $1,000; 20,000 shares authorized; 16,828 shares issued and outstanding at December 31, 2016, with a liquidation preference of $20,627 at December 31, 2016   -    13,432 
Common stock, $0.0001 par value; 150,000,000 shares authorized, 50,763,137 and 20,918,901 shares issued and outstanding as of September 30, 2017 and December 31, 2016, respectively   5    2 
Additional paid-in capital   266,300    219,837 
Accumulated deficit   (261,345)   (223,206)
Total stockholders’ equity   4,960    10,065 
           
Total liabilities, redeemable preferred stock and stockholders’ equity  $126,810   $53,519 

 

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

 

 5 

 

 

LILIS ENERGY, INC.

Condensed Consolidated Statements of Operations

(In thousands, except share and per share data)

(Unaudited)

 

   Three Months Ended September 30,   Nine Months Ended September 30, 
   2017   2016   2017   2016 
Revenue:                
Oil, natural gas and natural gas liquid sales  $5,390   $1,158   $13,779   $2,180 
                     
Costs and expenses:                    
Production costs   1,814    613    4,178    978 
Production taxes   290    61    710    115 
General and administrative   10,943    4,582    36,273    9,741 
Depreciation, depletion, accretion and amortization   1,443    601    3,946    1,162 
Total costs and expenses   14,490    5,857    45,107    11,996 
                     
Loss from operations   (9,100)   (4,699)   (31,328)   (9,816)
                     
Other income (expenses):                    
Other income (expense)   151    51    19    297 
Gain on modification of convertible debentures   -    602    -    602 
Inducement expense   -    (3,180)   -    (8,307)
Change in fair value of derivative liabilities   6,368    (438)   4,295    (535)
Change in fair value of conditionally redeemable 6% preferred stock   -    134    (41)   (644)
Interest expense   (3,656)   (617)   (11,084)   (4,220)
Total other income (expenses)   2,863    (3,448)   (6,811)   (12,807)
                     
Net loss   (6,237)   (8,147)   (38,139)   (22,623)
Dividends on redeemable preferred stock   -    (30)   (122)   (90)
Dividend on Series A Convertible Preferred Stock   -    -    -    (287)
Loss on extinguishment of Series A Convertible Preferred Stock   -    (300)   -    (540)
Dividends and deemed dividends on Series B Convertible Preferred Stock   -    -    (4,635)   (8,206)
Net loss attributable to common shareholders  $(6,237)  $(8,477)  $(42,896)  $(31,746)
                     
Net loss per common share basic and diluted  $(0.12)  $(0.50)  $(1.06)  $(2.59)
Weighted average shares outstanding:                    
Basic and diluted   50,785,588    17,113,942    40,596,281    12,280,013 

 

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

 

 6 

 

 

LILIS ENERGY, INC.

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

Nine Months Ended September 30, 2017

(In thousands, except share and per share data)

(Unaudited)

 

   Series B Preferred           Additional         
   Shares   Common Shares   Paid In   Accumulated     
   Shares   Amount   Shares   Amount   Capital   Deficit   Total 
                             
Balance, December 31, 2016   16,828   $13,432    20,918,901   $2   $219,837   $(223,206)  $10,065 
Stock based compensation   -    -    -    -    14,477    -    14,477 
Restricted stock awards   -    -    2,720,918    -    -    -    - 
Common stock for exercise of stock options   -    -    263,735    -    227         227 
Common stock withheld for taxes on stock based compensation   -    -    (523,411)   -    (2,427)   -    (2,427)
Common stock for drilling services   -    -    22,938    -    97    -    97 
Exercise of warrants   -    -    5,487,078    -    165    -    165 
Cashless exercise of warrants   -    -    77,131    -    371    -    371 
Conversion of Series B preferred stock and dividends to common stock   (16,828)   (13,432)   16,601,026    2    14,863    -    1,433 
Common stock for private placement, net   -    -    5,194,821    1    18,649    -    18,650 
Warrant repriced for term loan   -    -    -    -    1,031    -    1,031 
Dividends on conditionally redeemable preferred stock   -    -    -    -    (122)   -    (122)
Dividends and deemed dividends on Series B preferred stock   -    -    -    -    (868)   -    (868)
Net loss   -    -    -    -    -    (38,139)   (38,139)
Balance, September 30, 2017   -   $-    50,763,137   $5   $266,300   $(261,345)  $4,960 

 

 

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

 

 7 

 

 

LILIS ENERGY, INC.

Condensed Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)

 

   Nine Months Ended September 30, 
   2017   2016 
Cash flows from operating activities:          
Net loss  $(38,139)  $(22,623)
Adjustments to reconcile net loss to net cash used in operating activities:          
Equity instruments issued for compensation   14,477    3,552 
Inducement expense   -    8,307 
Bad debt expense   12    200 
Amortization of debt issuance cost and debt discount   6,703    2,958 
Paid-in-kind interest   3,258    - 
(Gain) loss in fair value of derivative instruments   (4,295)   535 
Loss in fair value of conditionally redeemable 6% preferred stock   41    644 
Depreciation, depletion, accretion and amortization   3,946    1,162 
Gain on modification of convertible debentures   -    (602)
Gain on extinguishment of debt   -    (250)
Changes in operating assets and liabilities:          
Accounts receivable   (2,364)   166 
Prepaid expenses and other assets   (13)   (555)
Accounts payable and accrued liabilities   8,764    (11)
Net cash used in operating activities   (7,610)   (6,517)
           
Cash flows from investing activities:          
Cash advance to Brushy Resources, Inc.   -    (552)
Net proceeds from sale of DJ Basin and non-operated properties   1,282    - 
Capital expenditures   (64,971)   (3,418)
Net cash used in investing activities   (63,689)   (3,970)
           
Cash flows from financing activities:          
Net proceeds from issuance of Series B Preferred Stock   -    18,195 
Proceeds from issuance of convertible notes   -    2,863 
Proceeds from exercise of accordion feature of the First Lien Term Loan, net of financing costs   6,706    - 
Proceeds from Bridge Loan and Second Lien Term Loan, net of financing costs   94,700    - 
Repayment of the First Lien Term Loan   (38,100)   - 
Repayment of conditionally redeemable 6% preferred stock including dividends   (2,276)   - 
Proceeds from warrant exercise   165    187 
Proceeds from exercise of stock options   227    - 
Payment for tax withholding on stock based compensation   (2,427)   - 
Proceeds from private placement, net of financing costs   18,399    - 
Proceeds from the First Lien Term Loan, net of financing costs   -    24,000 
Repayment of notes payable   (13)   (13,879)
Net cash provided by financing activities   77,381    31,366 
Increase in cash   6,082    20,879 
Cash and cash equivalents at beginning of period   11,738    110 
Cash and cash equivalents at end of period  $17,820   $20,989 
Supplemental disclosure:          
Cash paid for interest  $1,594   $217 

 

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

 8 

 

 

LILIS ENERGY, INC.

NOTES TO THE CONDENSED 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 Reeves, Winkler and Loving Counties, Texas and Lea County, New Mexico.

 

 

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND ESTIMATES

 

Principles of Consolidation

 

The condensed consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. As of September 30, 2017, the Company’s wholly owned subsidiaries include Brushy Resources, Inc. (“Brushy”), ImPetro Operating, LLC (“ImPetro Operating”), ImPetro Resources, LLC (“Resources”), Lilis Operating Company, LLC (“Lilis Operating”), and Hurricane Resources LLC (“Hurricane Resources”). All significant intercompany accounts and transactions have been eliminated in consolidation.

   

Interim Financial Statements

 

In management’s opinion, these unaudited condensed consolidated financial statements reflect all adjustments, consisting only of normal and recurring adjustments, necessary to fairly state the Company’s financial position as of, and results of operations for, the periods presented. These financial statements should be read in conjunction with the financial statements and related notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016. The Company’s accounting policies are described in the Notes to the Condensed Consolidated Financial Statements in its Annual Report on Form 10-K for the year ended December 31, 2016, and updated, as necessary, in this Quarterly Report on Form 10-Q.

 

Use of Estimates

 

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”) requires the Company to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ significantly from those estimates. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. Although actual results may differ from these estimates under different assumptions or conditions, the Company believes that its estimates are reasonable. 

 

The most significant financial estimates are associated with the Company’s estimated volumes of proved oil and natural gas reserves, asset retirement obligations, assessments of impairment on oil and natural gas properties, fair value of financial instruments including derivative liabilities, depreciation and accretion, income taxes and contingencies.

 

Reclassifications

 

Certain reclassifications have been made to the prior period financial statements to conform to the current period presentation. These reclassifications have no effect on the Company’s previously reported results of operations. For the three and nine months ended September 30, 2016, the income from operator’s overhead recovery of $60,615 and $75,731, respectively, have been reclassified from revenues to operating expenses as an offset against general and administrative expenses.

 

Oil and Natural Gas Producing Activities

 

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

 

 9 

 

 

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 costs to be incurred in developing proved reserves; and (c) estimated decommissioning and abandonment/restoration costs, net of estimated salvage values, that are not otherwise included in capitalized costs.

 

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

 

Under the full cost method of accounting, capitalized oil and 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. During the three and nine months ended September 30, 2017 and 2016, respectively, no impairment was recorded.

 

The present value of estimated future net cash flows was computed by applying a flat oil price to forecasted 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 flat oil price is based on the WTI Spot Posting SEC price. Specifically, it is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, as defined by the SEC in Rule 4-10 of Regulation S-X. The flat oil price is adjusted to match up with accounting data through the use of a differential.

 

Accrued Liabilities

 

As of September 30, 2017 and December 31, 2016, the Company’s accrued liabilities consisted of the following:

 

   September 30,
2017
   December 31,
2016
 
   ($ in thousands) 
Accrued bonus  $1,194   $- 
Accrued drilling costs   6,963    1,331 
Revenue payable   4,707    1,313 
Other accrued liabilities   1,094    62 
   $13,958   $2,706 

  

Asset Retirement Obligations

 

The Company incurs retirement obligations for certain assets at the time they are placed in service. The present values of these obligations are recorded as liabilities on a discounted basis. The costs associated with these liabilities are capitalized as part of the related assets and depreciated. Over time, the liabilities are accreted for the change in their present value. For purposes of depletion calculations, the Company includes estimated dismantlement and abandonment cost, net of salvage values, associated with future development activities that have not yet been capitalized as asset retirement obligations. Asset retirement obligations incurred are classified as Level 3 (unobservable inputs) fair value measurements. The asset retirement liability is allocated to operating expense using a systematic and rational method. The Company has accreted approximately $23,000 and $67,000 for the three and nine months ended September 30, 2017, respectively, and approximately $17,000 and $23,000 for the three and nine months ended September 30, 2016, respectively. Accretion expense is recorded in “depreciation, depletion, accretion and amortization” expense in the condensed consolidated statements of operations.

 

 10 

 

 

Revenue Recognition

 

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

 

The Company uses the entitlements method of accounting for oil, natural gas and natural gas liquid (NGL) revenues. Should sales proceeds be in excess of the Company's entitlement, these amounts will be included in accrued liabilities and the Company's share of sales taken by others will be included in other assets in the accompanying consolidated balance sheets. The Company had no material oil, natural gas or NGL entitlement assets or liabilities as of September 30, 2017 and December 31, 2016.

 

All revenue proceeds relating to third-party royalty owners not remitted by the end of a reporting period are recorded as revenue payable, a component of accrued liabilities. As of September 30, 2017 and December 31, 2016, the Company had approximately $4.7 million and $1.3 million, respectively, of such revenue proceeds recorded in accrued liabilities.

  

Major Customers

 

During the three and nine months ended September 30, 2017 and 2016, the Company’s major customers as a percentage of total revenue consisted of the following:

 

   Three Months Ended September 30,   Nine Months Ended September 30, 
   2017   2016   2017   2016 
Texican Natural Gas Company   86%   50%   83%   68%
Energy Transfer Partners, L.P.   14%   13%   15%   12%
Noble Energy   0%   17%   0%   11%
Others below 10%   0%   20%   2%   9%
    100%   100%   100%   100%

 

Other Property and Equipment, net

 

Other property and equipment consist principally of property and equipment with finite useful lives (subject to depreciation and amortization). The Company accounts for other property and equipment at cost. The Company may impair this property and equipment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be fully recoverable. Recoverability is measured by comparing the carrying amount of an asset to the expected undiscounted future net cash flows generated by the asset. If it is determined that the asset may not be recoverable, and if the carrying amount of an asset exceeds its estimated fair value, an impairment charge is recognized to the extent of the difference.

 

Loss Per Share

 

Basic loss per share was calculated by dividing loss applicable to common shareholders by the weighted average number of common shares outstanding during the periods presented. The weighted average common shares outstanding include issued and outstanding shares of common stock and shares issuable for little or no consideration. The calculation of diluted loss per share includes the weighted average common shares outstanding plus the potential dilutive impact of shares issuable upon the conversion of debt or preferred stock, unvested restricted stock and exercise of warrants and options during the period (common stock equivalents), unless their effect is anti-dilutive.

 

For the three and nine months ended September 30, 2017 and 2016, common stock equivalents including shares underlying conversion of the term loan, restricted stock units, restricted stock, options, warrants and preferred stock have been excluded from the diluted share calculations as they were anti-dilutive as a result of net losses incurred as follows:

 

 11 

 

  

   2017   2016 
Stock Options   7,369,000    3,488,333 
Restricted Stock Units   9,999    159,583 
Series B Preferred Stock   -    18,478,788 
Stock Purchase Warrants (1)   12,523,045    12,533,574 
Conversion of Term Loan   13,186,584    - 
    33,088,628    34,660,278 

 

  (1) Excludes warrants exercisable for 2,840,912 shares of common stock at an exercise price of $0.01 for the three and nine months ended September 30, 2016 since these warrants are not anti-dilutive. There were no warrants exercisable at $0.01 per share for the three and nine months ended September 30, 2017.

 

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 August 28, 2017, the Financial Accounting Standards Board (“FASB”) issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities which amends the hedge accounting recognition and presentation requirements in Accounting Standards Codification (“ASC”) Topic 815. The new standard provides partial relief on the timing of certain aspects of hedge documentation and eliminates the requirement to recognize hedge ineffectiveness separately in income. The amendments in this ASU are effective for fiscal years beginning after December 15, 2018 and for interim periods therein. Early adoption as of the date of issuance is permitted. The new standard does not impact accounting for derivatives that are not designated as accounting hedges. The Company does not currently account for any of its derivatives position as accounting hedges. The Company may consider designating certain derivatives contracts as accounting hedges in the future, but currently has no plans to do so.

 

On July 13, 2017, the 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 expects to adopt this ASU at its effective date. The Company’s SOS Warrant Liability (as defined in Note 4) is a derivative solely because of its down round feature. Any outstanding SOS Warrants as of the date of adoption will be reclassified to equity and gains or losses on changes in fair value will no longer be recognized. No other derivatives instruments outstanding as of September 30, 2017 would be affected.

 

On May 17, 2017, the FASB issued ASU 2017-09, Scope of Modification Accounting, clarifies Topic 718, Compensation – Stock Compensation, such that an entity must apply modification accounting to changes in the terms or conditions of a share-based payment award unless all of the following criteria are met: (1) the fair value of the modified award is the same as the fair value of the original award immediately before the modification and the ASU indicates that if the modification does not affect any of the inputs to the valuation technique used to value the award, the entity is not required to estimate the value immediately before and after the modification; (2) the vesting conditions of the modified award are the same as the vesting conditions of the original award immediately before the modification; and (3) the classification of the modified award as an equity instrument or a liability instrument is the same as the classification of the original award immediately before the modification; the ASU is effective for all entities for fiscal years beginning after December 15, 2017, including interim periods within those years. Early adoption is permitted, including adoption in an interim period. The Company will adopt this ASU at its effective date. The Company expects the adoption of this ASU would only impact future consolidated financial statements as and when there is a modification to its share-based award agreements.

 

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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 will adopt this ASU at its effective date, and expects that the adoption of this ASU could have a material impact on future consolidated financial statements as there may be acquisitions that are no longer considered to be business combinations.

 

On November 17, 2016, the FASB issued ASU 2016-18, Restricted Cash (Topic 230), to clarify the presentation of restricted cash in the statement of cash flows. The amendments require that a statement of cash flows explain the change during the period in restricted cash or restricted cash equivalents. In addition, changes in cash and cash equivalents, restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. As a result, transfers between cash and restricted cash will not be presented as a separate line item in the operating, investing or financing section of the cash flow statement. The amendments are effective for public entities for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted. The Company will adopt this ASU at effective date and expects the adoption of this ASU to affect only the consolidated statement of cash flows. As of September 30, 2017, the Company has no restricted cash.

 

 On August 26, 2016, the FASB issued ASU No. 2016-15, Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force. The amendments in ASU 2016-15 address eight specific cash flow issues and apply to all entities, including both business entities and not-for-profit entities that are required to present a statement of cash flows under ASC 230, Statement of Cash Flows. The amendments in ASU 2016-15 are effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The Company will adopt this ASU at the effective date. The Company expects the adoption of this ASU to affect only the consolidated statement of cash flows.

 

On March 30, 2016, the FASB issued ASU 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. This ASU will simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This ASU is effective for annual and interim periods beginning in 2017 with early adoption permitted. The Company adopted this ASU on January 1, 2017. The Company grants primarily qualified incentive stock options which do not require the Company to withhold any income taxes when these options are exercised. As of September 30, 2017, none of the four employees who have non-qualified stock options have exercised their vested options. During the three months ended September 30, 2017, the Company withheld income taxes for vested restricted shares but these tax withholdings were processed by a third-party payroll service company. The tax withholding payments were received from the employees who elected to pay cash within 30 days following the Company’s payment to the third-party payroll service company. As a result, these funds flowed through the operating section of the Company’s consolidated statement of cash flows and had no impact on its consolidated statement of operations.

 

On March 14, 2016, the FASB issued ASU 2016-06, Derivatives and Hedging (Topic 815): Contingent Put and Call Options in Debt Instruments. This new standard simplifies the embedded derivative analysis for debt instruments containing contingent call or put options by removing the requirement to assess whether a contingent event is related to interest rates or credit risks. This new standard will be effective for the Company on January 1, 2017. The Company has identified the conversion feature of its debt instrument as an embedded derivative which meets the criteria to be bifurcated from its host contract, the Second Lien Credit Agreement (as defined below), and accounted for separately from the debt instrument.

 

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 September 30, 2017, the Company currently has only one operating lease within the scope of this standard that expires in less than 2 years. The effect of this guidance relating to the Company’s existing long-term leases is expected to require additional disclosures, and the Company is currently evaluating the impact that this ASU would have on the Company’s consolidated financial statements.

 

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On May 28, 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, its final standard on revenue from contracts with customers. ASU 2014-09 outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The core principle of the revenue model is that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In applying the revenue model to contracts within its scope, an entity identifies the contract(s) with a customer, identifies the performance obligations in the contract, determines the transaction price, allocates the transaction price to the performance obligations in the contract and recognizes revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 applies to all contracts with customers and requires significantly expanded disclosures about revenue recognition. ASU 2014-09 has been amended several times with subsequent ASUs including ASU 2015-14 Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date. ASU 2014-09 will be effective for the Company on January 1, 2018, with early adoption permitted, but not earlier than January 1, 2017. The guidance under these standards is to be applied using a full retrospective method or a modified retrospective method. The Company plans to adopt the standard on January 1, 2018 using the modified retrospective approach. The Company has a small number of contracts with customers and has identified transactions within the scope of the standard. The Company is currently reviewing the terms of each of its contracts and believes that the preponderance of its revenue transactions are standard oil and gas sales contracts where revenue will be recognized when control passes to the purchaser, similar to current practices. Although the Company will be revising its policies with respect to gas balancing arrangements, the Company currently does not have any gas balancing transactions. The Company will conduct its contract review process throughout the remainder of 2017 and make appropriate changes to business and control processes to support recognition and disclosure under the new standard. Based on the Company’s evaluation to date, the adoption of the ASU 2014-09 is not expected to have a material impact on its consolidated financial statements because existing contractual performance obligations, which determine when and how revenue is recognized, are not materially changed under the new standard. Additionally, the Company is also working on the expanded disclosures related to revenue recognition as required by the new standard.

  

NOTE 3 - OIL AND NATURAL GAS PROPERTIES & OIL AND NATURAL GAS PROPERTY ACQUISITIONS AND DIVESTITURES

 

The following table sets forth a summary of oil and natural gas property costs (net of divestitures) not being amortized at September 30, 2017 and December 31, 2016:

 

   September 30,   December 31, 
   2017   2016 
   (In thousands) 
Unproved unevaluated acreage:          
Beginning balance  $24.461   $- 
Lease purchases   23,085    546 
Assets acquired   -    23,915 
Total unproved acreage  $47,546   $24,461 
           
Wells in progress:          
Beginning balance  $7,453   $- 
Additions   26,458    7,453 
Reclassification to evaluated properties   (14,649)   - 
Total wells in progress not subject to DD&A  $19,262   $7,453 

 

During the three and nine months ended September 30, 2017 and 2016, no impairment was recorded on the Company’s oil and natural gas properties. 

 

Depreciation, depletion and amortization expense related to proved properties was approximately $1.4 million and $3.9 million for the three and nine months ended September 30, 2017, respectively, and $0.6 million and $1.2 million for the three and nine months ended September 30, 2016, respectively.

 

Divestiture of DJ Basin Properties

 

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 Note 7 - 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.

 

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NOTE 4 - 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.

 

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 and unpaid 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 to 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 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. 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. On April 26, 2017, the embedded derivatives were recorded as a derivative liability at a fair value of approximately $36.7 million and approximately $39.6 million as of June 30, 2017. At September 30, 2017, the fair value of the derivative liabilities associated with the Loan conversion features was approximately $33.3 million. As a result, for the three and nine months ended September 30, 2017, the Company recorded an unrealized gain of $6.4 million and $3.5 million, respectively, on the 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.

 

 15 

 

 

Heartland Warrant Liability. On January 8, 2015, the Company entered into a credit agreement with Heartland Bank (the “Heartland Credit Agreement”). In connection with the Heartland Credit Agreement, the Company issued a warrant to purchase up to 22,500 shares of the Company’s common stock at an exercise price of $25.00. The warrant contained a price protection feature that would have automatically reduced the exercise price if the Company entered into another agreement pursuant to which warrants were issued with a lower exercise price and would also have triggered an adjustment to the number of underlying shares of common stock. On June 14, 2017, the Company and Heartland executed an amended and restated warrant agreement whereby the Company issued a warrant to purchase 160,714 shares of common stock at an exercise price of $3.50 to replace the original warrant to purchase 22,500 shares of common stock previously issued on January 8, 2015 to settle a disagreement regarding the fair value change pursuant to the anti-dilutive price protection provisions in the original warrant. The amended and restated warrant agreement no longer contains any anti-dilutive price protection provisions and the warrant is no longer accounted for as a derivative. As a result of the issuance of the amended and restated warrant, the Company recorded approximately $0.02 million of realized gain on the Heartland warrant liability during the nine months ended September 30, 2017. For the three and nine months ended September 30, 2016, the Company recorded approximately $0.04 million and $0.04 million, respectively, of unrealized losses on the Heartland warrant liability.

 

SOS Warrant Liability. On June 23, 2016, in conjunction with the merger with Brushy in June 2016, the Company issued to SOSV Investment LLC (“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. For the three and nine months ended September 30, 2017, the Company incurred an unrealized gain of approximately $0.1 million and an unrealized loss of approximately $0.06 million, respectively, on the SOS warrant liability. For the three and nine months ended September 30, 2016, the Company incurred an unrealized loss of approximately $0.3 million on the SOS warrant liability.

 

Bristol Capital, LLC Warrant Liability. On September 2, 2014, the Company entered into a consulting agreement with Bristol Capital, LLC (“Bristol”), pursuant to which the Company issued to Bristol a warrant to purchase up to 100,000 shares of the Company’s common stock at an exercise price of $20.00 (or, in the alternative, options exercisable for 100,000 shares of common stock, but in no case, both). The agreement had a price protection feature that automatically reduced the exercise price if the Company entered into another consulting agreement pursuant to which warrants were issued with a lower exercise price, which was triggered in year 2016.  On March 14, 2017, the Company issued 77,131 shares of common stock to Bristol pursuant to a settlement agreement for a cashless exercise of the warrant.  The Bristol warrant was also revalued on March 14, 2017 resulting in a realized gain in fair value of $0.8 million for the nine months ended September 30, 2017 and decreasing the Bristol derivative liability to $0.4 million.   As a result of the cashless exercise, the Company reclassified the $0.4 million of Bristol derivative liability to additional paid-in capital as of March 31, 2017.

 

The following table provides a summary of the recurring fair values of assets and liabilities measured at fair value (in thousands):

 

September 30, 2017  Level 1   Level 2   Level 3   Total 
Recurring fair value measurements:                    
Warrant liabilities  $-   $-   $(199)  $(199)
Second Lien Term Loan conversion features   -    -    (33,276)   (33,276)
Total recurring fair value measurements  $-   $-   $(33,475)  $(33,475)

 

December 31, 2016  Level 1   Level 2   Level 3   Total 
Recurring fair value measurements:                    
Warrant liabilities  $-   $-   $(1,400)  $(1,400)
Total recurring fair value measurements  $-   $-   $(1,400)  $(1,400)

 

The following table provides a summary of changes in fair value of the Company’s Level 3 financial assets and liabilities during the nine months ended September 30, 2017 and 2016 (in thousands):

 

   Second Lien
Term Loan
Conversion
Features
   Bristol/
Heartland/SOS
Warrant Liabilities
   Total 
             
Balance at January 1, 2017  $-   $(1,400)  $(1,400)
Issuance   (36,741)   -    (36,741)
Cashless exercise of warrants   -    371    371 
Change in fair value of derivative liabilities   3,465    830    4,295 
Balance at September 30, 2017  $(33,276)  $(199)  $(33,475)

 

 16 

 

  

   Convertible
Debenture
Derivative
Liability
   Bristol/
Heartland/SOS
Warrant
Liabilities
   Incentive
Bonus
   Total 
                 
Balance at January 1, 2016  $(6)  $(56)  $(223)  $(285)
Reversal of accrued bonus   -    -    616    616 
Additional liability   -    (164)   (393)   (557)
Converted to equity   43    -    -    43 
Change in fair value of derivative liabilities   (37)   (498)   -    (535)
Balance at September 30, 2016  $-   $(718)  $-   $(718)

 

Assets and liabilities measured at fair value on a nonrecurring basis. Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis, but are subject to fair value adjustments in certain circumstances. These assets and liabilities can include proved and unproved oil and natural gas properties and other long-lived assets that are written down to fair value when they are impaired or held for sale.

 

The Company did not have any transfers of assets or liabilities between Level 1, Level 2 or Level 3 of the fair value measurement hierarchy during the nine months ended September 30, 2017 and 2016.

 

NOTE 5 - LONG-TERM DEBTS

 

   September 30,   December 31, 
   2017   2016 
   (In thousands) 
Term Loans (see table below):          
6% Senior Secured Term Loan, due 2019, net of debt issuance costs  $-   $29,214 
6% Bridge Loan associated with the amended First Lien Term Loan, net of debt issuance costs   15,183    - 
8.25% Second Lien Term Loan, net of debt issuance costs and debt discount   49,526    - 
6% note payable to SOS Investment, LLC, due 2019   1,000    1,000 
Notes payable - other   15    29 
Total long-term debts:   65,724    30,243 
Less: current portion   (14)   (17)
Total long-term debts, net of current portion:  $65,710   $30,226 

 

At September 30, 2017 and December 31, 2016, the carrying amounts of the Term Loans were as follows: 

 

   Principal
Amount
   Paid-in-
kind
Interest
   Unamortized
Debt
Issuance
Costs & Debt
Discount
   Carrying
Amount
 
September 30, 2017:                    
Bridge Loan associated with the amended First Lien Term Loan, due September 2019  $15,000   $395   $(212)  $15,183 
Second Lien Term Loan, due April 2021   80,000    2,863    (33,337)   49,526 
Total:  $95,000   $3,258   $(33,549)  $64,709 
                     
December 31, 2016:                    
Senior Secured Term Loan, due 2019  $31,000   $-   $(1,786)  $29,214 
Total:  $31,000   $-   $(1,786)  $29,214 

 

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First Lien Credit Agreement

 

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

 

The First Lien Credit Agreement provided for a $50 million three-year senior secured term loan with initial commitments of $31 million. On February 7, 2017, pursuant to the terms of the First Lien Credit Agreement, the Company exercised the accordion advance feature, increasing the aggregate principal amount outstanding under the term loan from $31 million to $38.1 million (the “Existing Term Loan”).

 

In connection with the exercise of the accordion advance feature for $7.1 million, the Company incurred $0.4 million in commitment fees and also amended certain warrants held by the lenders to purchase up to approximately 738,638 shares of common stock, such that the exercise price per share was lowered from $2.50 to $0.01. The Company accounted for these repriced warrants as additional debt discount to the Existing Term Loan for $1.0 million, to be accreted, together with the remaining $0.6 million debt discount at December 31, 2016, over the remaining term of the loan. On April 26, 2017, the Company fully paid off the amount outstanding of $38.1 million including accrued interest on the Existing Term Loan. As a result, for the nine months ended September 30, 2017, the Company fully amortized approximately $1.5 million and approximately $1.6 million of deferred financing costs, respectively. These amounts were recorded as a non-cash component of interest expense.

 

Amendments to First Lien Credit Agreement

 

On April 24, 2017, and subsequently on April 26, 2017 and July 25, 2017, the Company entered into the first, second, and third amendments (together, the “First Lien Amendments”), respectively, to the Company’s First Lien Credit Agreement. The First Lien Amendments, among other things, added Lilis Operating and Hurricane Resources as guarantors under the credit agreement, added certain lenders, and extended further credit in the form of an initial bridge loan in an aggregate principal amount of $15.0 million (the “Bridge Loan”). The Bridge Loan was fully drawn on April 24, 2017, and is secured by the same first priority liens on substantially all of the Company’s assets as the Existing Term Loan.

 

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

  

The First Lien Credit Agreement, as amended by the First Lien Amendments, provides that the unpaid principal of the Bridge Loan will bear cash interest at a rate per annum of (i) 6% for the first six months after the execution of the Amendment and (ii) thereafter, so long as any Bridge Loan is outstanding, a rate of 10%. Additionally, the unpaid principal of the Bridge Loan will bear interest at a rate per annum of 6% compounded quarterly in arrears and payable only in-kind. The Bridge Loan matures on October 21, 2018, and may be repaid in whole or part at any time by the Company, subject to payment of certain specified prepayment premiums. The Bridge Loan is subject to mandatory prepayment with the net proceeds of certain asset sales and casualty events, subject to the right of the Company to reinvest the net proceeds of asset sales and casualty events within 180 days.

 

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 in two tranches. The first tranche consists of an $80 million term loan (the “Second Lien Term Loan”), which was fully drawn and funded on April 26, 2017. The second tranche consists of up to $45 million 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.

 

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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.

 

As discussed in Note 4, Fair Value of Financial Instruments, above and Note 6, 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 Term Loan using effective interest rate.

 

SOS Note

 

On June 30, 2016, pursuant to the merger agreement with Brushy and as a condition of the fourth amendment to such merger agreement, the Company was required to make a cash payment of $500,000 to SOS, and also executed a subordinated promissory note with SOS, for $1 million, at an interest rate of 6% per annum which matures on June 30, 2019. In conjunction with the cash payment and the note, the Company also issued 200,000 warrants at an exercise price of $25.00. The Company accounted for the cost of warrants of $0.2 million as part of the Brushy merger transaction costs for the year ended December 31, 2016.

 

Interest Expense

 

The components of interest expense are as follows (in thousands):

 

   Three Months Ended September 30,   Nine Months Ended September 30, 
   2017   2016   2017   2016 
                 
Interest on term loans  $229   $-   $1,086   $217 
Interest on notes payable   17    91    36    101 
Interest on convertible notes and debentures (1)   -    63    -    944 
Paid-in-kind interest on term loans   1,917    -    3,258    - 
Amortization of debt financing costs on term loans   51    -    1,673    220 
Amortization of discount on term loans   1,442    463    5,031    2,738 
Total:  $3,656   $617   $11,084   $4,220 

 

(1)These convertible notes and debentures including accrued interest were fully converted into the Company’s common stock upon closing of the Brushy merger on June 23, 2016.

 

 19 

 

 

NOTE 6 - DERIVATIVES

 

As discussed in Note 5, the Second Lien Term Loan contains conversion features that are exercisable at the option of the Lead Lender or the borrower. 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 the three and nine months ended September 30, 2017. The Company recorded a derivative liability associated with the Second Lien Term Loan at fair value of approximately $36.7 million at issuance date on April 26, 2017 and approximately $39.5 million as of June 30, 2017. As of September 30, 2017, the fair value of the derivative liability was approximately $33.3 million. As a result, the Company recognized unrealized gains of approximately $6.4 million and approximately $3.5 million in its consolidated statement of operations for the three and nine months ended September 30, 2017. There were no derivative liabilities associated with convertible debt instruments for the three and nine months ended September 30, 2016. In addition, as of September 30, 2017 and December 31, 2016, the Company’s outstanding derivative liabilities included the fair value of the derivative liabilities associated with the SOS warrants totaled $0.2 million and $0.3 million, respectively.

 

 

NOTE 7 - RELATED PARTY TRANSACTIONS

 

During the nine months ended September 30, 2017 and 2016, the Company was engaged in the following transactions with related parties:

 

      Nine Months Ended September 30, 
Related Party  Transactions  2017   2016 
      ($ in thousands) 
More than 5% Shareholder:             
Pierre Caland (Wallington
Investment Holdings, Ltd)
  Participated in Series B Preferred Stock offering in 2016 and converted into common stock during the nine months ended September 30, 2017.  $273   $250 
   Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017.  These notes were fully converted into common stock upon closing of the Brushy merger on June 23, 2016.   -    300 
   Converted the holdings of Debentures entered into on December 29, 2015 into common stock upon the closing of the Brushy merger on June 23, 2016.   -    2,090 
   Converted shares of Series A Preferred Stock into common stock upon the closing of the Brushy merger on June 23, 2016.   -    125 
   Participated in private placement transaction on February 28, 2017   1,100    - 
   Total:  $1,373   $2,765 

 

 20 

 

      Nine Months Ended September 30, 
Related Party  Transactions  2017   2016 
              
Bryan Ezralow  Participated in Series B Preferred Stock offering in 2016 and converted into common stock during the nine months ended September 30, 2017.  $628   $1,300 
   Participated in the September 29, 2016 $50 million credit facility   -    1,450 
   Converted the holdings of Debentures entered into on December 29, 2015 into common stock through EZ Colony Partners, LLC owned by Bryan Ezralow upon the closing of the Brushy merger on June 23, 2016.   -    1,540 
   Warrants exercised at $0.01 per share during the nine months ended September 30, 2017.   21    - 
   Participated in private placement transaction on February 28, 2017   1,400    - 
   Total:  $2,049   $4,290 
              
Mark Ezralow  Participated in Series B Preferred Stock offering in 2016 and converted into common stock during the nine months ended September 30, 2017.  $574   $- 
   Participated in the September 29, 2016 $50 million credit facility   -    950 
   Warrants exercised at $0.01 per share during the nine months ended September 30, 2017.   18    - 
   Participated in private placement transaction on February 28, 2017.   1,200    - 
   Total:  $1,792   $950 
              
J. Steven Emerson  Participated in Series B Preferred Stock offering in 2016 and converted into common stock during the nine months ended September 30, 2017.  $1,639   $- 
   Warrants exercised at $0.01 per share during the nine months ended September 30, 2017.   31    - 
   Participated in private placement transaction on February 28, 2017   2,500    - 
   Total:  $4,170   $- 
              
Steve B. Dunn and
Laura Dunn Revocable
Trust dated 10/28/10
  Converted the holdings of Debentures entered into on December 29, 2015 into common stock upon the closing of the Brushy merger on June 23, 2016.  $-   $1,020 
   Total:  $-   $1,020 
              
Rosseau Asset Management Ltd  Participated in Series B Preferred Stock offering in 2016 and converted into common stock during the nine months ended September 30, 2017.  $2,185   $- 
   Warrants exercised at $0.01 per share during the nine months ended September 30, 2017.   2    - 
   Total:  $2,187   $- 
              
Investor Company  Participated in Series B Preferred Stock offering in 2016 and converted into common stock during the nine months ended September 30, 2017.  $4,318   $- 
   Participated in the amendment to the Company’s first lien credit facility in April 2017 by reinvesting its principal amount that was paid down in the form of bridge loan including paid and accrued interests   2,105    - 
   Warrants exercised at $0.01 per share during the nine months ended September 30, 2017.   23    - 
   Total:  $6,446   $- 
              
LOGiQ Capital (Front Street)  Participated in Series B Preferred Stock offering in 2016 and converted into common stock during the nine months ended September 30, 2017.  $3,199   $- 
   Warrants exercised at $0.01 per share during the nine months ended September 30, 2017.   1    - 
   Total:  $3,200   $- 

 21 

 

 

      Nine Months Ended September 30, 
Related Party  Transactions  2017   2016 
              
Directors and Officers:             
G. Tyler Runnels,
(Director)
  Received advisory fee for Series B Preferred Stock offering fees and warrants to purchase up to 452,724 shares of common stock, at an exercise price of $1.30 per share, exercisable on or after September 17, 2016 through T.R. Winston & Company, LLC (“TRW”) (1).  $-   $500 
   Reinvested advisory fee for 150 shares of Series B Preferred Stock and 68,182 warrants at exercise price of $2.50 per share through TRW.   -    150 
   Converted shares of Series A Preferred Stock into common stock upon the closing of the Brushy merger on June 23, 2016 through TRW and Runnels Family Trust DTD 1-11-2000(2).   -    779 
   Cash paid for advisory fee on Convertible Notes which was reinvested in 350 shares of Series B Preferred Stock through TRW.   -    350 
   Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 through TRW, which were fully converted into common stock upon closing of the Brushy merger on June 23, 2016.   -    400 
   Participated in Series B Preferred Stock offering in 2016 through TRW and Runnels Family Trust DTD 1-11-2000 and converted into common stock during the nine months ended September 30, 2017.   520    - 
   Participated in private placement transaction on February 28, 2017 through TRW and Runnels Family Trust DTD 1-11-2000.   796    - 
   Warrants exercised at $0.10 per share during the nine months ended September 30, 2017 through Runnels Family Trust DTD 1-11-2000 and TRW Capital Growth Fund, LP(3)   17    - 
   Sublet office space through TRW in New York to the Company for rent of $10,000 per month from January 1, 2017 through October 31, 2017.   90    - 
   Total:  $1,423   $2,179 
              
Nuno Brandolini
(Director)
  Participated in Convertible Notes maturing on September 30, 2016 and April 1, 2017.  These notes were fully converted into common stock upon closing of the Brushy merger on June 23, 2016.  $-   $250 
   Converted shares of Series A Preferred Stock into common stock upon the closing of the Brushy merger on June 23, 2016.   -    100 
   Warrants exercised at $0.10 per share during the nine months ended September 30, 2017.   4    - 
   Total:  $4   $350 
              
General Merrill McPeak
(Director)
  Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017.  These notes were fully converted into common stock upon closing of the Brushy merger on June 23, 2016.  $-   $250 
   Converted shares of Series A Preferred Stock into common stock upon the closing of the Brushy merger on June 23, 2016.   -    250 
   Total:  $-   $500 
              
R. Glenn Dawson
(Director)
  Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017.  These notes were fully converted into common stock upon closing of the Brushy merger on June 23, 2016.  $-   $50 
   Participated in Series B Preferred Stock offering in 2016 and converted into common stock during the nine months ended June 30, 2017.   130    125 
   Total:  $130   $175 

 

 22 

 

 

        Nine Months Ended September 30,  
Related Party   Transactions   2017     2016  
                     
Mark Christensen (Director)   Participated in the Company’s upsize of the first lien facility in February 2017 through Trace Capital Inc. (“Trace Capital”) (4)   $ 1,600     $ -  
    Participated in private placement transaction on February 28, 2017 through Trace Capital.     1,000       -  
    Participated in the amendment to the Company’s first lien credit facility in April 2017 through Trace Capital by reinvesting its principal amount that was paid down in the form of bridge loans plus paid and accrued interest     1,526       -  
    Exercise of warrants     1       -  
    Received fees through KES 7 Capital Inc. (5) for acting as an advisor on certain of the Company’s financing transactions.     552       -  
    Total:   $ 4,679     $ -  
                     
Ronald D. Ormand (Executive Chairman)   Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 through the Bruin Trust.(6)  These notes were fully converted into common stock upon closing of the Brushy merger on June 23, 2016.   $ -     $ 1,150  
    Participated in Series B Preferred Stock offering in 2016 and converted into common stock in 2017 through Perugia Investment LP(7) during the nine months ended September 30, 2017.     1,093       1,000  
    Exercise of warrants     4       -  
    Converted shares of Series A Preferred Stock into common stock through Perugia Investment LP upon the closing of the Brushy merger on June 23, 2016.     -       500  
    Accounts receivable due for tax withholding on vested restricted shares. This amount was paid on October 11, 2017.     194       -  
    Total:   $ 1,291     $ 2,650  
                     
Abraham Mirman (former Chief Executive Officer and Director)   Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 through The Bralina Group, LLC.(8)  These notes were fully converted into common stock upon closing of the Brushy merger on June 23, 2016.   $ -     $ 750  
    Participated in Series B Preferred Stock offering in 2016 and converted into common stock in 2017 through the Bralina Group, LLC.     1,803       1,650  
    Converted shares of Series A Preferred Stock into common stock upon the closing of the Brushy merger on June 23, 2016.     -       250  
    Total:   $ 1,803     $ 2,650  
                     
Brennan Short (Chief Operating Officer)   Consulting fees paid to MMZ Consulting, Inc. which is owned by Mr. Short.  Mr. Short is the sole member of the corporation.   $ 282     $ -  
    Golf tournament charges billed by MMZ Consulting, Inc and other personal expenses claimed through expense reports.     3       -  
    Total:   $ 285     $ -  

 

 23 

 

 

      Nine Months Ended September 30, 
Related Party  Transactions  2017   2016 
              
Kevin Nanke (former Chief Financial Officer)  Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017.  These notes were converted into the Company’s common stock upon the closing of the Brushy merger on June 23, 2016.  $-   $100 
   Participated in Series B Preferred Stock offering in 2016 and converted into common stock in 2017 through KKN Holdings LLC during the nine months ended September 30, 2017.   219    200 
   Warrants exercised at $0.01 per share during the nine months ended September 30, 2017.   4    - 
   Purchased the DJ Basin properties from the Company through Nanke Energy, LLC on January 31, 2017.   2,000    - 
   Total:  $2,223   $300 

 

(1) Mr. Runnels has sole voting and dispositive power over all securities held by T.R. Winston & Company, LLC.
(2) Mr. Runnels acts as a trustee with Jasmine N. Runnels for the Runnels Family Trust DTD 1-11-2000 and has shared voting and dispositive power.
(3) Mr. Runnels has sole voting and dispositive power over all securities held by TRW Capital Growth Fund, LP.
(4) Trace Capital Inc. is an entity controlled by Mr. Christensen’s wife, who has sole voting and dispositive power over the securities held by Trace Capital Inc.
(5) Mr. Christensen has sole voting and dispositive power over all securities held by KES 7 Capital Inc.
(6) An irrevocable trust managed by Jerry Ormand, Mr. Ormand's brother, as trustee and whose beneficiaries are the adult children of Ronald Ormand.
(7) Mr. Ormand has sole voting and dispositive power over the securities held by Perugia Investment LP.
(8) Mr. Mirman has shared voting and dispositive power over the securities held by The Bralina Group, LLC with Susan Mirman.

 

 24 

 

 

NOTE 8 - SHAREHOLDERS’ EQUITY

 

Authorized Shares of Common Stock

 

On May 2, 2017, the Board of Directors authorized the amendment of the Company’s certificate of incorporation to increase the number of authorized shares of common stock by 50 million from the prior level of 100 million. This amendment was also approved by the Company’s shareholders on July 13, 2017. There was no change in the stated par value of the shares as a result of this amendment.

 

Conditionally Redeemable 6% Preferred Stock

 

In August 2014, the Company designated 2,000 shares of its authorized preferred stock as Conditionally Redeemable 6% Preferred Stock, or (the “Redeemable Preferred”). All 2,000 shares of Redeemable Preferred were issued in September 2014, pursuant to the Settlement Agreement with Hexagon, LLC (f/k/a Hexagon Investments, LLC) (“Hexagon”). The Redeemable Preferred had a par value and stated value $1,000 per share and were not convertible into common stock or any other securities of the Company. Except as otherwise required by law, holders of the Redeemable Preferred were not entitled to voting rights.

 

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

 

Series B 6% Convertible Preferred Stock

 

On June 15, 2016, the Company entered into a purchase agreement for the private placement of 20,000 shares of its Series B 6% Convertible Preferred Stock (the “Series B Preferred Stock”), along with detachable warrants to purchase up to 9,090,926 shares of common stock, at an exercise price of $2.50 per share, for aggregate gross proceeds of $20 million. The Series B Preferred Stock was converted in full as of June 30, 2017, as described below.

 

Each share of Series B Preferred Stock was convertible, at the option of the holder, subject to adjustment under certain circumstances into shares of common stock of the Company at a conversion price of $1.10. Except as otherwise required by law, holders of the Series B Preferred Stock were not entitled to voting rights. The Series B Preferred Stock was convertible at any time, subject to certain conditions, at the option of the holders, or at the Company’s discretion when the Company’s common stock traded above $10.00 (subject to any reverse or forward stock splits and the like) for ten consecutive days. In addition, the Company had the right to redeem the shares of Series B Preferred Stock, along with any accrued and unpaid dividends, at any time, subject to certain conditions set forth in the Certificate of Designation. The holders of the Series B Preferred Stock were entitled to receive a dividend payable (subject to certain conditions set forth in the Certificate of Designation), in cash or shares of common stock of the Company, at the election of the Company, at a rate of 6% per annum.

 

On April 25, 2017, the Company entered into a Series B 6.0% Convertible Preferred Stock Conversion Agreement (the “Conversion Agreement”), with all of the holders of the outstanding Series B Preferred Stock (the “Series B Holders”) to convert any outstanding shares of Series B Preferred Stock including an increase in the stated value of to reflect dividends that would have accrued through December 31, 2017 in the amount of approximately 14.3 million shares of common stock. On the same date, the Series B Holders further agreed to adopt the Amended and Restated Certificate of Designation of Preferences, Rights and Limitations of Series B 6% Convertible Preferred Stock (“A&R COD”) in order to remove certain restrictions contained therein with respect to beneficial ownership limitations, a condition of the Conversion Agreement. The A&R COD became effective on April 26, 2017, resulting in the automatic conversion of all outstanding Series B Preferred Stock. As a result of the automatic conversion, the Company recognized $4.6 million of dividends and deemed dividends on the Series B Preferred Stock during the nine months ended September 30, 2017.

 

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

 

 25 

 

 

Private Placement

 

On February 28, 2017, the Company entered into a Securities Subscription Agreement (the “Subscription Agreement”) with certain institutional and accredited investors in connection with a private placement the (“March 2017 Private Placement”) to sell 5.2 million units, consisting of approximately 5.2 million shares of common stock and warrants to purchase approximately an additional 2.6 million shares of common stock. Each unit consists of one share of common stock and a warrant to purchase 0.50 shares of common stock (each, a “Unit”), at a price per unit of $3.85. Each warrant has an exercise price of $4.50 and may be subject to redemption by the Company, upon prior written notice, if the price of the Company’s common stock closes at or above $6.30 for twenty trading days during a consecutive thirty trading day period. As of September 30, 2017, the Company has received aggregate gross proceeds of $20.0 million and issued 5,194,821 shares of common stock and warrants to purchase 2,597,420 shares of common stock.

 

Warrants

 

The following table provides a summary of warrant activity for the nine months ended September 30, 2017:

 

   Warrants   Weighted-
Average
Exercise Price
 
Outstanding at January 1, 2017   15,915,511   $3.34 
Warrants issued in connection with private placement   2,597,420   $4.50 
Warrants issued to Heartland   160,714   $3.50 
Exercised   (6,128,100)   (0.30)
Forfeited or expired   (22,500)  $(25.00)
Outstanding at September 30, 2017   12,523,045   $4.59 

  

NOTE 9 - SHARE BASED AND OTHER COMPENSATION

 

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

 

   Nine Months Ended  
September 30, 2017
   Nine Months Ended  
September 30, 2016
 
   Stock  
Options
   Restricted  
Stock
   Total   Stock  
Options
   Restricted  
Stock
   Total 
Stock-based compensation expensed  $6,550   $7,927   $14,477   $2,289   $1,263   $3,552 
Unrecognized stock-based compensation costs  $5,217   $1,133   $6,350   $2,720   $1,400   $4,120 
Weighted average amortization period remaining (in years)   0.75    0.68    -    1.74    1.18    - 

 

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 nine months ended September 30, 2017 is presented below:

 

   Number of
Shares
   Weighted
Average Grant
Date Price
 
Outstanding at January 1, 2017   1,068,305   $1.55 
Granted   1,488,845   $4.54 
Vested and issued   (1,426,684)  $(2.73)
Forfeited or cancelled   (448,424)  $(3.78)
Outstanding at September 30, 2017   682,042   $2.86 

 

 26 

 

 

Restricted Stock Units

 

A summary of restricted stock unit grant activity pursuant to the 2012 Plan and the 2016 Plan for the nine months ended September 30, 2017 is presented below.

 

   Number of
Shares
   Weighted
 Average Grant
Date Price
 
Outstanding at January 1, 2017   149,584   $10.56 
Vested and issued   (139,585)  $(4.77)
Outstanding at September 30, 2017   9,999   $6.57 

 

Stock Options

 

A summary of stock option activity pursuant to the 2012 Plan and the 2016 Plan for the nine months ended September 30, 2017 is presented below:

 

           Stock Options Outstanding and
 Exercisable
 
   Number
of Options
   Weighted
Average
Exercise
Price
   Number
of Options
Vested/
Exercisable
   Weighted
Average
Remaining
Contractual Life
(Years)
 
Outstanding at January 1, 2017   5,956,833   $2.04    2,208,757    9.7 
Granted   3,240,000   $4.73           
Exercised   (236,896)  $(1.34)          
Forfeited or cancelled   (1,590,937)  $(3.06)          
Outstanding at September 30, 2017   7,369,000   $3.74    3,552,944    9.2 

 

During the nine months ended September 30, 2017, options to purchase 3,240,000 shares of the Company’s common stock were granted under the 2016 Plan. The weighted average fair value of these options was $2.62. The fair values were determined using the Black-Scholes-Merton option valuation method assuming no dividends, a risk-free interest rate ranging from 1.21% to 1.45%, a weighted average expected life of 2 years and weighted-average volatility of 100.5%.

 

The options to purchase 3,240,000 shares of the Company’s common stock include the following:

 

  (i)

Options granted to employees of the Company to purchase 2,490,000 shares of the Company’s common stock during the nine months ended September 30, 2017; and

  (ii)

On June 16, 2017, the Company cancelled 250,000 of the options granted in June 2016 and all of the 500,000 options granted in December 2016 to an executive due to option grants that were in excess of the 2016 Plan individual limits. Additional options to purchase 750,000 shares of the Company’s common stock, 389,657 restricted shares and cash in an amount of $87,922 were awarded and paid to the executive to replace the cancelled option grants. The Company accounted for the replacement award as a modification of the terms of the cancelled award in accordance with ASC 718-20-35-8 “Cancellation of an award accompanied by the concurrent grant of (or offer to grant) a replacement award or other valuation consideration.” As a result, during the nine months ended September 30, 2017, the Company recorded incremental compensation of approximately $1.6 million which was the excess of the fair value of the vested replacement award over the fair value of the cancelled awards. The incremental fair value of the unvested replacement awards was to be amortized over the remaining vesting period.  As a result of the resignation of the executive in August 2017, the remaining unvested replacement awards were fully vested and expensed totaling approximately $3.2 million during the three and nine months ended September 30, 2017.

 

As of September 30, 2017, total unrecognized compensation costs relating to the outstanding options was approximately $5.2 million, which is expected to be recognized over the remaining weighted average vesting period of approximately 0.75 years.

 

 27 

 

 

NOTE 10 - SUPPLEMENTAL NON-CASH TRANSACTIONS

 

The following table presents the supplemental disclosure of cash flow information for the nine months ended September 30, 2017 and 2016:

 

   Nine Months Ended September 30, 
   2017   2016 
   ($ 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  $14,865   $- 
Common stock issued for Brushy’s common stock   -    6,942 
Common stock issued for Series A Preferred Stock and accrued dividends   -    8,221 
Common stock issued for convertible debentures and accrued interest   -    8,121 
Common stock issued for convertible notes and accrued interest   -    11,106 
Warrants issued for fees associated with Series B 6% Preferred Stock   -    1,590 
Loss on extinguishment of Series A Preferred Stock   -    540 
Warrants issued with Series B Preferred Stock issuance and recorded as deemed dividend   -    7,880 
Commitment fees offset by issuance of common stock for Private Placement   250    - 
Fair value of warrants issued and repriced as debt discount   1,031    1,479 
Cashless exercise of warrants   371    - 
Issuance of common stock for director fees   -    85 
Issuance of common stock for drilling services   97    - 
Deemed dividends on Series B 6% Convertible Preferred Stock associated with beneficial conversion features   3,767    - 
Change in capital expenditures for drilling costs in accrued liabilities   5,632    - 
Asset retirement established on newly drilled wells   8    1,479 

  

NOTE 11 - COMMITMENTS AND CONTINGENCIES

 

Revenue Contract

 

On August 10, 2017, the Company entered into a long-term agreement with Lucid Energy Group (“Lucid”) relating to gas gathering, processing and associated services to support the Company’s production operations. Pursuant to the agreement, Lucid will receive, gather and process the Company’s gas production from certain production areas located in Lea County, New Mexico and Loving and Winkler counties, Texas. The agreement secures incremental midstream capacity for the Company in the production areas committed to the new agreement. We currently expect to commence services with Lucid on our New Mexico and Texas properties in November and December 2017, respectively. Prior to the February 1, 2018 termination of our current gathering arrangement, we have negotiated the ability to deliver certain quantities of curtailed gas to Lucid upon connection to the Lucid system.

 

Departure of Chief Executive Officer and Director

 

On August 3, 2017, Abraham Mirman notified the Company of his resignation as Chief Executive Officer, and as a member of the Company’s Board of Directors (the “Board”), effective as of August 4, 2017 (the “Separation Date”). Mr. Mirman also resigned from all positions held with the Company’s subsidiaries. Mr. Mirman’s decision to resign was not the result of any disagreement with the Company, the Board, or management, or any matter relating to the Company’s operations, policies or practices. In connection with Mr. Mirman’s resignation, the Company entered into a Separation and Consulting Agreement with Mr. Mirman on August 3, 2017 (the “Mirman Agreement”), setting forth the terms of Mr. Mirman’s separation from the Company and his prospective consulting services.

 

Pursuant to the terms of the Mirman Agreement, in satisfaction of any and all obligations under his employment agreement, Mr. Mirman received the following severance payments, subject to applicable employer and employee withholding by the Company: (1) accrued benefits (including base salary, vacation pay and reimbursements) that are unpaid as of the Separation Date, (2) a lump-sum cash payment of $1.0 million, (3) premium payments for continuing COBRA coverage for eighteen months or until Mr. Mirman obtains alternative coverage, whichever is earlier, and (4) reimbursement of reasonable attorneys’ fees incurred in connection with his separation. Any unvested shares of restricted stock or unvested stock options which were previously awarded to Mr. Mirman vested on August 12, 2017.

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The Mirman Agreement also provides for the engagement of Mr. Mirman as an independent consultant to provide consulting or advisory services as the Company may reasonably request with respect to its business. Mr. Mirman’s consultancy commenced on August 5, 2017 and will terminate on August 5, 2018, unless terminated earlier or extended by mutual agreement in accordance with the terms of the Agreement. In consideration for his consulting services, the Company will pay Mr. Mirman a monthly consulting fee of $41,661.

 

The Mirman Agreement contains other standard provisions contained in agreements of this nature, including restrictive covenants concerning confidentiality, non-competition, non-solicitation and non-disparagement, and a general release of any and all claims Mr. Mirman may have against the Company, its directors, officers and associated persons.

 

Environmental and Governmental Regulation

 

At September 30, 2017, there were no known environmental or regulatory matters which are reasonably expected to result in a material liability to the Company. Many aspects of the oil and 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 September 30, 2017, the Company had not been fined or cited for any violations of governmental regulations that would have a material adverse effect on the financial condition of the Company.

 

Legal Proceedings

 

The Company may from time to time be involved in various legal actions arising in the normal course of business. In the opinion of management, the Company’s liability, if any, in these pending actions would not have a material adverse effect on the financial position of the Company. The Company’s general and administrative expenses would include amounts incurred to resolve claims made against the Company.

 

The Company believes there is no litigation pending that could have, individually or in the aggregate, a material adverse effect on its results of operations or financial condition.

 

NOTE 12 - SUBSEQUENT EVENTS

 

Lease Acquisition Agreement

 

On October 3, 2017, the Company entered into a lease acquisition agreement (the “Acquisition Agreement”) with KEW Drilling, a Delaware limited partnership (“KEW”), pursuant to which the Company will acquire from KEW undeveloped net acres in Winkler County, Texas for an aggregate purchase price of up to $47.0 million pursuant to the terms set forth in the Acquisition Agreement (collectively, the “Leases”). If KEW acquires additional acreage during the time period between the execution of the Acquisition Agreement until closing that exceeds the $47.0 million aggregate purchase price threshold (calculated on a per-net-acre basis), the Company has the option, but not the obligation, to acquire any additional oil and natural gas leases that are acquired by KEW that meet the specifications set forth in the Acquisition Agreement.

 

The Acquisition Agreement contains terms and conditions customary to transactions of the type including title due diligence provisions and representations and warranties regarding the Leases, including, but not limited to, those regarding taxes, liens, litigation, preferential rights to purchase and consents.

 

The Company expects to fund the purchase price for the Leases with borrowings drawn under the Delayed Draw Term Loans pursuant to the Second Lien Credit Agreement and cash on hand, which includes proceeds drawn under the First Lien Credit Agreement as described below.

 

On November 9, 2017, the Company closed on the initial settlement of approximately 3,200 net acres in Winkler County, Texas for approximately $35.8 million and expects to complete the close of the remaining net acreage in early December 2017.

 

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Amendment No. 1 to the Second Lien Credit Agreement

 

On October 3, 2017, the Company, the Guarantors, the Agent and the Lenders, including the Lead Lender, 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 $45.0 million Delayed Draw Term Loans under the Second Lien Credit Agreement and to provide for the funding of such Delayed Draw Term Loans upon the signing of the Acquisition Agreement. The Company borrowed the full $45.0 million of the availability under the Delayed Draw Terms Loans on October 4, 2017.

 

Pursuant to Amendment No. 1 to the Second Lien Credit Agreement, if the Company does not use any portion of the Delayed Draw Term Loans for the acquisitions contemplated by the Acquisition Agreement or such other acquisitions as may be approved by the Lead Lender within a specified time period ending not later than January 10, 2018, the Company will be required to prepay such unused portion of the Delayed Draw Terms Loans, together with accrued and unpaid interest and a prepayment premium equal to a 20% annualized rate on such amount (but without the make-whole amount otherwise payable on repayment of loans under the Second Lien Credit Agreement), within two business days after the end of such specified period. Any portion of the Delayed Draw Term Loans so repaid may be later re-borrowed by the Company, subject to the terms of the Second Lien Credit Agreement.

 

Amendment No. 4 to the First Lien Credit Agreement

 

On October 19, 2017, the Company entered into a fourth amendment to the First Lien Credit Agreement (“Amendment No. 4 to the First Lien Credit Agreement”). Pursuant to Amendment No. 4 to the First Lien Credit Agreement, among other things, certain lenders identified therein joined the existing lenders as lenders under the First Lien Credit Agreement, and the lenders made further extensions of credit, in addition to the existing loans under the First Lien Credit Agreement (the “Existing Bridge Loans”), in the form of an additional, incremental bridge loan in an aggregate principal amount of $15.0 million (the “Incremental Bridge Loan”, and together with the Existing Bridge Loans, the “First Lien Loans”). The First Lien Loans, including the Incremental Bridge Loan, were fully drawn as of October 19, 2017.

 

The First Lien Credit Agreement, as amended by Amendment No 4. to the First Lien Credit Agreement, (a) provides that, effective as of October 1, 2017, the unpaid principal of the First Lien Loans will bear (i) cash interest at a rate per annum of 10% and (ii) additional interest at a rate per annum of 6%, payable only in-kind by increasing the principal amount of the First Lien Loans by the amount of such interest due on each interest payment date and (b) permits the loans under the Second Lien Credit Agreement to equal an increased amount of up to $175.0 million. The First Lien Loans mature on October 21, 2018 and may be repaid in whole or part at any time at the option of the Company, subject to the payment of certain specified prepayment premiums. Additionally, the First Lien Loans are subject to mandatory prepayment with the net proceeds of certain asset sales and casualty events, subject to the right of the Company to reinvest the net proceeds of asset sales and casualty events within 180 days.

 

Amendment No. 2 to the Second Lien Credit Agreement 

 

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.

 

Amendment No. 3 to the Second 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. As previously disclosed, in October 2017, the Company borrowed the full $45 million of Delayed Draw Term Loans available under the Second Lien Credit Agreement prior to Amendment No. 3 to the Second Lien Credit Agreement. The additional $25.0 million of delayed draw term loans is undrawn as of November 14, 2017 and will be available for borrowing by the Company in one or more drawings of $5.0 million or more from time to time on or before February 28, 2019, subject to certain conditions. Proceeds of the additional loans may be used to fund oil and gas property acquisitions, subject to certain limitations, or drilling and completions costs or for other general corporate purposes.

 

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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, 2016, as well as the unaudited condensed consolidated 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 “Forward-Looking Statements” above and Item 1A (Risk Factors) in our Annual Report on Form 10-K for the year ended December 31, 2016.

 

Overview

 

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

 

On June 23, 2016, we completed a merger transaction with Brushy Resources, Inc. (“Brushy”). The merger resulted in the acquisition of our properties in the Delaware Basin as well as the majority of our current operating activity. This contiguous acreage position is offset by RSP Permian, Inc., Matador Resources Company, Devon Energy Corporation, Royal Dutch Shell PLC, Anadarko Petroleum Corp., and XTO Energy Inc., among other operators. Since entering the Delaware Basin in June 2016, we have grown our acreage position approximately 340% from approximately 3,500 net acres to approximately 15,400 net acres primarily in our Delaware Basin-Core area.

 

Our Business

 

As of November 10, 2017, we have accumulated approximately 15,400 net acres in what we believe to be the core of the Delaware Basin in Reeves, Winkler and Loving Counties, Texas and Lea County, New Mexico. Our leasehold position is largely contiguous, allowing us to maximize development efficiency and manage full cycle finding costs. In addition, approximately 38% of our acreage position is held by production, and we are the named operator on 100% of our producing acreage. These two characteristics give us control over the pace of development and the ability to design a more efficient and profitable drilling program that maximizes recovery of hydrocarbons. We expect that the remainder of our 2017 and our 2018 capital expenditure budget will be focused on the development and expansion of our Delaware Basin acreage and operations. We also plan to continue to selectively and opportunistically pursue strategic acreage acquisitions in the Delaware Basin. 

 

We generate the majority of our revenues from sales of oil, natural gas and natural gas liquids (NGLs). The prices of these products are critical factors to our success and volatility in the prices of oil and natural gas could impact our results of operations. In addition, our business requires substantial capital to acquire properties and develop our non-producing properties. Declines in these prices would reduce our revenues and result in lower cash inflow which would make it more difficult for us to pursue our plans to acquire new properties and develop existing properties. The declines in oil and natural gas prices may also adversely affect our ability to obtain additional funding.

 

On August 10, 2017, we entered into a long-term agreement with Lucid Energy Group (“Lucid”) relating to gas gathering, processing and associated services to support our production operations. Pursuant to the agreement, Lucid will receive, gather and process our gas production from certain production areas located in Lea County, New Mexico and in Loving and Winkler counties, Texas. The agreement secures incremental midstream capacity for us in the production areas committed to the new agreement. This agreement is expected to tie in our New Mexico production in mid-November 2017 with our Texas production commencing in early December 2017 providing a long-term solution to the curtailment issues which we are currently experiencing with our production.

 

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Liquidity

 

We have reported a net operating loss during the quarter and year-to-date ended September 30, 2017 and for the past five years. As a result, we funded our operations in 2016 and the merger with Brushy through a combination of debt and equity financing. On September 29, 2016, we entered into a new first lien credit agreement that provided for a three-year, senior, secured term loan with initial aggregate principal commitments of $31 million and a maximum facility size of $50 million (the “First Lien Credit Agreement”). The initial commitment on the term loan was funded with $25 million collected as of September 30, 2016 and an additional $6 million collected as of November 11, 2016. We have funded our operations during the nine months ended September 30, 2017 through cash flows from operations, additional debt and equity financing. On February 7, 2017, we completed the drawdown of an incremental $7.1 million under our first lien credit agreement, and on March 1, 2017, we completed a private placement that raised net proceeds of approximately $18.7 million (the “March 2017 Private Placement”). Net proceeds of $17.9 million were received in March 2017 and $0.6 million were received in May 2017.

 

As described below, in April 2017, we amended our First Lien Credit Agreement and closed on a new $125 million, four-year convertible, second lien term loan facility earning paid-in-kind interest (the “Second Lien Credit Agreement”). This resulted in approximately $56.6 million of combined net proceeds and our option for a delayed-draw tranche under the Second Lien Credit Agreement with maximum additional capacity of $45 million for certain pre-approved leasing and acquisition activity (the “Delayed Draw Term Loan”). We additionally refinanced $38.1 million in principal under our then existing first lien term loan (the “First Lien Term Loan”), paid accrued and unpaid interest thereon, and redeemed and converted all of our preferred stock. On October 3, 2017 we entered into a lease acquisition agreement to acquire up to $47 million in additional acreage. On October 4, 2017, we amended the Second Lien Term Loan (as defined below) and borrowed the full $45 million available under the Delayed Draw Term Loan, proceeds of which will be used to fund the majority of the purchase price due at closing of the Acquisition Agreement. (See Note 12 – Subsequent Events). As of November 8, 2017, we have approximately $62.0 million of cash on hand. On November 10, 2017, we entered into a third amendment to the Second Lien Credit Agreement to increase the Delayed Draw Term Loan by $25.0 million. The additional $25.0 million delayed draw term loans are undrawn as of November 14, 2017 and will be available for borrowing by the us in one or more drawings of $5.0 million or more from time to time prior to February 28, 2019, subject to certain conditions. Proceeds of these delayed draw term loans will be used to fund oil and gas property acquisitions, subject to certain limitations, or drilling and completions costs or for other general corporate purposes.

 

As a result of our financing, drilling and completion operations and the other liquidity events outlined herein that occurred subsequent to September 30, 2017, we believe that we will have sufficient capital to operate over the next 12 months. However, it is possible that we could seek to raise additional debt and equity capital depending on the pace of our drilling and leasing activity. If we need to obtain new debt or equity financing in the future, the terms and availability of such financing may be impacted by economic and financial market conditions, as well as our financial condition and results of operations at the time we seek additional financing. There can be no assurance that financing will be available in amounts or on terms acceptable to us, if at all.

 

Amendments to First Lien Credit Agreement and Second Lien Credit Agreement

 

On April 24, 2017, and subsequently on April 26, 2017 and July 25, 2017, we entered into three amendments to First Lien Credit Agreement and into the Second Lien Credit Agreement. Under the amendments to our existing credit facility, among other things, we received approximately $14.7 million in net proceeds from a new, $15 million, 18-month, first lien term loan (“Bridge Loan”). On April 26, 2017, we entered into the Second Lien Credit Agreement which was structured as an $80 million, four-year term loan that funded at closing (the “Second Lien Term Loan”), and a $45 million Delayed Draw Term Loan that may be used to fund acreage leasing activity and acquisitions under certain conditions. We received approximately $56.6 million in combined net proceeds from the Bridge Loan and the Second Lien Credit Agreement, following repayment of $38.1 million in principal outstanding under the then existing first lien term loan, which was subsequently terminated, plus accrued interest.

 

The structure of the Delayed Draw Term Loans, which was drawn in full on October 4, 2017, is otherwise identical to the $80 million Second Lien Term Loan that funded at closing. The conversion price under both the Second Lien Term Loan and the Delayed Draw Term Loan is $5.50, subject to adjustment under a conversion formula and customary anti-dilution provisions. At conversion, 70% of the total conversion amount, including a make whole payment, will convert to equity, and 30% will convert into a three-year term loan bearing cash interest.

 

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

 

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Pursuant to the terms of the Second Lien Credit Agreement, Värde Partners, Inc. (the “Lead Lenders”) have the right to appoint up to two members to the Board upon conversion of the Second Lien Term Loan, based on the percentage of outstanding common stock held by the Lead Lenders at the time of conversion. On August 12, 2017, we and the Lead Lenders entered into a letter agreement pursuant to which we granted the Lead Lenders the right to appoint one member to the Board, who shall be reasonably acceptable to us, effective immediately upon execution of the letter agreement. The letter agreement provides that, to the fullest extent permitted by law, until the conversion of the Second Lien Term Loan, we will include in the slate of nominees recommended by the Board at any meeting of stockholders called for the purpose of electing directors the person designated by the Lead Lenders to serve on the Board pursuant to the appointment right set forth in the letter agreement. The letter agreement was entered into in connection with an acknowledgment and consent by the Lenders related to the resignation and replacement of our Chief Executive Officer, among other matters. On September 6, 2017, pursuant to the terms of the letter agreement, Mark Christensen was appointed to our Board of Directors.

 

Redemption of Conditionally Redeemable 6% Preferred Stock

 

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

 

Series B 6% Convertible Preferred Stock Conversion

 

On April 25, 2017, we entered into a Series B 6.0% Convertible Preferred Stock Conversion Agreement (the “Conversion Agreement”), with all of the holders of the outstanding Series B 6% Convertible Preferred Stock (the “Series B Holders”) to convert any outstanding shares of Series B Preferred Stock including an increase in the stated value of to reflect dividends that would have accrued through December 31, 2017 in the amount of approximately 14.3 million shares of common stock. Approximately 2.3 million shares of common stock were issued to Series B Holders who converted their shares of Series B Preferred Stock prior to April 25, 2017. On the same date, we and the Series B Holders further agreed to adopt the Amended and Restated Certificate of Designation of Preferences, Rights and Limitations of Series B 6% Convertible Preferred Stock (“A&R COD”) in order to remove certain restrictions contained therein with respect to beneficial ownership limitations, a condition of the Conversion Agreement. The A&R COD became effective on April 26, 2017, resulting in the automatic conversion of all outstanding Series B Preferred Stock.

 

Drilling Program

 

We have a drilling program of up to 11 gross Delaware Basin wells (9 net) that is contingent upon our access to sufficient capital to fully execute. In the first half of 2017, we completed five wells and one well close to completion. As of September 30, 2017, we had drilled a sixth well, which was waiting on completion, and had begun drilling a seventh well. We expect our 2017 horizontal drilling program will be focused almost exclusively on the Wolfcamp zone of the Delaware Basin, with lateral lengths ranging from approximately 4,000’ laterals to 7,000’ laterals.

 

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Results of Operations

 

We have executed a new midstream agreement and arranged for optionality with our existing midstream provider in an effort to increase our natural gas production takeaway, resulting in the increased ability to produce and provide capacity for our expanding production base. During the three months ended September 30, 2017, we successfully brought online our fifth Wolfcamp B horizontal well the Wildhog BWX State Com #1H. Located in Lea County New Mexico, the Wildhog BWX State Com #1H is our most geologically eastern well and is the closest well to the Central Basin Platform in our current acreage position. As of September 30, 2017, we have production flowing from our five horizontal wells and 17 legacy vertical wells with an estimated productive capacity of approximately 2,750 net BOE per day, on a combined equivalent oil, NGL and natural gas basis. Our production for the three months ended September 30, 2017 and thereafter, however, has been temporarily impacted by curtailments resulting from operational issues and midstream infrastructure constraints pursuant to our current gathering and processing arrangement. Primarily as a result of this midstream constraint, our productive capacity has been curtailed by approximately 40%. Accordingly, our average realized production for the quarter was approximately 1,675 BOE per day for the three months ended September 30, 2017 as compared to our full wellhead capacity of 2,750 BOE per day. To resolve the curtailment issues, we entered into a long-term gas gathering processing and purchase agreement with Lucid that would secure incremental midstream capacity for us in the production areas.  Additionally, on November 10, 2017, we executed a gas gathering and processing agreement with our existing gas gathering provider to extend their services on certain vertical wellbores upon expiration of the original contract on February 1, 2018 to further increase our capacity. Adding the Lucid midstream solution should permanently resolve our midstream constraints, improving our ability to produce to operational capacity. We expect to be connected and selling gas in Southeast New Mexico from both the Wildhog BWX State Com #1H and the Prizehog BWX State Com #1H under the Lucid contract in November. The Lucid system should be operational in Texas by December 15, 2017 and we should have maximum production potential on the Lucid system by mid-January 2018. Additionally, upon connection to the Lucid system, we should be able to deliver additional quantities of gas in Texas to Lucid in the event that we continue to experience curtailment issues with our current gas gatherer from December 2017 through February 2018.

 

The results of operations of Brushy are included with those of Lilis commencing on June 23, 2016. As a result, results of operations for the nine months ended September 30, 2017 are not necessarily comparable to the nine-month period in 2016. Additionally, all discussion related to historical representations of common stock, unless otherwise noted, gives retroactive effect to the reverse split for all periods presented.

 

The following table compares production volumes and average prices for the three and nine months ended September 30, 2017 and 2016:

 

   Three Months Ended September 30,         
   2017   2016   Variance   % 
Product                
Oil (Bbls)-net production   97,824    21,892    75,932    347%
Oil (Bbls)-average realized price  $44.75   $40.05   $4.70    12%
                     
Natural gas (Mcf)-net production   215,930    99,030    116,900    118%
Natural gas (MCFE)-average realized price  $2.74   $2.35   $0.39    17%
                     
Natural gas liquids (Bbls)-net production   20,266    3,381    16,886    499%
Natural gas liquids (Bbls)-average realized price  $20.74   $14.12   $6.62    47%
                     
Barrels of oil equivalent (BOE)   154,078    41,778    112,301    269%
Average daily net production (BOE/day)   1,675    459    1,216    265%
Average price per BOE  $34.98   $27.71   $7.27    26%

 

 

   Nine Months Ended September 30,         
   2017   2016   Variance   % 
Product                    
Oil (Bbls)-net production   243,369    44,711    198,658    444%
Oil (Bbls)-average realized price  $45.36   $37.03   $8.33    22%
                     
Natural gas (Mcf)-net production   574,486    183,337    391,148    213%
Natural gas (MCFE)-average realized price  $2.84   $2.37   $0.47    20%
                     
Natural gas liquids (Bbls)-net production   54,743    6,259    48,485    775%
Natural gas liquids (Bbls)-average realized price  $20.23   $14.24   $6.00    42%
                     
Barrels of oil equivalent (BOE)   393,859    81,525    312,334    383%
Average daily net production (BOE/day)   1,443    299    1,144    383%
Average price per BOE  $34.98   $26.74   $8.24    31%

 

 

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The following table compares revenues for the three and nine months ended September 30, 2017 and 2016:

 

   Three Months Ended September 30,         
   2017   2016   Variance   % 
   (In Thousands)         
Revenue:                
Oil  $4,378   $877   $3,501    399%
Natural gas   592    233    359    154%
Natural gas liquids   420    48    372    775%
   $5,390   $1,158   $4,232    365%

 

Total revenue was approximately $5.4 million for the three months ended September 30, 2017 as compared to approximately $1.2 million for the three months ended September 30, 2016, representing an increase of approximately $4.2 million or 365%. The changes were associated primarily with an increase in production from the Delaware Basin wells. Oil revenues increased 399% due to an increase in volumes of 347% and realized price increases of 12%. Natural gas revenues increased 154% due to an increase in volumes of 118% and realized price increases of 17%. NGL revenues increased 775% due to an increase in volumes of 499%, partially offset by realized price decrease of 47%.

 

BOE production during the three months ended September 30, 2017 increased by more than 269% as compared to the three months ended September 2016 due to additional wells completed and in production.

 

   Nine Months Ended September 30,         
   2017   2016   Variance   % 
   (In Thousands)         
Revenue:                    
Oil  $11,040   $1,655   $9,385    567%
Natural gas   1,631    436    1,195    274%
Natural gas liquids   1,108    89    1,019    1,145%
   $13,779   $2,180   $11,599    532%

 

Total revenue was approximately $13.8 million for the nine months ended September 30, 2017 as compared to approximately $2.2 million for the nine months ended September 30, 2016, representing an increase of approximately $11.6 million or 532%. As mentioned above, the increase in revenue is attributed primarily with an increase in production from and an increase in the number of producing Delaware Basin wells. Oil revenues increased 567% due to an increase in volumes of 444% and realized price increases 22%. Natural gas revenues increased 274% due to an increase in volumes of 213% and realized price increases of 20%. NGL revenues increased 1,145% due to an increase in volumes of 775% and realized price increases of 42%.

 

Production during the nine months ended September 30, 2017 increased by more than 383% as compared to the nine months ended September 2016. During the nine months ended September 30, 2017, we completed five wells that have started production.

 

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

 

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

 

   Three Months Ended September 30,         
   2017   2016   Variance   % 
   (In Thousands)         
Production costs per BOE  $11.77   $14.67   $(2.90)   -62%
Production taxes per BOE   1.88    1.46    0.42    29%
Depreciation, depletion, and amortization per BOE   9.36    14.37    (5.01)   -35%
Total operating costs per BOE  $23.01   $30.50   $(7.49)   -25%

 

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   Three Months Ended September 30,         
   2017   2016   Variance   % 
   (In Thousands)         
Costs and expenses:                    
Production costs  $1,814   $613   $1,201    196%
Production taxes   290    61    229    375%
General and administrative   10,943    4,582    6,361    139%
Depreciation, depletion, amortization and accretion   1,443    601    842    140%
Total operating expenses  $14,490   $5,857   $8,633    147%

 

Production Costs

 

Production costs were approximately $1.8 million for the three months ended September 30, 2017, compared to approximately $0.6 million for the three months ended September 30, 2016, an increase of approximately $1.2 million, or 196%. The increase in production costs was primarily due to increased production volumes associated with the producing wells in the Delaware basin during the three months ended September 30, 2017. Production costs per BOE decreased to $11.77 for the three months ended September 30, 2017 from $14.67 for the three months ended September 30, 2016, a decrease of $2.90 per BOE, or 20%. The decrease in production costs per BOE was primarily due to increased production volumes associated with the producing wells in the Delaware basin during the three months ended September 30, 2017, as compared to production volumes associated with the Denver-Julesburg basin and legacy wells.

 

Production Taxes

 

Production taxes were approximately $0.3 million for the three months ended September 30, 2017, compared to approximately $0.06 million for the three months ended September 30, 2016, an increase of approximately $0.2 million, or 375%.  Currently, ad valorem, severance and conservation taxes range from 1% to 13% based on the state and county from which production is derived.  The increase in production taxes corresponds to the increase in production revenues during the three months ended September 30, 2016.

 

General and Administrative Expenses

 

General and administrative expenses were approximately $10.9 million during the three months ended September 30, 2017, compared to approximately $4.6 million during the three months ended September 30, 2016, an increase of approximately $6.4 million, or 139%.  The increase of $6.4 million is primarily attributed to the increase in payroll of approximately $1.8 million due to severance payment made to a former senior executive of approximately $1.1 million, an approximate $2.2 million increase in stock based compensation and an increase of approximately $2.4 million in other general and administrative expenses during the three months ended September 30, 2017. General and administrative expenses for the three months ended September 30, 2017 included stock based compensation expense of $5.1 million as compared to $2.9 million in the comparable period in 2016 and severance payments of $1.1 million which were not incurred in the prior period. For the three months ended September 30, 2017, payroll included approximately $1.4 million of recurring base payroll, and approximately $0.4 million in payroll taxes and other benefits. Excluding severance, stock based compensation and unexpected charges, we expect normal recurring general and administrative expenses to be between $2.5 million and $4.5 million per quarter.

 

Depreciation, Depletion, and Amortization

 

Depreciation, depletion, and amortization (“DD&A”) was approximately $1.4 million during the three months ended September 30, 2017, compared to $0.6 million during the three months ended September 30, 2016, an increase of approximately $0.8 million, or 140%.  Our DD&A rate decreased to $9.37 per BOE during the three months ended September 30, 2017 from $14.39 per BOE during the three months ended September 30, 2016. Our DD&A expense increased primarily due to an increase in volumes produced by 112,301 BOE or 269% from 41,778 BOE during the three months ended September 30, 2016.

 

 36 

 

 

   Nine Months Ended September 30,         
   2017   2016   Variance   % 
   (In Thousands)         
Production costs per BOE  $10.61   $12.00   $(1.39)   -12%
Production taxes per BOE   1.80    1.42    0.38    27%
Depreciation, depletion, and amortization per BOE   10.02    14.26    (4.24)   -30%
Total operating costs per BOE  $22.43   $27.68   $(5.25)   -19%

 

 

   Nine Months Ended September 30,         
   2017   2016   Variance   % 
   (In Thousands)         
Costs and expenses:                    
Production costs  $4,178   $978   $3,200    327%
Production taxes   710    115    595    517%
General and administrative   36,273    9,741    26,532    272%
Depreciation, depletion, amortization and accretion   3,946    1,162    2,784    240%
Total operating expenses  $45,107   $11,996   $33,111    276%

  

Production Costs

 

Production costs were approximately $4.2 million for the nine months ended September 30, 2017, compared to approximately $1.0 million for the nine months ended September 30, 2016, an increase of approximately $3.2 million, or 327%. The increase in production costs was primarily due to increased production volumes associated with the producing wells in the Delaware basin during the nine months ended September 30, 2017. Production costs per BOE decreased to $10.61 for the nine months ended September 30, 2017 from $12.00 for the nine months ended September 30, 2016, a decrease of approximately $1.39 per BOE, or 12%. The decrease in production costs per BOE was primarily due to increased reserves during the nine months ended September 30, 2017. The decrease in production costs per BOE was primarily due to increased production volumes associated with the producing wells in the Delaware basin during the nine months ended September 30, 2017, as compared to production volumes associated with the Denver-Julesburg basin and legacy wells.

 

Production Taxes

 

Production taxes were approximately $0.7 million for the nine months ended September 30, 2017, compared to approximately $0.1 million for the nine months ended September 30, 2016, an increase of approximately $0.6 million, or 517%.  Currently, ad valorem, severance and conservation taxes range from 1% to 13% based on the state and county from which production is derived.  Production taxes per BOE increased to $1.80 per BOE during the nine months ended September 30, 2017 from $1.42 during the nine months ended September 30, 2016. As discussed above, the increase in production taxes corresponds to the increase in production revenues during the nine months ended September 30, 2017.

 

General and Administrative Expenses

 

General and administrative expenses were approximately $36.3 million during the nine months ended September 30, 2017, compared to approximately $9.7 million during the nine months ended September 30, 2016, an increase of approximately $26.5 million, or 272%.  The $26.5 million increase was primarily due to an increase in payroll of approximately $11.5 million, an approximate $10.9 million increase in stock based compensation and an approximate $4.1 million increase in other general and administrative expenses during the nine months ended September 30, 2017. For the nine months ended September 30, 2017, payroll included approximately $4.2 million of recurring base payroll, approximately $7.8 million in bonus payments, approximately $1.1 million in severance pay and approximately $3.2 million in stock based compensation to former executives and approximately $0.9 million in payroll taxes and other benefits.

 

 37 

 

 

Depreciation, Depletion, and Amortization

 

DD&A was approximately $3.9 million during the nine months ended September 30, 2017, compared to approximately $1.2 million during the nine months ended September 30, 2016, an increase of $2.8 million, or 240%.  Our DD&A rate decreased to $10.02 per BOE during the nine months ended September 30, 2017 from $14.26 per BOE during the nine months ended September 30, 2016. The DD&A expense increased primarily due to an increase in volumes produced by 312,334 BOE or 383% from 81,525 BOE during the nine months ended September 30, 2016.

 

   Three Months Ended September 30,         
   2017   2016   Variance   % 
   (In Thousands)         
Other income (expense):                    
Other income (expense)  $151   $51   $100    196%
Inducement expense   -    (3,180)   3,180    100%
Gain on modification of convertible debentures   -    602    (602)   -100%
Change in fair value of derivative instruments   6,368    (438)   6,806    -1554%
Change in fair value of conditionally redeemable 6% preferred stock   -    134    (134)   -100%
Interest expense   (3,656)   (617)   (3,039)   -493%
Total other income (expense)  $2,863   $(3,448)  $6,311    183%

 

Interest Expense

 

Interest expense for the three months ended September 30, 2017 was approximately $3.7 million compared to $0.6 million, for the three months ended September 30, 2016. For the three months ended September 30, 2017, we incurred interest expense of approximately $0.3 million for quarterly interest payments on notes payable and term loans, approximately $1.9 million of paid-in-kind interest and approximately $1.4 million of amortized debt issuance costs associated with the $15 million drawn under the Bridge Loan and debt discount associated with the $80 million drawn under the Second Lien Term Loan. During the three months ended September 30, 2016, we incurred approximately $0.1 million of interest expense and approximately $0.5 million of non-cash interest relating to amortized debt issuance costs on debentures and convertible notes. 

 

Change in Fair Value of Derivative Instruments

 

The change in fair values of derivative instruments comprised a gain of approximately $6.4 million during the three months ended September 30, 2017, as compared to a loss of approximately $0.4 million during the three months ended September 30, 2016, and is as follows:

 

  · Second Lien Term Loan Derivative Liability.  On April 26, 2017, we entered into the Second Lien Term Loan, which included a make-whole premium and a conversion feature, which is required to be recorded as an embedded derivative and bifurcated from its host contract. These features are therefore recorded as a derivative liability at fair value each reporting period based upon values determined through the use of the discounted lattice model. On April 26, 2017, the embedded derivatives were recorded as a derivative liability at a fair value of approximately $36.7 million and approximately $39.6 million as of June 30, 2017.   As of September 30, 2017, the fair value of the embedded derivatives was $33.3 million.  As a result, the Company recorded an unrealized gain of $6.3 million recorded for the three months ended September 30, 2017.

 

  · SOSV Investments LLC Warrant Liability. On June 23, 2016, in conjunction with the merger with Brushy in June 2016, we issued to SOSV Investments LLC (“SOS”) a warrant to purchase up to 200,000 shares of our common stock at an exercise price of $25.00. The warrant contains a price protection feature that will automatically reduce the exercise price if we enter into another agreement pursuant to which warrants are issued with a lower exercise price. For the three months ended September 30, 2017 and 2016, we recorded an unrealized gain in the fair value of the derivative liability related to the warrant of approximately $0.1 million and an unrealized loss of $0.3 million, respectively.

 

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Inducement Expense

 

During the three months ended September 30, 2016, inducement expense of approximately $3.2 million was incurred as a result of debt and equity restructuring in connection with the Brushy merger. There was no inducement expense incurred during the three months ended September 30, 2017.

 

   Nine Months Ended September 30,         
   2017   2016   Variance   % 
   (In Thousands)         
Other income (expense):                    
Other income  $19   $297   $(278)   -94%
Gain on modification of convertible debentures   -    602    (602)   -100%
Inducement expense   -    (8,307)   8,307    -100%
Change in fair value of derivative instruments   4,295    (535)   4,830    -903%
Change in fair value of conditionally redeemable 6% preferred stock   (41)   (644)   603    -94%
Interest expense   (11,084)   (4,220)   (6,864)   163%
Total other income (expense)  $(6,811)  $(12,807)  $5,996    47%

 

Interest Expense

 

Interest expense for the nine months ended September 30, 2017 was approximately $11.1 million compared to approximately $4.2 million, for the nine months ended September 30, 2016. For the nine months ended September 30, 2017, we incurred interest expense of approximately $1.1 million for quarterly interest payments on notes payable and term loans, approximately $3.3 million of paid-in-kind interest and approximately $6.7 million of amortized debt issuance costs for the First Lien Term Loan, Bridge Loan and the Second Lien Term Loan as compared to the nine months ended September 30, 2016, when we incurred approximately $1.2 million of interest expense and approximately $3.9 million of non-cash interest relating to amortized debt issuance costs on debentures, convertible notes and non-convertible notes.

  

Change in Fair Value of Derivative Instruments

 

The change in fair values of derivative instruments comprised a gain of approximately $4.3 million during the nine months ended September 30, 2017, as compared to a loss of approximately $0.5 million during the nine months ended September 30, 2016, and is as follows:

 

  · Second Lien Term Loan Derivative Liability. On April 26, 2017, we entered into the Second Lien Term Loan, which included a make-whole premium and a conversion feature, which is required to be recorded as an embedded derivative and bifurcated from its host contract. These features are therefore recorded as a derivative liability at fair value each reporting period based upon values determined through the use of the discounted lattice model. On April 26, 2017, the embedded derivatives were recorded as a derivative liability at a fair value of approximately $36.7 million and approximately $39.6 million as of June 30, 2017.   As of September 30, 2017, the fair value of the embedded derivatives was $33.3 million.  As a result, we recorded an unrealized gain of $3.5 million recorded for the nine months ended September 30, 2017.

 

  · Heartland Warrant Liability. On January 8, 2015, we entered into the Heartland Credit Agreement. In connection with the Heartland Credit Agreement, we issued a warrant to purchase up to 22,500 shares of our common stock at an exercise price of $25.00. The warrant contained a price protection feature that would have automatically reduced the exercise price if we entered into another agreement pursuant to which warrants were issued with a lower exercise price and would also have triggered an adjustment to the number of underlying shares of common stock. On June 14, 2017, we and Heartland executed an amended and restated warrant agreement whereby we issued a warrant to purchase 160,714 of common stock at an exercise price of $3.50 to replace the original warrant to purchase 22,500 shares of common stock previously issued on January 8, 2015 to settle a disagreement regarding the fair value change pursuant to the anti-dilution provisions in the original warrant. The amended and restated warrant agreement no longer contains the same anti-dilution provisions. As a result of the reissuance of the warrants, we recorded approximately $0.04 million realized gain and approximately $0.04 million unrealized loss on the Heartland warrant liability during the nine months ended September 30, 2017 and 2016, respectively.

 

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  · SOS Warrant Liability. On June 23, 2016, in conjunction with the merger with Brushy in June 2016, we issued to SOS a warrant to purchase up to 200,000 shares of our common stock at an exercise price of $25.00. The warrant contains a price protection feature that will automatically reduce the exercise price if we enter into another agreement pursuant to which warrants are issued with a lower exercise price. For the nine months ended September 30, 2017 and 2016, we incurred an unrealized gain in fair value of the derivative liability related to the warrant of approximately $0.05 million and approximately $0.3 million, respectively.
     
  · Bristol Warrant Liability. On September 2, 2014, we entered into a consulting agreement with Bristol Capital, LLC (“Bristol”), pursuant to which we issued Bristol a warrant to purchase up to 100,000 shares of our common stock at an exercise price of $20.00 (or, in the alternative, options exercisable for 100,000 shares of common stock, but in no case, both). The agreement had a price protection feature that automatically reduced the exercise price of the warrant if we entered into another consulting agreement pursuant to which warrants were issued with a lower exercise price, which was triggered in year 2016.  On March 14, 2017, we issued 77,131 shares of common stock to Bristol pursuant to a settlement agreement for a cashless exercise of the warrant.  The Bristol warrant was also revalued on March 14, 2017 resulting in a realized gain in fair value of $0.8 million for the nine months ended September 30, 2017 and decreasing the Bristol derivative liability to $0.4 million.   As a result of the cashless exercise, we reclassified the $0.4 million of Bristol derivative liability to additional paid-in capital as of March 31, 2017.  For the nine months ended September 30, 2016, we recorded approximately $0.2 million of unrealized loss on the Bristol warrant.

 

Inducement Expense

 

During the nine months ended September 30, 2016, inducement expense of approximately $8.3 million was incurred as a result of debt and equity restructuring in connection with the Brushy merger. There was no inducement expense incurred during the nine months ended September 30, 2017.

 

 

Liquidity and Capital Resources

 

Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions and investors, the sale of equity and equity derivative securities and asset dispositions. Our primary uses of capital have been for the acquisition, development, exploration and exploitation of oil and natural gas properties, in addition to refinancing of debt instruments.

 

Based upon current commodity price expectations for 2017 and 2018, we believe that our cash flow from operations, in addition to financing activity that occurred subsequent to September 30, 2017 (see Note 12 – Subsequent Events), will be sufficient to fund our drilling and completion operations over the next 12 months, including working capital requirements.  However, our Board has not approved an operational capital expenditure program for the year ending December 31, 2018. In addition, future cash flows are subject to a number of variables, including uncertainty in forecasted production volumes and commodity prices.  We are the operator for 100% of our 2017 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 nine months ended September 30, 2017 and 2016 are presented in the following table ($ in thousands):

  

   Nine Months Ended September 30, 
   2017   2016 
Cash provided by (used in):          
Operating activities  $(7,610)  $(6,517)
Investing activities   (63,689)   (3,970)
Financing activities   77,381    31,366 
Net change in cash  $6,082   $20,879 

 

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Operating activities. For the nine months ended September 30, 2017, net cash used in operating activities was $7.6 million, compared to $6.5 million for the same period in 2016. The increase of $1.1 million in cash used in operating activities was primarily attributable to the increase in operating costs, which corresponds with higher producing activities and supporting general and administrative costs.

  

Investing activities. For the nine months ended September 30, 2017, net cash used in investing activities was $63.7 million compared to $4.0 million for the same period in 2016. The $62.4 million in cash used in investing activities was primarily attributable to the following:

 

  · A $39.7 million increase in drilling and completion costs on the six wells of which five were completed in the Delaware Basin during the nine months ended September 30, 2017. There were minimal drilling activities in the DJ Basin during the nine months ended September 30, 2016;

 

  · A $2.2 million increase in workover costs associated with producing wells;
     
  · A $23.1 million increase in acquisition of additional working interests on leases of which $15.5 million related to leases in Winkler and Lea Counties, Texas and $7.6 million related to leases in Reeves County, Texas; and

 

  · Offset by net proceeds of $1.3 million received from the divestiture of the DJ Basin properties and non-operated properties.

 

Financing activities. For the nine months ended September 30, 2017, net cash provided by financing activities was $77.4 million compared to cash provided by financing activities of $31.4 million during the same period in 2016. The $77.4 million in net cash provided by financing activities included the following:

 

  · $14.7 million increase in net proceeds from the Bridge Loan under the amended First Lien Term Loan financing transactions;

 

  · $80.0 million increase in net proceeds from the Second Lien Term Loan financing transactions;

 

  · $0.4 million of proceeds from the exercise of warrants and stock options;

 

  · $18.4 million of proceeds from the March 2017 Private Placement, net of financing costs; and

 

  ·

$6.7 million of proceeds from exercise of accordion features under the First Lien Term Loan, net of financing costs.

 

Offset by:

 

  · $2.3 million repayment of conditionally redeemable 6% preferred stock including dividends;

 

  · $38.1 million repayment of the First Lien Term Loan; and

 

  · $2.4 million relating to payment of tax withheld on stock based compensation

 

Off-Balance Sheet Arrangements

 

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

 

Recently Issued Accounting Pronouncements

 

For a discussion of recently issued accounting pronouncements see Note 2 – “Summary of Significant Accounting Policies and Estimates” to our condensed consolidated financial statements in Item 1 of this Quarterly Report.

 

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Subsequent Events

 

Lease Acquisition Agreement

 

On October 3, 2017, we entered into a lease acquisition agreement (the “Acquisition Agreement”) with KEW Drilling, a Delaware limited partnership (“KEW”), pursuant to which we will acquire from KEW undeveloped net acres in Winkler County, Texas for an aggregate purchase price of up to $47.0 million for additional pursuant to the terms set forth in the Acquisition Agreement (collectively, the “Leases”). If KEW acquires additional acreage during the time period between the execution of the Acquisition Agreement until closing that exceeds the $47.0 million aggregate purchase price threshold (calculated on a per-net-acre basis), we have the option, but not the obligation, to acquire any additional oil and natural gas leases that are acquired by KEW that meet the specifications set forth in the Acquisition Agreement.

 

The Acquisition Agreement contains terms and conditions customary to transactions of the type including title due diligence provisions and representations and warranties regarding the Leases, including, but not limited to, those regarding taxes, liens, litigation, preferential rights to purchase and consents.

 

We expect to fund the purchase price for the Leases with borrowings under the Delayed Draw Term Loans available pursuant to its Second Lien Credit Agreement and cash on hand, which includes proceeds drawn under the First Lien Credit Agreement as described below.

 

On November 9, 2017, we closed on the initial settlement of approximately 3,200 net acres in Winkler County, Texas for approximately $35.8 million and expect to complete the close of the remaining net acreage in early December 2017.

  

Amendment No. 1 to Second Lien Credit Agreement

 

On October 3, 2017, 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 the Lead Lender, 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 $45.0 million Delayed Draw Term Loans under the Second Lien Credit Agreement and to provide for the funding of such Delayed Draw Term Loans upon the signing of the Acquisition Agreement. We borrowed the full $45.0 million of the availability under the Delayed Draw Terms Loans on October 4, 2017.

 

Pursuant to Amendment No. 1 to the Second Lien Credit Agreement, if we do not use any portion of the Delayed Draw Term Loans for the acquisitions contemplated by the Acquisition Agreement or such other acquisitions as may be approved by the Lead Lender within a specified time period ending not later than January 10, 2018, we will be required to prepay such unused portion of the Delayed Draw Term Loans, together with accrued and unpaid interest and a prepayment premium equal to a 20% annualized rate on such amount (but without the make-whole amount otherwise payable on repayment of loans under the Second Lien Credit Agreement), within two business days after the end of such specified period. Any portion of the Delayed Draw Term Loans so repaid may be later re-borrowed by the Company, subject to the terms of the Second Lien Credit Agreement. The Delayed Draw Term Loan was drawn in full on October 4, 2017.

 

Amendment No. 4 to the First Lien Credit Agreement

 

On October 19, 2017, we entered into a fourth amendment to the First Lien Credit Agreement (“Amendment No. 4 to the First Lien Credit Agreement”). Pursuant to the Amendment No. 4 to the First Lien Credit Agreement, among other things, certain lenders identified therein joined the existing lenders as lenders under the First Lien Credit Agreement, and the lenders made further extensions of credit, in addition to the currently existing loans under the First Lien Credit Agreement (the “Existing Bridge Loans”), in the form of an additional, incremental bridge loan in an aggregate principal amount of $15,000,000 (the “Incremental Bridge Loan”, and together with the Existing Bridge Loans, the “First Lien Loans”). The First Lien Loans, including the Incremental Bridge Loan, were fully drawn as of October 19, 2017.

 

The First Lien Credit Agreement, as amended by the Amendment No 4. to the First Lien Credit Agreement, (a) provides that, effective as of October 1, 2017, the unpaid principal of the First Lien Loans will bear (i) cash interest at a rate per annum of 10% and (ii) additional interest at a rate per annum of 6%, payable only in-kind by increasing the principal amount of the First Lien Loans by the amount of such interest due on each interest payment date and (b) permits the loans under the Second Lien Credit Agreement to equal an increased amount of up to $175,000,000. The First Lien Loans mature on October 21, 2018 and may be repaid in whole or part at any time at our option, subject to the payment of certain specified prepayment premiums. Additionally, the First Lien Loans are subject to mandatory prepayment with the net proceeds of certain asset sales and casualty events, subject to our right to reinvest the net proceeds of asset sales and casualty events within 180 days.

 

Amendment No. 2 to the Second Lien Credit Agreement 

 

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

 

Amendment No. 3 to the Second Lien Credit Agreement

 

On November 10, 2017, we entered into a third amendment to the Second Lien Credit Agreement (“Amendment No. 3 to the Second Lien Credit Agreement”), by and among us, the Guarantors, the Agent and the Lenders, including the Lead Lender. Amendment No. 3 to the Second Lien Credit Agreement increased by $25 million the amount of delayed draw term loans available for borrowing under the Second Lien Credit Agreement. As previously disclosed, in October 2017, we borrowed the full $45 million of Delayed Draw Term Loans available under the Second Lien Credit Agreement prior to Amendment No. 3 to the Second Lien Credit Agreement. The additional $25.0 million of delayed draw term loans is undrawn as of November 14, 2017 and will be available for borrowing by us in one or more drawings of $5.0 million or more from time to time on or before February 28, 2019, subject to certain conditions. Proceeds of the additional loans may be used to fund oil and gas property acquisitions, subject to certain limitations, or drilling and completions costs or for other general corporate purposes.

 

 42 

 

 

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

 

Not applicable

 

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 September 30, 2017 as the changes described below are still being evaluated.  

 

Changes in Internal Control over Financial Reporting

 

The Company made significant changes and improvements in internal control over financial reporting as its remediation plan will address the material weakness disclosed in our previous filing. Specifically, the following measures were implemented to remediate the material weakness related to accounting for complex transactions, namely: use of comprehensive checklists to identify and review complex accounting issues, additional guidance obtained from an expert accounting technical consultant with respect to the appropriate application of GAAP on non-routine and complex transactions. Management believes these changes should be sufficient to remediate the material weakness previously identified. However, management is continuing to validate the operating effectiveness of these new controls over an appropriate period of time prior to concluding that the material weakness has been remediated.

 

There were no other changes in our internal control over financial reporting during our most recent fiscal quarter that materially affected, or were reasonably likely to materially affect, our internal control over financial reporting.

 

 

PART II - OTHER INFORMATION

 

ITEM 1. LEGAL PROCEEDINGS.

 

None

 

ITEM 1A. RISK FACTORS.

 

We are a smaller reporting company as defined by Rule 12b-2 under the Exchange Act and are not required to provide the information under this item. 

 

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ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

 

None, except as previously disclosed in our Current Reports on Form 8-K.

 

ITEM 4. MINE SAFETY DISCLOSURES

 

 

ITEM 5. OTHER INFORMATION

 

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ITEM 6. EXHIBITS.

 

Exhibit
Number
  Exhibit Description
2.1*   Lease Acquisition Agreement, dated October 3, 2017 by and among the Company and KEW Drilling.

3.1

 

Amended and Restated Articles of Incorporation of Recovery Energy, Inc., dated as of October 10, 2011 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on October 20, 2011).

3.2   Certificate of Amendment to the Amended and Restated Articles of Incorporation of Recovery Energy, Inc., dated as of November 18, 2013 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on November 19, 2013).
3.3   Certificate of Amendment to the Company’s Articles of Incorporation (incorporated herein by reference to Annex A of the Company’s Definitive Proxy Statement on Schedule 14A, filed on June 19, 2017)
3.4   Certificate of Designation of Preferences, Rights, and Limitations of Series A 8% Convertible Preferred Stock, dated as of May 30, 2014 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 4, 2014).
3.5   Amendment to Certificate of Designation of Preferences, Rights, and Limitations of Series A 8% Convertible Preferred Stock, dated as of June 12, 2014 (incorporated herein by reference to Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, filed on June 17, 2014).
3.6   Certificate of Designation of Preferences, Rights and Limitations of 6% Redeemable Preferred Stock, dated as of August 29, 2014 (incorporated herein by reference to Exhibit 3.3 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2014, filed on November 26, 2014).
3.7   Certificate of Designation of Preferences, Rights and Limitations of Series B 6% Convertible Preferred Stock, dated as of June 15, 2016 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 16, 2016).
3.8   Certificate of Change of Lilis Energy, Inc., dated as of June 21, 2016 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 28, 2016).
3.9   Amended and Restated Certificate of Designations of Preferences, Rights and Limitations of Series B 6% Convertible Preferred Stock, dated April 25, 2017 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on April 27, 2017).
3.10   Amended and Restated Bylaws (incorporated herein by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed on June 18, 2010).
10.1   Third Amendment to Credit and Guarantee Agreement, dated July 25, 2017 by and among the Company, Brushy Resources, Inc., ImPetro Operating, LLC, ImPetro Resources, LLC, Lilis Operating Company, LLC, the Lenders party thereto and Deans Knight Capital Management Ltd., as collateral agent (incorporated herein by reference to Exhibit 10.3 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2017 filed on August 14, 2017).
10.2   Second Amendment to the Company’s 2016 Omnibus Incentive Plan, dated July 13, 2017 (incorporated herein by reference to Annex A of the Company’s Definitive Proxy Statement on Schedule 14A, filed on June 19, 2017).
10.3†   Separation and Consulting Agreement, dated August 3, 2017, by and between Lilis Energy, Inc. and Abraham Mirman (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on August 4, 2017)
10.4†   First Amendment of Executive Employment Agreement, dated August 4, 2017, by and between Lilis Energy, Inc. and Jim Linville (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on August 4, 2017)
10.5*   Gas Gathering, Processing and Purchase Agreement, dated August 10, 2017 by and among the Company and Lucid Energy Delaware. Specific items in this exhibit have been redacted, as marked by two asterisks (**), because confidential treatment for those items has been requested. The redacted material has been separately filed with the SEC.
10.6   Letter Agreement dated August 12, 2017 between the Company and Värde Partners, Inc. (incorporated herein by reference to Exhibit 10.14 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2017 filed on August 14, 2017)
10.7   Amendment No. 1 to Second Lien Credit Agreement, dated October 3, 2017 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 10.1 to the Company’s Current Report on Form 8-K filed on October 3, 2017).
10.8   Amendment No. 4 and Joinder to Credit and Guarantee Agreement, dated October 19, 2017 by and among the Company, the Guarantors party thereto, the Lenders party thereto and Deans Knight Capital Management Ltd., as collateral agent (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 24, 2017).
10.9   Amendment No. 2 to Second Lien Credit Agreement, dated October 19, 2017 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 10.2 to the Company’s Current Report on Form 8-K filed on October 24, 2017).
10.10   Amendment No. 3 to Second Lien Credit Agreement, dated November 10, 2017 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 10.1 to the Company’s Current Report on Form 8-K filed on November 14, 2017).

  

 45 

 

 

Exhibit
Number
  Exhibit Description
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 Schema
101.CAL*   XBRL Taxonomy Calculation Linkbase
101.DEF*   XBRL Taxonomy Definition Linkbase
101.LAB*   XBRL Taxonomy Label Linkbase
101.PRE*   XBRL Taxonomy Presentation Linkbase

  

* Filed herewith
Indicates management contract or compensatory plan.

 

 46 

 

 

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.

 

Signature   Title   Date
         
By: /s/ James (Jim) L. Linville   Chief Executive Officer   November 14, 2017
  James (Jim) L. Linville   (Principal Executive Officer)    
         
By: /s/ Joseph C. Daches   Executive Vice President, Chief Financial Officer and Treasurer   November 14, 2017
  Joseph C. Daches   (Principal Financial and Accounting Officer)    

 

 47 

 

 

EXHIBIT INDEX

 

Exhibit
Number
  Exhibit Description
2.1*   Lease Acquisition Agreement, dated October 3, 2017 by and among the Company and KEW Drilling.

3.1

 

Amended and Restated Articles of Incorporation of Recovery Energy, Inc., dated as of October 10, 2011 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on October 20, 2011).

3.2   Certificate of Amendment to the Amended and Restated Articles of Incorporation of Recovery Energy, Inc., dated as of November 18, 2013 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on November 19, 2013).
3.3   Certificate of Amendment to the Company’s Articles of Incorporation (incorporated herein by reference to Annex A of the Company’s Definitive Proxy Statement on Schedule 14A, filed on June 19, 2017)
3.4   Certificate of Designation of Preferences, Rights, and Limitations of Series A 8% Convertible Preferred Stock, dated as of May 30, 2014 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 4, 2014).
3.5   Amendment to Certificate of Designation of Preferences, Rights, and Limitations of Series A 8% Convertible Preferred Stock, dated as of June 12, 2014 (incorporated herein by reference to Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, filed on June 17, 2014).
3.6   Certificate of Designation of Preferences, Rights and Limitations of 6% Redeemable Preferred Stock, dated as of August 29, 2014 (incorporated herein by reference to Exhibit 3.3 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2014, filed on November 26, 2014).
3.7   Certificate of Designation of Preferences, Rights and Limitations of Series B 6% Convertible Preferred Stock, dated as of June 15, 2016 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 16, 2016).
3.8   Certificate of Change of Lilis Energy, Inc., dated as of June 21, 2016 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 28, 2016).
3.9   Amended and Restated Certificate of Designations of Preferences, Rights and Limitations of Series B 6% Convertible Preferred Stock, dated April 25, 2017 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on April 27, 2017).
3.10   Amended and Restated Bylaws (incorporated herein by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed on June 18, 2010).
10.1   Third Amendment to Credit and Guarantee Agreement, dated July 25, 2017 by and among the Company, Brushy Resources, Inc., ImPetro Operating, LLC, ImPetro Resources, LLC, Lilis Operating Company, LLC, the Lenders party thereto and Deans Knight Capital Management Ltd., as collateral agent (incorporated herein by reference to Exhibit 10.3 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2017 filed on August 14, 2017).
10.2   Second Amendment to the Company’s 2016 Omnibus Incentive Plan, dated July 13, 2017 (incorporated herein by reference to Annex A of the Company’s Definitive Proxy Statement on Schedule 14A, filed on June 19, 2017).
10.3†   Separation and Consulting Agreement, dated August 3, 2017, by and between Lilis Energy, Inc. and Abraham Mirman (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on August 4, 2017)
10.4†   First Amendment of Executive Employment Agreement, dated August 4, 2017, by and between Lilis Energy, Inc. and Jim Linville (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on August 4, 2017)
10.5*   Gas Gathering, Processing and Purchase Agreement, dated August 10, 2017 by and among the Company and Lucid Energy Delaware. Specific items in this exhibit have been redacted, as marked by two asterisks (**), because confidential treatment for those items has been requested. The redacted material has been separately filed with the SEC.
10.6   Letter Agreement dated August 12, 2017 between the Company and Värde Partners, Inc. (incorporated herein by reference to Exhibit 10.14 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2017 filed on August 14, 2017)
10.7   Amendment No. 1 to Second Lien Credit Agreement, dated October 3, 2017 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 10.1 to the Company’s Current Report on Form 8-K filed on October 3, 2017).
10.8   Amendment No. 4 and Joinder to Credit and Guarantee Agreement, dated October 19, 2017 by and among the Company, the Guarantors party thereto, the Lenders party thereto and Deans Knight Capital Management Ltd., as collateral agent (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 24, 2017).
10.9   Amendment No. 2 to Second Lien Credit Agreement, dated October 19, 2017 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 10.2 to the Company’s Current Report on Form 8-K filed on October 24, 2017).
10.10   Amendment No. 3 to Second Lien Credit Agreement, dated November 10, 2017 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 10.1 to the Company’s Current Report on Form 8-K filed on November 14, 2017).

 

 48 

 

 

Exhibit
Number
  Exhibit Description
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 Schema
101.CAL*   XBRL Taxonomy Calculation Linkbase
101.DEF*   XBRL Taxonomy Definition Linkbase
101.LAB*   XBRL Taxonomy Label Linkbase
101.PRE*   XBRL Taxonomy Presentation Linkbase

 

* Filed Herewith
Indicates management contract or compensatory plan.

 

 49 

Exhibit 2.1

 

 

 

Execution Version

 

 

 

 

 

 

lEASE ACQUISITION AGREEMENT

 

between

 

LILIS ENERGY, INC., as Buyer

 

and

 

KEW DRILLING, as Seller

 

 

 

dated as of OCTOBER 3, 2017

 

 

 

 

 

 

 

 

 

 

 

lEASE ACQUISITION AGREEMENT

 

This Lease Acquisition Agreement (this “Agreement”), dated as of October 3, 2017 (the “Execution Date”), is among Lilis Energy, Inc., a Nevada corporation (“Buyer”), whose address is 300 E. Sonterra Blvd., Suite 1220, San Antonio, Texas 78258, and KEW Drilling, a Delaware limited partnership (“Seller”), whose address is 4925 Greenville Avenue, Suite 500, Dallas, Texas 75206. Buyer and each Seller may sometimes be referred to individually as a “Party,” and collectively, the “Parties.”

 

Recitals

 

WHEREAS, Seller presently owns certain oil and gas leases located in Winkler County, Texas covering approximately 16,209 gross acres and 4,051 Net Acres described on Schedule A; and

 

WHEREAS, Seller desires to sell and Buyer desires to purchase all of the right title and interest in the oil and gas leases and lands listed on Schedule A, upon the terms and conditions set forth in this Agreement;

 

NOW WHEREFORE, in consideration of the mutual promises contained herein and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, Buyer and Seller agree as follows:

 

ARTICLE 1
DEFINITIONS

 

As used herein the terms “Agreement,” “Execution Date,” “Buyer”, “Seller,” “Party” and “Parties” shall have the meanings assigned thereto above, and the following terms shall have the following meanings:

 

Additional Lease Cutoff Date” means the date that is ten (10) Business Days after the Initial Closing Date.

 

Additional Leases” means those oil and gas leases which Seller has not acquired as of the Execution Date, but to which Seller acquires record title on or prior to the Additional Lease Cutoff Date, to the extent, and only to the extent, (a) such oil and gas leases cover lands located within any governmental sections set forth on Schedule D, and (b) such oil and gas leases are in substantially the form of Schedule E or are otherwise expressly approved by Buyer; provided, however, that notwithstanding anything herein to the contrary, with respect to any oil and gas lease which meets the requirements set forth in the foregoing clause, but, at the time such oil and gas lease is acquired, it causes the sum of: (i) the aggregated Allocated Values of the Leases, plus (ii) the aggregated Allocated Values of the Additional Leases, plus (iii) any upward adjustments under Section 3.2A to exceed an amount equal to Forty-Seven Million ($47,000,000), such oil and gas lease shall be deemed an “Optional Additional Lease” hereunder.

 

 1 

 

 

Affiliate” means with respect to a designated Person, any Person which, directly or indirectly, controls, or is controlled by or is under common control with, such designated Person. For purposes of this definition, “control” (including, with correlative meanings, the terms “controlled by” and “under common control with”), as used with respect to any Person, shall mean the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of such Person, whether through the ownership of voting securities or by contract or otherwise. A Person conclusively will be deemed to control another Person if it owns 50% or more of the equity in, or voting power of, such Person.

 

Allocated Value” with respect to a Lease shall mean (a) the number of Net Acres set forth in Schedule A for such Lease (or, with respect to Additional Leases, on the schedule referenced in Section 11.2B or in the disclosure referenced in Section 12.4B, as applicable), multiplied by (b) the Per Net Acre Price.

 

Assets” has the meaning assigned thereto in Section 2.1.

 

Assignment and Conveyance” means an Assignment and Conveyance of substantially the form attached hereto as Schedule C.

 

Business Days” means any day other than a Saturday, Sunday or a day on which national banks are allowed by the Federal Reserve to be closed; and “days,” without further qualification, means calendar days.

 

Closing Amount” has the meaning assigned thereto in Section 3.2.

 

Code” means the Internal Revenue Code of 1986, as amended, or any successor statute.

 

Cure Period” has the meaning assigned thereto in Section 5.6.

 

Defect Notice Date” has the meaning assigned thereto in Section 5.5.

 

Defect Value” has the meaning assigned thereto in Section 5.4.

 

Defensible Title” as the meaning assigned thereto in Section 5.1.

 

Designated NRI” means an NRI of 75% with respect to the Leases.

 

Effective Date” means September 1, 2017

 

Hydrocarbons” means all oil, gas, condensate, casinghead gas, plant products and other hydrocarbons and products.

 

Initial Closing” has the meaning assigned thereto in Section 11.1.

 

Lands” means the lands described on Schedule A.

 

Leases” means the oil and gas leases described in Schedule A. Except where expressly treated otherwise, the Additional Leases shall be considered Leases hereunder in all respects.

 

Net Acres” means, as to each Lease, (a) the number of acres of land that are covered by such Lease (i.e., gross acres), multiplied by (b) the lessor’s undivided mineral interests in the lands covered by such Lease, multiplied by (c) Seller’s undivided interest in the leasehold estate created by such Lease.

 

 2 

 

 

Net Revenue Interest” or “NRI” means, with respect to a Lease, the lessee’s interest in and to all production of Hydrocarbons produced, saved and sold under and pursuant to such Lease after accounting for all royalties, overriding royalties and other burdens upon the working interest created by such Lease.

 

Optional Additional Lease” means an oil and gas lease which meets the requirements of an “Additional Lease”, but, at the time such oil and gas lease is acquired, it causes the sum of: (i) the aggregated Allocated Values of the Leases, plus (ii) the aggregated Allocated Values of the Additional Leases, plus (iii) any upward adjustments under Section 3.2A to exceed an amount equal to Forty-Seven Million ($47,000,000). For the sake of clarity, the last oil and gas lease to be acquired by Seller shall be the first to be designated as an “Optional Additional Lease” and such designation shall continue in reverse chronological order until such time as the sum of items (i) through (iii) above is less than or equal to Forty-Seven Million Dollars ($47,000,000).

 

ORRI Assignment” shall have the meaning set forth in Section 8.1.

 

Outstanding Title Defect” has the meaning assigned thereto in Section 5.7.

 

Per Net Acre Price” means Eleven Thousand Two Hundred Seventy-Five and No/100 Dollars ($11,275.00) per Net Acre for all of the Leases.

 

Permitted Encumbrances” has the meaning assigned thereto in Section 5.2.

 

Person” means any individual, governmental agency, corporation, limited liability company, partnership, joint venture, trust, estate, unincorporated organization or other entity or organization.

 

Post-Closing Cure Period” has the meaning assigned thereto in Section 5.8.

 

Property Taxes” means all federal, state or local Taxes, assessments, levies or other charges, which are imposed upon the Assets, including ad valorem, property, documentary or stamp, as well as any interest, penalties and fines assessed or due in respect of any such Taxes, whether disputed or not.

 

Purchase Price” has the meaning assigned thereto in Section 3.1

 

Records” has the meaning assigned thereto in Subsection 2.1.D.

 

Seller’s Warranties” has the meaning assigned thereto in Section 14.16.

 

Settlement Statement” has the meaning assigned thereto in Section 3.2.

 

Severance Taxes” means all federal, state or local Taxes, assessments, levies or other charges, which are imposed upon production from the Assets, including excise Taxes on production, severance or gross production, as well as any interest, penalties and fines assessed or due in respect of any such Taxes, whether disputed or not.

 

 3 

 

 

Special Warranty” means a warranty of title whereby the assignor agrees to warrant and forever defend the title of the assignee against all defects, encumbrances, liens, security interests and claims created by, through or under the assignor, but not otherwise.

 

Subsequent Closing” has the meaning assigned thereto in Section 12.4.

 

Subsequent Closing Date” has the meaning assigned thereto in Section 12.4.

 

Taxes” means mean any and all taxes, levies or other like assessments, including but not limited to income tax, franchise tax, profits tax, windfall profits tax, surtax, gross receipts tax, capital gains tax, remittance tax, withholding tax, sales tax, use tax, value added tax, goods and services tax, presumptive tax, net worth tax, special contribution, production tax, pipeline transportation tax, severance tax, excise tax, ad valorem tax, property tax (real, personal or intangible), inventory tax, transfer tax, premium tax, environmental tax (including taxes under Section 59A of the Code), customs duty, stamp tax or duty, capital stock tax, margin tax, occupation tax, payroll tax, employment tax, social security tax, unemployment tax, disability tax, alternative or add-on minimum tax, estimated tax, and any similar tax or assessment imposed by any Governmental Authority or other taxing authority, together with any interest, fine or penalty, or addition thereto, whether disputed or not.

 

Title Defect” has the meaning assigned thereto in Section 5.3.

 

Title Defect Value” has the meaning assigned thereto in Section 5.5.

 

Title Disputed Matters” has the meaning assigned thereto in Section 5.9.

 

Transfer Tax” has the meaning assigned thereto in Section 13.1.

 

ARTICLE 2
PURCHASE AND SALE

 

2.1       Purchase and Sale. Subject to the terms and conditions of this Agreement, Buyer agrees to purchase from Seller and Seller agrees to sell, assign and deliver to Buyer the following (the “Assets”):

 

A.       The Leases.

 

B.       Without limitation of the foregoing, excluding the overriding royalty interests to be conveyed by the ORRI Assignment, and any mineral fee or royalty interests owned of record by Seller as of the Initial Closing Date or Subsequent Closing Date, as applicable, all other right, title and interest (of whatever kind or character, whether legal or equitable, and whether vested or contingent) of Seller in and to the oil, gas and other minerals in and under or that may be produced from the lands covered by the Leases whether such lands be described in a description of the Leases set forth on such Schedule A, or be described in such Schedule A by reference to another instrument.

 

 4 

 

 

C.       All right, title and interest of Seller in and to all easements, rights-of-way, surface leases and other surface rights, all permits and licenses being used or held for use in connection with, or otherwise related to, the properties described in paragraphs A. and B. above, if any.

 

D.       The files, records, data and information relating to the Leases and in the control or the possession of Seller (the “Records”), including, but not limited to, copies of Lease files, land files, run sheets, mineral take-offs, abstracts and title opinions.

 

E.       All rights, claims and causes of action (including, but not by way of limitation, claims for adjustments or refunds) to the extent attributable to all obligations with respect to the properties described in items A. through D. above to be assumed by Buyer, or for which Buyer is otherwise responsible under this Agreement.

 

2.2       Effective Date. The assignment and delivery of the Assets shall be effective as of the Effective Date.

 

ARTICLE 3
PURCHASE PRICE

 

3.1       Purchase Price. The purchase price for the Assets to be delivered at the Initial Closing, subject to the adjustments in Section 3.2, below, shall be $45,675,025 (the “Purchase Price”), which is the product of (i) 4,051 (the number of Net Acres covered by the Leases as represented in Schedule A, less the Additional Leases), multiplied by (ii) the Per Net Acre Price.

 

3.2       Adjustments to Purchase Price. The Purchase Price attributable to the Assets to be transferred at such Closing shall be adjusted according to this Section 3.2 (without duplication) as follows:

 

 

A.       Upward Adjustments. If Seller can demonstrate to Buyer’s reasonable satisfaction by the Defect Notice Date that the Net Acres covered by a Lease exceeds the aggregate number of Net Acres set forth in Schedule A for such Lease, the Purchase Price shall be adjusted upward by an amount equal to the number of Net Acres covered by a Lease in excess of the number of Net Acres set forth in Schedule A for such Lease, multiplied by the Per Net Acre Price.

 

B.       Downward Adjustments. The Purchase Price shall be adjusted downward by the amount of (i) the aggregate Defect Values, plus (ii) the Allocated Value of each Lease excluded from the Initial Closing pursuant to any of the various provisions of Article 5.

 

All such adjustments to the Purchase Price shall be set forth on a “Settlement Statement” which Seller shall prepare and provide to Buyer at least two (2) Business Days before the Initial Closing. The Settlement Statement shall be approved by Buyer and Seller at the Initial Closing. The Purchase Price as so adjusted shall be paid at the Initial Closing and is referred to herein as the “Closing Amount.”

 

 5 

 

 

ARTICLE 4
BUYER’S INSPECTION

 

4.1       Access to Records. No later than the Execution Date, Seller shall deliver in electronic format (via a “Drop Box” internet account), complete and accurate duplicate copies of the Leases and all title information related thereto in Seller’s possession or control, including, but not limited to, any pertinent mineral and surface ownership reports, title information, curative and contracts affecting the Leases or the Additional Leases (including gas gathering, marketing, processing or transportation contracts, if any) (the “Title Records”). Seller must promptly supplement the information required hereunder after the Execution Date when new information of this type is obtained by Seller and notify Buyer of such additional information, including, without limitation, information regarding Additional Leases.

 

4.2       No Representation or Warranty. Except as set forth in Section 6.8, Seller makes no representation or warranty as to the accuracy or completeness of the Title Records. Buyer agrees that any conclusions drawn from such Title Records shall be the result of its own independent review and judgment.

 

ARTICLE 5
TITLE DEFECTS

 

5.1       Defensible Title. The term “Defensible Title” with respect to a Lease means such record title of Seller in and to the Leases as of the Execution Date and the Defect Notice Date, subject to and except for Permitted Encumbrances, which: (i) results in Seller owning and having the ability to transfer to Buyer at each respective Closing, that number of Net Acres with respect to the Lease equal to or greater than the number of Net Acres for the Lease set forth in Schedule A; (ii) entitles Seller to not less than the Designated NRI for the duration of such Lease; (iii) if Seller owns less than a 100% working interest in a Lease, obligates Seller to bear no greater share of costs for developing the Lease than is set forth in Schedule A as the working interest for such Lease (without a corresponding increase in the NRI for that Lease); (iv) provides for a remaining primary term that expires December 13, 2019 or later, and (v) is free and clear of liens, security interests, encumbrances, contracts, claims, and other defects that would create a material impairment to the Allocated Value, use and enjoyment of, or loss of interest in, the affected Lease.

 

5.2       Permitted Encumbrances. The term “Permitted Encumbrances” shall mean:

 

A.       Lessors’ royalties, overriding royalties, net profits interests, production payments, reversionary interests and similar burdens if the net cumulative effect of such burdens does not operate to reduce the NRI in any Lease below the NRI represented on Schedule A for such Lease, subject to Section 8.1;

 

B.       All rights to consent by, approvals of, required notices to, filings with, or other actions by federal, state or local governmental bodies, in connection with the conveyance of the applicable Lease if the same are customarily sought after closing;

 

C.       Easements, rights-of-way, servitudes, permits, surface leases and other rights with respect to surface operations, on, over or in respect of any of the Leases or the Lands covered thereby or any restriction on access thereto that do not materially interfere with the operation, use, or development of the affected Lease; and

 

 6 

 

 

D.       Liens for taxes or assessments not yet due and delinquent or, if delinquent, that are being contested in good faith in the normal course of business and for which Seller will remain responsible to the extent they relate to times prior to the Execution Date.

 

E.       Such Title Defects as Buyer has waived in writing prior to the Initial Closing.

 

5.3       Title Defect. The term “Title Defect” means, with respect to a Lease, any lien, encumbrance, adverse claim, default, expiration, failure, defect in or objection to record title (other than Permitted Encumbrances), that alone or in combination with other defects or matters renders Seller’s title to the Lease less than Defensible Title. Notwithstanding the foregoing, a Title Defect shall not include (i) defects in the early chain of title consisting of failure to recite marital status or the omission of succession or heirship proceedings, (ii) defects or irregularities arising out of prior oil and gas leases which, on their face, expired more than ten (10) years prior to the Initial Closing, and which have not been released of record, (iii) defects or irregularities arising out of the lack of a survey, (iv) defects or irregularities arising out of the lack of recorded powers of attorney from corporations to execute and deliver documents on their behalf, (v) defects or irregularities cured by possession under applicable statutes of limitation, (vi) proof of representative capacity on behalf of a corporation, partnership, limited liability company or trust, unless it is clear from other documentation that a signatory party has not signed a document in the proper representative capacity, (vii) consents to assign any of the Leases if the failure to obtain such consent (A) does not render the Lease subject to such consent void or voidable, (B) does not render the assignment of the Lease subject to such consent void, invalid or unenforceable, (C) requires a payment of a fee, or (D) has been denied in writing by the holder of such consent, (viii) outstanding deeds of trust and mortgage liens burdening the interests of any lessor under any of the Leases, unless there is evidence that that the mortgagee or lien holder has asserted a default under any such deed of trust or mortgage and has or intends to exercise foreclosure proceedings, and (ix) any Title Defect for which written notice is not provided to Seller prior to the expiration of the Defect Notice Date.

 

5.4       Defect Value. “Defect Value” means the following:

 

A.       Lien or Encumbrance. If the Title Defect is a lien or similar encumbrance on a Lease, the Defect Value shall be the cost of removing such lien or encumbrance;

 

B.       Net Revenue Interest. If the effect of a Title Defect is a reduction in the NRI below the Designated NRI, and if Buyer, in accordance with Section 5.6 has elected to exclude the affected Lease, the Defect Value shall be the Allocated Value for the entire affected Lease; provided, however, that Seller shall have the right to exclude any Lease affected by such type of Title Defect from this Agreement, retain such Lease and the Purchase Price will be reduced by the Allocated Value for such Lease;

 

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C.       Net Acres. If the Title Defect is that the Net Acres actually covered by the Lease is less than the number of Net Acres set forth in Schedule A for such Lease, the Defect Value shall an amount equal to the Per Net Acre Price, multiplied by such difference;

 

D.       Primary Term. If the Title Defect arises from a Lease having a primary term that expires sooner than December 13, 2019, then the Defect Value shall be the Allocated Value of such Lease.

 

5.5       Notice of Title Defects. On or before 5:00 p.m. Central Time, five (5) Business Days prior to the Initial Closing Date (the “Defect Notice Date”), Buyer shall deliver to Seller a written notice of Title Defects describing in reasonable detail on a Lease-by-Lease basis (i) the Title Defect, (ii) the basis of the Title Defect and (iii) Buyer’s good faith estimate of the Defect Value of the Title Defect (“Title Defect Value”). The failure of Buyer to timely notify Seller of a Title Defect or the Title Defect Value thereof on the Defect Notice Date shall be deemed a waiver by Buyer of such Title Defect, other than Title Defects arising from a breach of the Special Warranty contained in the Assignment and Conveyance, and other than as may constitute a breach of Section 6.12.

 

5.6       Right to Cure. Seller shall have the option, but not the obligation, to attempt to cure, on or before 5:00 p.m. Central Time, two (2) Business Days prior to the Initial Closing (“Cure Period”), any Title Defect affecting the Assets that is timely identified under Section 5.5. If a Title Defect is a reduction in NRI below the Designated NRI for any Lease, the Parties agree that Seller may cure such Title Defect by delivering, or causing to be delivered, assignments of existing overriding royalties assigned by Seller under Article 8 of this Agreement in amounts sufficient to increase the NRI to the Designated NRI, which assignments shall be delivered at the Initial Closing or Subsequent Closing, as the case may be, and shall contain a special warranty of title.   If Seller is unable to cure a Title Defect that is a reduction in NRI below the Designated NRI for any Lease in the manner set forth above, then Buyer shall have the right, but not the obligation, to elect to exclude the affected Lease from the Initial Closing, and the Purchase Price will be reduced by the Allocated Value of such Lease. Prior to the end of the Cure Period, Seller shall provide evidence that a Title Defect has been cured. Prior to the execution of the Settlement Statement pursuant to Section 3.2, Buyer shall notify Seller whether such Title Defect has been cured to the reasonable satisfaction of Buyer. Without limitation of Section 5.8 below, if there are any Title Defects described under sub-clause (iv) in the definition of Defensible Title in Section 5.1, and (i) Seller elects, or is deemed to have elected, to not cure such Title Defect, or (ii) Seller elects to cure such Title Defect in accordance with this Section 5.6 but is unable to cure such Title Defect by the end of the Cure Period (or, if such Lease has already been excluded from the Initial Closing due to its being subject to an Outstanding Title Defect, by the by the end of the Post-Closing Cure Period), then Seller may elect to retain the Lease or Leases affected by such Title Defect and the Purchase Price shall be reduced by the Allocated Value of such Lease or Leases.

 

5.7       Defect Adjustments. If any Title Defects are timely asserted by Buyer pursuant to Section 5.5, but are not (i) cured within the Cure Period to Buyer’s reasonable satisfaction, or (ii) waived by Buyer on or before the Initial Closing (an “Outstanding Title Defect”), the Purchase Price shall be adjusted downward by the amount of the Defect Value, unless such Lease is excluded from the Initial Closing, in which event the Purchase Price shall be adjusted downward by the Allocated Value of the applicable Lease.

 

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5.8       Right to Cure Post-Closing. With respect to each Lease that is subject to an Outstanding Title Defect as of the Initial Closing which, in Seller’s opinion, is reasonably susceptible to being cured within the Post-Closing Cure Period (defined below), Seller shall have the right to elect to exclude such Lease from the Initial Closing, in which event the Purchase Price shall be adjusted downward by the Allocated Value attributable to such Lease. Seller shall have the option, but not the obligation, to attempt to cure any Outstanding Title Defect on or before 5:00 p.m. Central Time on the date that is 30 days after the Initial Closing (the “Post-Closing Cure Period”). As soon as practicable, but no later than the end of the Post-Closing Cure Period, Seller shall provide to Buyer evidence that Outstanding Title Defects have been cured. If Seller timely cures any Outstanding Title Defects to the reasonable satisfaction of Buyer, the Lease(s) affected by same shall be included in the Subsequent Closing.

 

5.9       Title Dispute Resolution.

 

A.       Prior to the Initial Closing, the Parties shall attempt to resolve, through good faith negotiations, all disputes concerning (i) the existence and scope of a Title Defect, (ii) the amount of the Defect Value, and (iii) the adequacy of any Title Defect curative materials and Buyer’s reasonable satisfaction therewith. In the event the Parties cannot resolve any Title Disputed Matters on or before the Initial Closing (the “Title Disputed Matters”), the Leases affected by any Title Disputed Matter shall not be conveyed to Buyer at the Initial Closing, and the Purchase Price shall be reduced by the Allocated Value of such affected Leases.

 

B.       If any Title Disputed Matter is resolved by the Parties during the Post-Closing Cure Period then the pertinent Lease(s) shall be included in the Subsequent Closing. In the event the Parties cannot resolve any Title Disputed Matters on or before the end of the Post-Closing Cure Period, the dispute resolution procedures provided for in Article 14 below shall be applied.

 

5.10       Termination. Notwithstanding anything contained herein to the contrary, if the aggregate of (i) all Defect Values with respect to Leases which are not retained by Seller, plus (ii) the Allocated Value of Leases (a) retained by Buyer pursuant to Section 5.6 or 5.8, and (b) subject to a consent that is retained by Seller pursuant to Section 5.11, reduced by (iii) the aggregate amount of upward adjustments under Section 3.2A, exceeds $8,200,000, Seller or Buyer may terminate this Agreement upon written notice to the other Party delivered no later than 5:00 p.m. Central Time on the Business Day before Closing.

 

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5.11       Consents.

 

Prior to the Initial Closing, Seller shall use reasonable efforts to obtain all consents to assignment of the Leases, including, without limitation, those set forth on Schedule 6.10. If Buyer discovers properties for which consents to assign are applicable during the course of Buyer’s due diligence activities, Buyer shall notify Seller immediately and Seller shall use reasonable efforts to obtain such consents prior to the Initial Closing. Except for consents and approvals which are customarily obtained post-closing (including without limitation federal, state, or other governmental approvals), if a consent to assign any Leases has not been obtained as of the pertinent Closing, (i) if the consent to assign is not a Title Defect as set forth in sub-clause (vii) of Section 5.3, then the affected Leases shall be conveyed to Buyer at that Closing and without an adjustment to the Purchase Price; or (ii) if the consent to assign is not subject to the provisions of sub-clause (i) above, then at Buyer’s election, the affected Leases shall either be (1) conveyed to Buyer at that Closing and without an adjustment to the Purchase Price and Buyer shall assume the obligation and risk of obtaining or not obtaining such consents post-closing, or (2) retained by Seller and the Purchase Price be reduced by the Allocated Value of such Leases. If a Lease is retained by Seller in accordance with sub-part (2) above and if the applicable consent is obtained after the Initial Closing or the Subsequent Closing, as applicable, Seller shall promptly notify Buyer. If such consent to assign is obtained within ninety (90) days after the Initial Closing or the Subsequent Closing, as applicable, then within thirty (30) calendar days after Buyer’s receipt of written notice from Seller that such consent is no longer outstanding, Seller shall sell to Buyer, and Buyer shall purchase from Seller, such Lease retained by Seller under the terms of this Agreement for a price equal to the Allocated Value of such Lease (as adjusted under the terms of this Agreement) and Seller shall assign and convey such Lease to Seller on the form of assignment attached hereto as Schedule C.

 

5.12       Certain Restricted Activities. For a period of six (6) months commencing on the Additional Lease Cutoff Date, Seller shall not, and shall cause its Affiliates not to, directly or indirectly, own, acquire or solicit the acquisition of (or assist any other Person to own, acquire or solicit the acquisition of) any oil and gas leases, oil, gas and mineral leasehold interests, working interests, subleases, top leases, licenses, easements, pooling orders and other cost-bearing interests in oil, gas and other hydrocarbons, or any other rights, titles and interests relating directly or indirectly to the cost-bearing participation in the drilling, exploration, development, operation, marketing, sale or other disposal of the foregoing assets and interests (“Oil and Gas Interests”), or any option or other right to acquire any Oil and Gas Interests, in any case covering, in whole or in part, the governmental sections set forth on Schedule D (the “Covered Lands”). In addition to the foregoing, during such six (6) month period, Seller shall not, and shall cause its Affiliates not to, directly or indirectly terminate, own, acquire, solicit or otherwise interfere with any of Buyer’s Oil and Gas Interests covering in whole or in part the Covered Lands or in any way attempt to do any of the foregoing or assist any third Person to do any of the foregoing. The provisions of this Section 5.12 shall not apply to (a) the Leases retained by Seller under Section 5.6, Section 5.11 or Section 12.4 or (b) oil and gas leases acquired by Seller prior to the Additional Lease Cutoff Date.

 

ARTICLE 6
SELLER’S REPRESENTATIONS AND WARRANTIES

 

Seller makes the following representations and warranties to Buyer as of the date of the Agreement and again as of each Closing:

 

6.1       Status. Seller is a limited partnership duly organized, validly existing and in good standing under the laws of the State of Delaware.

 

6.2       Power. Seller has all requisite power and authority to carry on its business as presently conducted. The execution and delivery of this Agreement does not, and the fulfillment of and compliance with the terms and conditions hereof will not violate, or be in conflict with, any provision of Seller’s governing documents, or any material provision of any agreement or instrument to which Seller is a party or by which it is or the Assets are bound, or any judgment, decree, order, statute, rule or regulation applicable to Seller.

 

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6.3       Authorization and Enforceability. This Agreement constitutes Seller’s legal, valid and binding obligation, enforceable in accordance with its terms, subject as to enforceability, to the effects of bankruptcy, insolvency, reorganization, moratorium and other laws for the protection of creditors, as well as to general principles of equity, regardless of whether such enforceability is considered in a proceeding in equity or at law. The execution, delivery and performance of this Agreement by Seller and the transactions contemplated hereby, will not (i) conflict with, breach or result in a default (with due notice or lapse of time or both) or the creation of any lien or encumbrance or give rise to any right of termination, cancellation or acceleration or any of the terms, conditions or provisions or any note, bond, mortgage, indenture or agreement to which Seller is a party or by which Seller or any of the Assets are bound; (ii) violate any judgment, order, ruling or decree applicable to Seller; or (iii) violate any law.

 

6.4       Liability for Brokers’ Fees. Seller has not incurred any liability, contingent or otherwise, for brokers’ or finders’ fees relating to the transactions contemplated by this Agreement for which Buyer shall have any responsibility whatsoever.

 

6.5       No Bankruptcy. There are no bankruptcy proceedings pending, being contemplated by or, threatened against such Seller.

 

6.6       Litigation. There are no actions or suits pending against Seller with respect to the Assets or which would hinder or impede the performance by Seller of its obligations under this Agreement and, to Seller’s knowledge, there is no proceeding, claim or investigation pending or threatened with respect to the Assets or which would hinder or impede the performance by Seller of its obligations under this Agreement.

 

6.7       Lease Status/Rentals. Seller has paid all bonuses, extension or renewal payments, rentals, minimum royalties and shut-in payments due under the Leases. Seller has not received a written notice of any request or demand for payments, adjustments of payments or performance pursuant to obligations under the Leases that is still outstanding. Seller has not received a written notice of default with respect to the payment or calculation of rentals that has not been cured.

 

6.8       Accuracy of the Records. To Seller’s knowledge after a reasonably diligent review of its internal records, the information it supplied in connection with Section 4.1 conforms to the requirements of the first sentence of said Section in all material respects, and contains all documentation in Seller’s possession or under its control which could reasonably be expected to affect the Leases subsequent to the Initial Closing.

 

6.9       Compliance With Laws. Seller has owned and operated the Assets in material compliance with all applicable laws, statutes, rules, regulations and orders, and Seller has not received written notice from any governmental agency that Seller’s ownership or operation of the Assets is in violation of any applicable federal, state or local laws, including environmental laws, in any material respect.

 

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6.10       Preferential Rights to Purchase and Consents. None of the Assets are subject to any preferential rights to purchase or similar arrangements. Except as set forth on Schedule 6.10, Seller does not require the consent of any Person to assign the Leases or Assets to Buyer.

 

6.11       No Operations or Wells. Seller has not conducted oil and gas exploration, development or production operations on the Leases, or any lands pooled or unitized therewith.

 

6.12       Basic Documents. The following documents, agreements and instruments are in full force and effect and constitute the valid and binding obligations of the parties thereto: excluding the Leases (A) all contracts and agreements, licenses, permits and easements, rights of way and other rights of surface use comprising any part of or otherwise relating to the Assets; and (B) all contracts and agreements that are reasonably necessary to own, explore develop, operate, maintain or use the Assets in the manner in which they are currently being owned, explored, developed, operated, maintained or used, and in accordance with the prudent practices of the oil and gas industry ((A) and (B) collectively, the “Basic Documents”). Seller has provided true and correct copies of all Basic Documents (together will all amendments, supplements and extensions thereto) to Buyer. The Basic Documents are in full force and effect. Seller is not in breach or default (and no situation exists which with the passing of time or giving of notice would create a breach or default) of its obligations under any of the Basic Documents, and, to Seller’s knowledge, no breach or default by any third party exists under any of the Basic Documents. All payments owing under the Basic Documents have been and are being made timely. The Assets are not subject to or bound by any area of mutual interest, most favored nations provision, farmout, farm-in, non-compete provision or any other term or provision that would restrict the manner in which Buyer is permitted to own and operate the Assets (or any other assets or properties) after the Closing.

 

6.13       Dedication. There exist no agreements or arrangements for the sale of production from the Leases or under which production from the Leases is dedicated or committed for sale, gathering, transportation, processing, treating, or any other services.

 

6.14       Liens. To Seller’s actual knowledge, without any duty of inquiry, there are no outstanding liens, mortgages, claims or other encumbrances burdening or affecting the Assets.

 

6.15       Taxes. All Property Taxes and Severance Taxes assessed against the Assets that are due have been timely paid. Seller has timely filed or caused to be timely filed all Tax returns, reports, statements and similar filings required by applicable Law with respect to the Assets due on or prior to the Closing Date, and all such Tax returns, reports, statements and similar filings are complete and accurate in all material respects. There are no pending or threatened audits, investigations or claims for or relating to any additional liability in respect of Property Taxes or Severance Taxes with respect to the Assets. There are no extensions or waivers of any statute of limitations with respect to such Taxes or Tax liens burdening the Assets except for liens for current Taxes not yet due and payable. All of the Assets have been properly listed and described on the applicable property tax rolls for all periods prior to and including the Closing Date. None of the Assets is subject to tax partnership reporting requirements under applicable provisions of the Code.

 

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ARTICLE 7
BUYER’S REPRESENTATIONS AND WARRANTIES

 

Buyer makes the following representations and warranties to Seller as of the date of the Agreement and again as of each Closing:

 

7.1       Organization and Standing. Buyer is a corporation duly organized, validly existing and in good standing under the laws of Nevada.

 

7.2       Power. Buyer has all requisite power and authority to carry on its business as presently conducted. The execution and delivery of this Agreement does not, and the fulfillment of and compliance with the terms and conditions hereof will not, as of the Closing Date, violate, or be in conflict with, any provision of Buyer’s governing documents, or any material provision of any agreement or instrument to which Buyer is a party or by which it is bound, or any judgment, decree, order, statute, rule or regulation applicable to Buyer.

 

7.3       Authorization and Enforceability. This Agreement constitutes Buyer’s legal, valid and binding obligation, enforceable in accordance with its terms; subject, however, to the effects of bankruptcy, insolvency, reorganization, moratorium and other laws for the protection of creditors, as well as to general principles of equity, regardless whether such enforceability is considered in a proceeding in equity or at law. The execution, delivery and performance of this Agreement by Buyer and the transactions contemplated hereby, will not (i) conflict with, breach or result in a default (with due notice or lapse of  time or both) or the creation of any lien or encumbrance or give rise to any right of termination, cancellation or acceleration or any of the terms, conditions or provisions or any note, bond, mortgage, indenture or agreement to which Buyer is a party or by which Buyer or any of the Assets are bound; (ii) violate any judgment, order, ruling or decree applicable to Buyer; or (iii) violate any applicable law.

 

7.4       Liability for Brokers’ Fees. Buyer has not incurred any liability, contingent or otherwise, for brokers’ or finders’ fees relating to the transactions contemplated by this Agreement for which Seller shall have any responsibility whatsoever.

 

7.5       Independent Evaluation. Buyer represents that it is sophisticated in the evaluation, purchase, operation and ownership of oil and gas properties and related properties. In making its decision to enter into this Agreement and to consummate the transaction contemplated herein, Buyer represents that it has relied solely on its own independent investigation and evaluation of the Assets together with the express representations and warranties of Seller set forth in this Agreement.

 

7.6       Financial Resources. At the Initial Closing, Buyer will have the financial resources available to close the transactions contemplated by this Agreement.

 

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ARTICLE 8
COVENANTS AND AGREEMENTS

 

8.1       Covenants and Agreements of Seller. Seller covenants and agrees with Buyer that, from the Execution Date until the Subsequent Closing Date, Seller shall not, without the written consent of the Buyer (i) commit to drill any wells on the Leases or conduct any oil and gas exploration, development or production operations on the Leases, or any lands pooled or unitized therewith, (ii) abandon any part of the Leases; (iii) sell, transfer, assign, convey or otherwise dispose of any of the Leases, or any interest therein or enter into any commitment to do so; provided, however, that no later than two (2) Business Days prior to the Defect Notice Date, Seller may assign overriding royalty interests in the Leases to certain key personnel of Seller (or their Affiliates), provided that after giving effect to such assignments, the Designated NRI will be delivered at the Closing with respect to the Leases covered by such assignments, such assignments of overriding royalty to be in form of Schedule B (the “ORRI Assignment”); (iv) enter into any farmout agreement, farm-in agreement or any other contract affecting the Leases; (v) modify or terminate any Lease; or (vi) create or suffer any lien, security interest or encumbrance on the Leases, the oil or gas attributable to the Leases, or the proceeds thereof. The ORRI Assignment for all affected Leases must be disclosed to Buyer in fully executed and acknowledged form no less than two (2) Business Days prior to the Defect Notice Date.

 

ARTICLE 9
CONDITIONS PRECEDENT TO CLOSING

 

9.1       Seller’s Conditions. The obligations of Seller at each Closing are subject to the satisfaction or waiver by Seller at or prior to the Closing of the following conditions precedent as such apply to such Closing:

 

A.       All representations and warranties of Buyer contained in this Agreement shall be true and correct in all material respects on and as of the Closing (other than (i) representations and warranties of Buyer that are qualified by materiality, and (ii) the representations and warranties in Section 7.1 through 7.4, which shall be true and correct in all respects), and Buyer shall have performed and satisfied all covenants and agreements required by this Agreement to be performed and satisfied by Buyer at or prior to the Closing in all material respects; and

 

B.       Buyer stands ready, willing and able to close with Seller.

 

9.2       Buyer’s Conditions. The obligations of Buyer at each Closing are subject to the satisfaction or waiver by Buyer at or prior to such Closing of the following conditions precedent as such apply to such Closing:

 

A.       All representations and warranties of Seller contained in this Agreement shall be true and correct in all material respects on and as of the Closing (other than (i) representations and warranties of Seller that are qualified by materiality, and (ii) the representations and warranties in Section 6.1 through 7.5, which shall be true and correct in all respects), Seller shall have performed and satisfied all covenants and agreements required by this Agreement to be performed and satisfied by Seller at or prior to the Closing in all material respects; and

 

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B.       Seller stands ready, willing and able to close with Buyer.

 

9.3       Mutual Conditions. The obligations of the Parties at a Closing are subject to the satisfaction or waiver by the Parties at or prior to such Closing of the following conditions precedent as such apply to such Closing:

 

A.       No order has been entered by any court or governmental agency having jurisdiction over the Parties or the subject matter of this Agreement that restrains or prohibits the purchase and sale provided for by this Agreement and that remains in effect at Closing; and

 

B.       As to the Initial Closing, neither Party has invoked Section 5.10 when it has the right to do so.

 

ARTICLE 10
RIGHT OF TERMINATION

 

10.1       Termination. This Agreement may be terminated in accordance with the following provisions:

 

A.       By Seller if the conditions set forth in Sections 9.1 or 9.3 are not satisfied, or are not waived by Seller in writing, as of the Initial Closing or the Subsequent Closing, as applicable; or

 

B.       By Buyer if the conditions set forth in Sections 9.2 or 9.3 are not satisfied, or are not waived by Buyer in writing, as of the Initial Closing or the Subsequent Closing, as applicable; or

 

C.       By Seller or Buyer if the Initial Closing has not occurred by November 10, 2017; or

 

D.       By Seller or Buyer pursuant to Section 5.10; or

 

E.       By mutual consent of Buyer and Seller.

 

10.2       Liabilities Upon Termination.

 

A.       Buyer’s Default. If this Agreement is terminated by Seller in accordance with Section 10.1 above due to a failure of a condition set forth in Section 9.1, and Seller is not in material default under this Agreement, Seller, subject to Section 14.13, shall be entitled, as its sole and exclusive remedy hereunder, to seek damages; provided that in no event shall Seller be entitled to seek damages in excess of an amount that is five percent (5%) of the Purchase Price.

 

B.       Seller’s Default. If this Agreement is terminated by Buyer in accordance with Section 10.1 above due to a failure of a condition set forth in Section 9.2, and if Buyer is not in material default under this Agreement, Buyer, subject to Section 14.13, shall be entitled to elect to either: (1) seek specific performance, or (2) terminate this Agreement in which event Buyer shall be entitled to all rights and remedies that may be available at law or in equity provided that in no event shall Buyer be entitled to seek damages in excess of an amount that is five percent (5%) of the Purchase Price.

 

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C.       Other Termination. If this Agreement is terminated for any other reason than those specified in Section 10.2.A or Section 10.2.B, each Party shall release the other Party from any and all liability for termination of this Agreement.

 

D.       Certain Limitations. THE PARTIES FURTHER AGREE THAT, UNLESS AND UNTIL THE CLOSING OCCURS, THE SOLE AND EXCLUSIVE REMEDY OF SELLER AND ITS AFFILIATES AGAINST BUYER, AND ANY OF ITS PARTNERS, EQUITYHOLDERS, CONTROLLING PERSONS, MANAGEMENT COMPANIES, REPRESENTATIVES, ASSIGNEES OR AFFILIATES AND ANY AND ALL FORMER, CURRENT OR FUTURE HEIRS, EXECUTORS, ADMINISTRATORS, TRUSTEES, SUCCESSORS OR ASSIGNS, OFFICERS, DIRECTORS, EMPLOYEES, AGENTS, LENDERS, ADVISORS, REPRESENTATIVES, ACCOUNTANTS, ATTORNEYS AND CONSULTANTS OF ANY OF THE FOREGOING (COLLECTIVELY, THE “BUYER RELATED PARTIES”) ARISING FROM OR RELATING TO THIS AGREEMENT AND THE TRANSACTIONS CONTEMPLATED HEREUNDER, INCLUDING FOR ANY FAILURE OF BUYER TO EFFECT THE CLOSING OR OTHERWISE TO PERFORM ITS OBLIGATIONS UNDER THIS AGREEMENT (WHETHER WILLFULLY, INTENTIONALLY, UNINTENTIONALLY OR OTHERWISE), WHETHER IN CONTRACT, TORT OR OTHERWISE, SHALL BE THE RIGHTS AND REMEDIES AGAINST BUYER EXPRESSLY DESCRIBED HEREIN. EXCEPT FOR THE RIGHTS AND REMEDIES AGAINST BUYER DESCRIBED HEREIN, IN FURTHERANCE OF THE FOREGOING, IF AND ONLY IF THE CLOSING DOES NOT OCCUR, (A) SELLER HEREBY RELEASES THE BUYER RELATED PARTIES, WAIVES ANY RIGHT OF RECOVERY FOR AND AGREES NOT TO SEEK ANY RECOVERY FOR ANY LOSS SUFFERED AS A RESULT OF ANY BREACH OF ANY COVENANT, OBLIGATION, REPRESENTATION OR WARRANTY IN THIS AGREEMENT OR THE FAILURE OF THE TRANSACTION TO BE CONSUMMATED, OR IN RESPECT OF ANY ORAL REPRESENTATION MADE OR ALLEGED TO HAVE BEEN MADE IN CONNECTION HEREWITH AND (B) THE MAXIMUM AGGREGATE MONETARY LIABILITY THAT THE BUYER RELATED PARTIES SHALL HAVE IN CONNECTION WITH SUCH LOSS SHALL BE AS SET FORTH IN THIS SECTION 10.2.

 

ARTICLE 11
CLOSING

 

11.1       Closing. The “Initial Closing” of the transaction contemplated hereby shall occur on November 10, 2017, or such other date as the Parties may agree, and shall occur at the offices of Seller or by electronic means in a manner mutually agreed to by the Parties. The date on which Initial Closing actually occurs is referred to herein as the “Initial Closing Date.”

 

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11.2       Closing Obligations. At the Initial Closing, the following events shall occur with respect to the Assets being conveyed at such Closing, each being a condition precedent to the others and each being deemed to have occurred simultaneously with the others:

 

A.       Assignment and Conveyance. Seller and Buyer shall execute, acknowledge and deliver the Assignment and Conveyance assigning the Assets to be conveyed by Seller at such Initial Closing to Buyer (after applying the various provisions of Article 5), substantially in the form of Schedule C (modified as appropriate to conform to the Assets being so conveyed).

 

B.       Schedule of Additional Leases and Optional Additional Leases; Cured Leases. Seller shall provide Buyer with an accurate schedule identifying all Additional Leases and Optional Additional Leases which have not then been obtained by Seller and which Seller expects to assign to Buyer at the Subsequent Closing, as well as identifying all Leases still then subject to Outstanding Title Defects.

 

C.       Settlement Statement. Seller and Buyer shall execute the Settlement Statement.

 

D.       Closing Amount. Buyer shall deliver to Seller the Closing Amount applicable to the Assets being conveyed by Seller at such Closing, by wire transfer in immediately available funds, according to the wire instructions provided by Seller.

 

E.       Possession. Seller shall deliver to Buyer possession of the Assets being conveyed by Seller at the Initial Closing.

 

ARTICLE 12
POST-CLOSING OBLIGATIONS

 

12.1       Records. Seller shall deliver the Records to Buyer at a mutually agreeable time promptly after each Closing.

 

12.2       Recording Fees. Buyer shall pay all documentary, transfer, filing, licensing, and recording fees required in connection with the processing, filing, licensing or recording of any assignments, except for any ORRI Assignments, which shall be recorded at the sole cost and expense of Seller.

 

12.3       Assumption of Obligations; Defense and Indemnification. From and after the Initial Closing and the Subsequent Closing, Buyer shall assume and pay for, perform and fulfill all obligations arising under the Leases assigned to Buyer at the Initial Closing or the Subsequent Closing, to the extent that same arise subsequent to the Initial Closing Date or the Subsequent Closing Date, as the case may be, but not otherwise. Seller shall remain responsible for and shall promptly pay and perform all other duties, obligations and liabilities related to or arising under the Leases.

 

A.       Seller shall indemnify, hold harmless and defend Buyer, its partners and their respective affiliates and respective officers, directors, employees, attorneys, contractors and agents of such parties, and each of its successors, assigns, and legal representatives (collectively, the “Buyer Indemnified Parties”), from and against any and all liabilities, losses, claims and causes of action, of every kind or character (including attorney’s fees and costs of investigation), arising in whole or part out of (i) Seller’s failure to perform or satisfy the obligations it retains under this Section 12.3, or (ii) Seller’s breach of any of its representations, warranties or covenants under this Agreement.

 

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B.       Buyer shall indemnify, hold harmless and defend Seller its partners and their respective affiliates and respective officers, directors, employees, attorneys, contractors and agents of such parties, and each of its successors, assigns, and legal representatives (collectively, the “Seller Indemnified Parties”), from and against any and all liabilities, losses, claims and causes of action, of every kind or character (including attorney’s fees and costs of investigation), arising in whole or part out of (i) Buyer’s failure to perform or satisfy the obligations it assumes under this Section 12.3, or (ii) Buyer’s breach of any of its representations, warranties or covenants under this Agreement.

 

C.       THE FOREGOING RELEASE AND INDEMNIFICATION SHALL APPLY WHETHER OR NOT SUCH CLAIMS, ACTIONS, CAUSES OF ACTION, LIABILITIES, DAMAGES, LOSSES, COSTS OR EXPENSES ARISE OUT OF (i) NEGLIGENCE (INCLUDING SOLE NEGLIGENCE, SIMPLE NEGLIGENCE, CONCURRENT NEGLIGENCE, ACTIVE OR PASSIVE NEGLIGENCE, OR (ii) STRICT LIABILITY BUT EXCLUDING IN EACH CASE OF (i) AND (ii), THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT ON THE PART OF ANY MEMBER OF THE SELLER INDEMNIFIED PARTIES OR BUYER INDEMNIFIED PARTIES, AS APPLICABLE.

 

D.       From and after Closing, in addition to and without limitation of Buyer’s rights under the special warranty of title in the Assignment and Conveyance to be delivered at each of the Initial Closing and the Subsequent Closing, the sole and exclusive remedy of each Party with respect to the Assets shall be pursuant to the express provisions of this Agreement and any agreement delivered between the Parties at the Initial Closing and Subsequent Closing, including for any and all (a) claims relating to any representations, warranties, covenants and agreements that are contained in this Agreement or in any certificate delivered at the Initial Closing or Subsequent Closing, (b) other claims pursuant to or in connection with this Agreement and (c) other claims relating to the Assets and the purchase and sale thereof.

 

E.       For purposes of this Section 12.3, the representations and warranties of Seller shall not be deemed qualified by any references to materiality.

 

12.4       Subsequent Closing. As soon as practicable, but no later than ten (10) Business Days after the end of the Post-Closing Cure Period (the “Subsequent Closing Date”), the Parties shall convene a second closing of the transaction contemplated hereby (the “Subsequent Closing”). The Subsequent Closing shall be conducted in a substantially similar manner as the Initial Closing under Article 11 above, except that the Assets conveyed to Buyer at that time shall consist only of (i) Additional Leases (including any Optional Additional Leases which Buyer elects to acquire pursuant to this Section 12.4); and (ii) Leases identified pursuant to Section 11.2.B which were subject to Outstanding Title Defects as of the Initial Closing, and which were cured to Buyer’s reasonable satisfaction pursuant to Section 5.8. The Purchase Price shall be an amount equal to (i) the aggregate Allocated Value of the Additional Leases, plus (ii) the Allocated Value of all Leases identified pursuant to Section 11.2.B which were subject to Outstanding Title Defects as of the Initial Closing, and which were cured to Buyer’s reasonable satisfaction pursuant to Section 5.8, subject, in each case, to the adjustments set forth in Section 3.2.

 

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A.       Additional Leases which are obtained by Seller shall be promptly disclosed to Buyer when acquired by Seller along with all Records pertaining to same for application of the due diligence provisions of Article 5. Such disclosure shall include Seller’s represented Net Acres and all documentation evidencing the acquisition of such Additional Lease. All of Sections 5.1 through 5.9 inclusive shall be applied to conforming Additional Leases, except for the following modifications:

 

i.       the Defect Notice Date for such Additional Leases shall be three (3) Business Days after the end of the Post-Closing Cure Period;

 

ii.       the Cure Period for Additional Leases shall end two (2) Business Days prior to the Subsequent Closing Date;

 

iii.       Section 5.8 shall not apply;

 

iv.       In the event any Additional Lease remains subject to a Title Defect which is not cured to Buyer’s reasonable satisfaction within the Cure Period for Additional Leases, or waived by Buyer on or before the Subsequent Closing Date, Buyer shall have the right to exclude such Additional Lease from the Subsequent Closing, in which event the Purchase Price shall be reduced by the aggregate number of Net Acres covered by such Additional Lease, multiplied by the Per Net Acre Price; and

 

v.       all references to the “Initial Closing” and the “Initial Closing Date” in Article 5 (and where required, elsewhere in this agreement) are conformed for application of this Section 12.4 in such manner as is reasonably necessary to effectuate the Subsequent Closing or the Subsequent Closing Date, as applicable.

 

B.       For the Subsequent Closing, Seller shall prepare a Settlement Statement of the same form and substance as is contemplated in connection with the Initial Closing and provide same to Buyer at least two (2) Business Days before the Subsequent Closing. The Settlement Statement must be approved by Buyer and Seller at the Subsequent Closing. The Settlement Statement shall set forth the additional monetary amount owed hereunder by Buyer to Seller for assignment of the Additional Leases and the Leases falling under the last sentence of Section 5.8 or the first sentence of Section 5.9(B), as well as any downward adjustments provided for under this Agreement.

 

C.       At the Subsequent Closing, Section 11.1 and Section 11.2 shall again be applied to consummate said Closing, except:

 

i.        Subsection 11.2(B), shall not apply; and

 

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ii.       Seller shall execute and deliver a certificate duly executed by an officer of Seller, which shall certify that the representations and warranties are true and correct as of the Subsequent Closing, insofar as such representations and warranties apply to the Assets to be conveyed at the Subsequent Closing.

 

D.       Section 8.1 shall apply to the Additional Leases to be assigned to Buyer at the Subsequent Closing; provided that as to Subsection 8.1(iii), the ORRI Assignment for all Leases to be assigned at the Subsequent Closing must be disclosed to Buyer no later than two Business Days before the end of the Defect Notice Date for the Subsequent Closing.

 

E.       Buyer shall have the right, but not the obligation, to purchase one or more of the Optional Additional Leases under the terms and conditions of this Agreement. With respect to all Optional Additional Leases, Seller shall comply with the notice requirements set forth in Section 12.4.A above. On a date no later than the Defect Notice Date for Additional Leases set forth in Section 12.4.A.i above, Buyer shall provide written notice to Seller specifying which, if any of the Optional Additional Leases it elects to acquire. Upon such election, the Optional Leases Buyer so elects to acquire shall be deemed “Additional Leases” for all purposes under this Agreement. With respect to all other Optional Additional Leases which Buyer does not elect to acquire, such Optional Additional Leases shall be excluded from this Agreement, and the Parties shall have no further obligation to each other with respect thereto.

 

12.5       Further Assurances. From time to time after each Closing, Seller and Buyer shall each execute, acknowledge and deliver to the other such further instruments and take such other action as may be reasonably requested in order to accomplish more effectively the purposes of the transactions contemplated by this Agreement, including assurances that Seller and Buyer are financially capable of performing any indemnification required hereunder.

 

ARTICLE 13
TAXES

 

13.1       Transfer Taxes. The transactions described in this Agreement involve the transfer of real estate with tangible personal property, if any, being transferred incidental to such real estate; accordingly, Seller and Buyer do not anticipate that any sales, use, stamp, real estate transfer, documentary, registration, recording and other similar Taxes (each a “Transfer Tax”) will be incurred or imposed with respect to the transactions described in this Agreement. Buyer and Seller hereby acknowledge and agree that the Purchase Price excludes any such Transfer Tax. Buyer and Seller will use commercially reasonable efforts and cooperate in good faith to exempt the sale, conveyance, assignments and transfers to be made to Buyer from any such Transfer Tax. If a determination is ever made that a Transfer Tax applies, Buyer will be liable for such Transfer Tax.

 

13.2       Allocation of Value for Tax Purposes. Seller and Buyer agree that the transaction under this Agreement is not subject to the reporting requirement of Section 1060 of the Code and that, therefore, Internal Revenue Service Form 8594 (Asset Acquisition Statement Under Section 1060) is not required to be and will not be filed for this transaction. In the event that the Seller and Buyer mutually agree that a filing of Form 8594 is required, Seller and Buyer will confer and cooperate in the preparation and filing of their respective forms to reflect a consistent reporting of the agreed upon allocation. In the event that the allocation is disputed by any taxing authority, the Party receiving notice of such dispute will promptly notify and consult with the other Party and keep the other Party apprised of material developments concerning resolution of such dispute.

 

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13.3       Responsible Party. All Taxes attributable to the ownership or operation of the Assets prior to the Effective Date are Seller’s responsibility and all deductions, credits or refunds pertaining to the aforementioned Taxes, no matter when received, belong to Seller. All Taxes attributable to the ownership or operation of the Assets on or after the Effective Date (excluding Seller’s income taxes, franchise taxes or margin taxes through the Initial Closing Date or Subsequent Closing Date, as applicable, and excluding income or capital gains taxes from the sale of the Assets) are the responsibility of Buyer, and all deductions, credits or refunds pertaining to the aforementioned Taxes, no matter when received, belong to Buyer. For these purposes, Property Taxes shall be prorated and allocated based on the percentage of the assessment period occurring before and after the Effective Date and Severance Taxes shall be allocated to the period in which the production giving rise to such Severance Taxes occurred. If either Party pays Property Taxes or Severance Taxes for which the other Party is responsible under this Section 13.3, and the amount of such payment is not taken into account as an adjustment to the Purchase Price under Section 3.2, then upon receipt of evidence of payment the nonpaying Party will reimburse the paying Party promptly for the nonpaying Party’s share of such Property Taxes or Severance Taxes.

 

13.4       Survival. The obligations of the Parties under this Article 13 shall survive the consummation of the transactions described in this Agreement indefinitely.

 

ARTICLE 14
MISCELLANEOUS

 

14.1       Schedules . The Schedules referred to in this Agreement are hereby incorporated in this Agreement by reference and constitute a part of this Agreement.

 

14.2       Expenses. Except as otherwise specifically provided, all fees, costs and expenses incurred by Seller or Buyer in negotiating this Agreement or in consummating the transactions contemplated by this Agreement shall be paid by the Party incurring same, including legal and accounting fees, costs and expenses.

 

14.3       Notices. All notices and other communications under this Agreement shall be in writing and delivered (i) personally, (ii) by registered or certified mail with postage prepaid, and return receipt requested, (iii) by nationally recognized commercial overnight courier service with charges prepaid, (iv) by facsimile transmission or electronic mail, directed to the intended recipient as follows:

 

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If to KEW Drilling:

 

4925 Greenville Avenue, Suite 500

Dallas, Texas 75206

Facsimile:

214-292-6655

Attn: Kathryn W. Francis

Email: kwf@kewdrilling.com

 

If to Lilis Energy, Inc.:
 

300 E. Sonterra Blvd.,

Suite 1220,

San Antonio, Texas 78548

Facsimile:

210-999-5401

Attn: Legal Department

Email: AFuchs@lilisenergy.com

 

A notice or other communication shall be deemed delivered on the earlier to occur of (i) its actual receipt, (ii) the fifth Business Day following its deposit in registered or certified mail, with postage prepaid and return receipt requested, (iii) the first Business Day following its deposit with a nationally recognized commercial overnight courier service, with charges prepaid, (iv) the date it is sent by confirmed facsimile transmission (if sent before 4:00 p.m. local time of the receiving Party on a Business Day) or the next Business Day (if sent after 4:00 p.m. of such local time or sent on a day that is not a Business Day), or (v) the date it is sent by electronic mail. Any Party may change the address to which notices and other communications hereunder can be delivered by giving the other Party notice in the manner herein set forth.

 

14.4       Entire Agreement. This Agreement, the documents to be executed hereunder and the Schedules attached hereto constitute the entire Agreement among Seller and Buyer pertaining to the subject matter hereof and supersede all prior agreements, understandings, negotiations and discussions, whether oral or written, of Seller and Buyer pertaining to the subject matter hereof.

 

14.5       Amendments and Waivers. This Agreement may not be amended except as provided in a written instrument executed by the Parties. Except for waivers specifically provided for in this Agreement, no right of any Party under this Agreement may be waived except by an instrument in writing signed by the Party to be charged with such waiver and delivered by such Party to the other Party.

 

14.6       Assignment. Neither Buyer nor Seller shall assign all or any portion of its respective rights hereunder or delegate all or any portion of its respective duties hereunder without the prior written consent of the other Party; provided however, the foregoing shall not apply with respect to assignments of Leases by Buyer following Closing.

 

14.7       Press Releases. Without the prior written consent of Buyer, which consent shall not be unreasonably withheld, Seller shall not make, or permit any agent or Affiliate of Seller to make, any public announcement or statement with respect to the transactions contemplated by this Agreement, including the existence of this Agreement and the contents hereof; provided, however, the foregoing shall not restrict disclosures by Seller which are required by applicable securities or other Laws or the applicable rules of any stock exchange having jurisdiction over Seller or its Affiliates.

 

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14.8       Counterparts. This Agreement may be executed by Seller and Buyer in any number of counterparts, each of which shall be deemed an original instrument, but all of which together shall constitute one and the same instrument. This Agreement may be delivered by facsimile, portable document format or similar electronic transmission, and portable document or similar electronic transmission evidencing execution shall be effective as a valid and binding agreement between the Parties for all purposes.

 

14.9       Governing Law; ADR. This Agreement and the transactions contemplated hereby shall be governed by the laws of Texas, without regard to its rules concerning conflicts of laws. Any dispute between the parties, including any disagreement regarding the existence, value or other issue with respect to Title Defects, shall be resolved by binding arbitration under the rules of the American Arbitration Association (Expedited Procedures), provided that the terms of this Agreement shall control to the extent of any conflict. The Parties shall select a single, independent, mutually agreeable arbitrator, or, if the Parties cannot reach agreement, then a single independent arbitrator shall be appointed under the applicable rules (the “Arbitrator”). The Arbitrator’s decision and award shall be delivered within (i) 30 days with respect to any matter asserted or arising as a Title Defect; or (ii) 90 days in all other cases, in each case after submission by either party to the tribunal, and shall thereafter be final and binding upon the parties and enforceable in accordance with Texas law. The Arbitrator shall have broad discretion to limit discovery to the minimum needed to render a decision and award. The costs and fees of the Arbitrator shall be borne equally by Buyer and Seller, provided that the Arbitrator may award all reasonable attorney’s fees and costs of the proceeding to the prevailing party (as determined by the Arbitrator). The Arbitrator shall have authority to fashion any remedy that is fair and equitable to both parties in light of the terms of this Agreement as applied to the circumstances leading to such a dispute, provided that (a) that such remedy shall be no less favorable to Seller than Buyer’s position and no less favorable to Buyer than Seller’s position, and (b) the provisions and limitations of Section 14.13 shall apply to such remedy.

 

14.10       Binding Effect. This Agreement shall be binding upon, and shall inure to the benefit of, the Parties and their respective successors and assigns.

 

14.11       Survival. The representations and warranties of the Parties set forth in Section 6.1 through Section 6.5 and Section 7.1 through 7.4 shall survive the Initial Closing and Subsequent Closing indefinitely. Seller’s representations and warranties set forth in Section 6.14 shall survive the Initial Closing and Subsequent Closing until the date that is thirty (30) days after the expiration of the applicable statute of limitations. The remainder of the representations and warranties of the Parties contained herein shall survive for a period of twelve (12) months after the Subsequent Closing Date and shall then terminate. The covenants and agreements of the Parties shall survive until performed. Any claim for a breach of any such representation or warranty must be made on or before such date or it shall be forever barred. The covenants of the Parties contained in this Agreement shall survive until they are fully performed.

 

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14.12       No Third-Party Beneficiaries. Except as expressly set forth herein, including without limitation in Section 12.3, this Agreement is intended only to benefit the Parties and their respective permitted successors and assigns; and nothing in this Agreement, express or implied, is intended to confer upon any other Person any benefits, rights or remedies.

 

14.13       Limitation on Damages. THE PARTIES EXPRESSLY WAIVE ANY AND ALL RIGHTS TO CONSEQUENTIAL, SPECIAL, INCIDENTAL, PUNITIVE OR EXEMPLARY DAMAGES, OR LOSS OF PROFITS RESULTING FROM BREACH OF THIS AGREEMENT; PROVIDED, HOWEVER, THAT THIS WAIVER SHALL NOT APPLY TO MATTERS COVERED BY SECTION 12.3 ABOVE TO THE EXTENT SUCH DAMAGES ARE ASSERTED BY A THIRD PARTY AGAINST THE PARTY ENTITLED TO DEFENSE AND INDEMNIFICATION THEREUNDER.

 

14.14       Severability. It is the intent of the Parties that the provisions contained in this Agreement shall be severable. Should any provision, in whole or in part, be held invalid as a matter of law, such holding shall not affect the other provisions of this Agreement, and such provisions that are not invalid shall be given effect without the invalid provision.

 

14.15       Time is of the Essence. The Parties understand and agree that time is of the essence in this Agreement.

 

14.16       Disclaimers. The Parties agree that, to the extent required by applicable law to be operative, the disclaimers of warranties contained in this Section 14.16 are “conspicuous” disclaimers for the purposes of any applicable law, rule or order. The express representations and warranties of Seller contained in this Agreement, and the title warranties in the conveyances of the Assets to be delivered at a Closing (collectively “Seller’s Warranties”) are exclusive and are in lieu of all other representations and warranties, express, implied, statutory or otherwise. Seller expressly disclaims any and all such other representations and warranties. Without limitation of the foregoing and except for Seller’s Warranties, the Assets shall be conveyed pursuant hereto without (a) any warranty or representation, whether express, implied, statutory or otherwise, relating to (i) title to the Assets, the condition, quantity, quality, fitness for a particular purpose, conformity to the models or samples of materials or merchantability of any equipment or its fitness for any purpose, (ii) the accuracy or completeness of any data, reports, records, projections, information or materials now, heretofore or hereafter furnished or made available to Buyer in connection with this Agreement, (iii) pricing assumptions, or quality or quantity of Hydrocarbon reserves (if any) attributable to the Assets or the ability or potential of the assets to produce Hydrocarbons, (iv) any implied or express warranty of non-infringement, or (v) any other matters contained in any materials furnished or made available to Buyer by Seller or by Seller’s agents or representatives, or (b) any other express, implied, statutory or other warranty or representation whatsoever. The Assets shall be conveyed to Buyer in their “as is, where is” condition.

 

[Signature Page Follows]

 

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The Parties have executed this Agreement as of the Execution Date.

 

 

SELLER:

 

KEW DRILLING

 

  KEW Drilling,
  By: MPE Financial Group, L.L.C., its
    sole general partner
     
     
  By: /s/ Kathryn W. Francis
    Kathryn W. Francis, Manager  

 

 

 

 

Signature Page to Lease Acquisition Agreement

 

 

 

 

BUYER:

 

LILIS ENERGY, INC.

 

   
  By: /s/ Ronald D. Ormand

  Ronald D. Ormand,
  Executive Chairman of the Board

 

 

 

 

 

 

 

Signature Page to Lease Acquisition Agreement

 

 

 

The following schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K promulgated by the Securities and Exchange Commission (the “SEC”). Lilis Energy, Inc. agrees to furnish supplementally a copy of any omitted schedules to the SEC upon request.

 

Schedules

 

Schedule A - Leases

 

Schedule B – Form of ORRI Assignment

 

Schedule C – Form of Assignment and Conveyance

 

Schedule D – Additional Lease Sections

 

Schedule E – Form of Additional Lease

 

Schedule 6.10 – Required Consents

 

 

 

Exhibit 10.5 

 

** Text Omitted and Filed Separately Confidential Treatment Requested Under 17 C.F.R. §§ 80(b)(4) and 240.24b-2

 

 

 

Execution Version

 

 

 

GAS GATHERING, PROCESSING AND PURCHASE AGREEMENT

 

 

BETWEEN

 

 

LILIS ENERGY, INC

AS “SELLER”

 

 

and

 

 

LUCID ENERGY DELAWARE, LLC

AS “BUYER”

 

 

 

** Text Omitted and Filed Separately Confidential Treatment Requested Under 17 C.F.R. §§ 80(b)(4) and 240.24b-2

 

 

GAS GATHERING, PROCESSING AND PURCHASE AGREEMENT

 

This Gas Gathering, Processing and Purchase Agreement (this “Agreement”) is made and entered into this 10th day of August, 2017 (the “Effective Date”), by and between Lucid Energy Delaware, LLC, a Delaware limited liability company (“Buyer”), and Lilis Energy, Inc., a Nevada corporation (“Seller”). Buyer and Seller are sometimes referred to in this Agreement individually as a “Party” and collectively as the “Parties.”

 

Background:

 

Seller owns, controls, or may acquire Interests (including oil and gas leases) in certain lands in the Dedicated Acreage (as defined in Exhibit A).

 

Seller has or contemplates having a supply of Gas from present and future wells located in the Dedicated Acreage and desires to deliver such Gas to Buyer.

 

Buyer owns and operates, or plans to own and operate, gathering and processing facilities capable of receiving deliveries of Committed Gas (as defined below).

 

Seller desires that Buyer provide gathering, processing and other services as set forth in this Agreement and to sell Gas to Buyer, and Buyer desires to provide to Seller gathering, processing and other services and to purchase Gas from Seller, all in accordance with the terms and conditions stated in this Agreement.

 

Agreement:

 

In consideration of the premises and of the mutual covenants set forth in this Agreement, the Parties agree as follows:

 

ARTICLE I
GENERAL TERMS AND CONDITIONS

 

Exhibit A, which is attached to and made a part of this Agreement, contains general terms and conditions that apply to the Parties’ performance under this Agreement. If there is any conflict between the terms and conditions contained in this Agreement and the terms and conditions contained in Exhibit A, then the body of this Agreement will prevail. Unless otherwise defined, capitalized terms used this Agreement will have the meanings assigned to those terms in Exhibit A.

 

 1 

** Text Omitted and Filed Separately Confidential Treatment Requested Under 17 C.F.R. §§ 80(b)(4) and 240.24b-2

 

ARTICLE II
DEDICATION

 

Article 2.1              Dedication. Beginning on the Effective Date and continuing through the term of this Agreement, subject to the express provisions of this Agreement, Seller does hereby (the “Dedication”): (i) dedicate and commit to deliver all of its Gas produced from, and which is attributable to, well(s) operated by Seller or its Affiliates now or subsequently located on Interests owned by Seller (and its successors and assigns) in the Dedicated Acreage, and (ii) commits to deliver all Gas produced from such wells that is attributable to the interests in such wells owned by working interest, royalty and overriding royalty owners that is not taken “in-kind” by such owners and for which Seller or is Affiliates has the right or obligation to market, for so long as that Gas is not taken “in-kind” by the owners of that Gas (collectively, the “Committed Gas”). If, after the Effective Date, Seller acquires additional Interests located in the Dedicated Acreage, then such Interests shall automatically be subject to this Agreement without any further actions by the Parties; provided, however, if any such Interests or Gas produced from such Interests is subject to a prior written dedication or commitment for gathering, processing or purchase at the time of acquisition, then such Interests or Gas will be excluded from the Dedication (and such Gas will not be subject to this Agreement) until the prior dedication or commitment expires. Upon the expiration or termination of that prior dedication or commitment, such Interests and Gas will automatically be subject to this Agreement without any further actions by the Parties. In addition, Seller shall be entitled to comply with the prior written dedications or commitments for gathering, processing or purchase existing as of the Effective Date and set forth on Exhibit E. If, at any time in the future, Seller (or its successors or assigns) has the right or ability to terminate any prior dedication or commitment covering Interests at no additional cost to Seller, the prior dedication or commitment will be promptly terminated, and upon termination, the Interests subject to the prior dedication or commitment will automatically be subject to this Agreement without any further action by the Parties; provided, however, Seller shall have no obligation to terminate any such prior dedication or commitment to the extent that the Gas subject to such prior dedication or commitment would not constitute Committed Gas hereunder. Seller represents and warrants to Buyer that there are no prior assignments, dedications or commitments covering such Interests assigned and dedicated hereunder or Committed Gas produced therefrom except as set forth on Exhibit E. For the avoidance of doubt, Seller shall not be required to deliver Gas from any well now or subsequently located on the Dedicated Acreage if Seller would be required to install split stream connection facilities or similar facilities to take such Gas in kind from wells operated by an operator other than Seller or its Affiliates, and such Gas shall not be Committed Gas subject to Dedication hereunder. From time to time, and in Seller’s sole discretion, Seller may elect to dedicate and commit hereunder additional Interests located outside of the Dedicated Acreage. Such additional Interests shall only become dedicated and committed hereunder and subject to this Agreement at such time as Seller provides written notice to Buyer of such election; provided, however, such dedication and commitment of the additional Interests shall be subject to the available capacity on the Gathering System. For the avoidance of doubt, any additional Interest dedicated and committed hereunder shall be entitled to the services provided under this Agreement on a Firm basis.

 

Article 2.2              Sale of Committed Gas. From and after the In-Service Date, subject to Article 4.5, Seller agrees to sell and deliver to Buyer at the Receipt Points all Committed Gas.  From and after the In-Service Date, subject to Article 4.5, Buyer will receive and purchase from Seller at the Receipt Points each Day all Committed Gas delivered by Seller in accordance with this Agreement, on a Firm basis.  If Buyer is unable to receive from Seller at the Receipt Points each Day all Committed Gas delivered by Seller in accordance with this Agreement, Seller shall have the right to find an alternative market and such Committed Gas shall be released from the Dedication as provided in Articles 2.3 and 2.4 below.

 

 2 

** Text Omitted and Filed Separately Confidential Treatment Requested Under 17 C.F.R. §§ 80(b)(4) and 240.24b-2

 

Article 2.3              Temporary Release. Notwithstanding anything herein to the contrary, and in addition to any other remedies that Seller may have under this Agreement, at any time after the In-Service Date when Buyer curtails or is otherwise unable to accept all of Seller’s deliveries of Committed Gas for any reason, and there exists no uncured material breach of this Agreement on the part of the Seller, the volumes affected will be, and are hereby, released from this Agreement for a period of time corresponding with Buyer’s curtailment or inability to otherwise accept Seller’s deliveries, and Seller will be free to dispose of such affected volumes under other arrangements for such period. At such time as receipts and deliveries of Committed Gas are no longer interrupted or curtailed, Buyer may resume receipts of released volumes only upon thirty (30) days’ advance written notice as of the beginning of a month unless otherwise agreed.

 

Article 2.4              Permanent Release. Notwithstanding anything herein to the contrary, and in addition to any other remedies that Seller may have under this Agreement, at any time after the In-Service Date, Committed Gas dedicated and committed to Buyer under this Agreement shall be permanently released from the Dedication as follows:

 

(a)               in the event that the Gathering System has insufficient capacity to receive and handle all of the Committed Gas dedicated and committed to Buyer under this Agreement or Buyer is otherwise unable or fails to receive such Committed Gas or fully perform the services under this Agreement and there exists no uncured material breach of this Agreement on the part of the Seller, for a period of at least [**] Days or [**] Days [**] Day period, and such inability is not due to a Force Majeure declared by Buyer, then at Seller’s option and upon written notice to Buyer, Seller shall be granted a permanent release from Dedication to this Agreement of the affected Interests and wells, from which Buyer cannot receive and handle such Committed Gas or perform the services, and all of such Committed Gas produced and producible therefrom. In the event that the Gathering System has insufficient capacity to receive and handle all of the Committed Gas dedicated and committed to Buyer under this Agreement or Buyer is otherwise unable or fails to receive such Committed Gas and/or fully perform the services, and there exists no uncured material breach of this Agreement on the part of the Seller, for a period of at least [**] Days [**] Days [**] Day period and such inability is due to a Force Majeure declared by Buyer, then at Seller’s option and upon written notice to Buyer, Seller shall be granted a permanent release from Dedication to this Agreement of the affected Interests and wells, from which Buyer cannot receive and handle such Committed Gas or perform the services, and all of such Committed Gas produced and producible therefrom;

 

(b)               at Seller’s option and upon written notice to Buyer, in the event that Seller elects to exercise its rights to a permanent release as provided in Article 6.4; and

 

(c)               at Seller’s option and upon written notice to Buyer, in the event that Seller elects to exercise its rights to a permanent release as provided in Section VI of Exhibit A.

 

At the request of Seller, the Parties shall execute a release reasonably acceptable to Seller (which, in the case of a permanent release, shall be in recordable form) reflecting the release of any Receipt Point(s), wells, Interests or Committed Gas released from Dedication hereunder.

 

Article 2.5              Covenant. So long as this Agreement is in effect, this Agreement will: (i) be a covenant running with the Interests now owned by Seller or hereafter acquired (that become subject to this Agreement) by Seller within the Dedicated Acreage, and (ii) be binding on and enforceable by Buyer and its successors and assigns against Seller and all subsequent owners, successors and assigns of all or any part of such Interests in the Dedicated Acreage. Seller will cause any conveyance by it of all or any Interests (or Committed Gas) in the Dedicated Acreage to be made expressly subject to this Agreement, and to cause such transferee to execute a written instrument in a form reasonably satisfactory to Buyer acknowledging such transferee’s obligations and rights under this Agreement. Notwithstanding the foregoing, Seller shall be permitted to sell, transfer, convey, assign, grant, or otherwise dispose of any Interest in the Dedicated Acreage free of the dedication and commitment hereunder (i) in a transaction in which undeveloped Interests within the Dedicated Acreage are exchanged for other Interests located in the Dedicated Acreage that would become subject to dedication and commitment hereunder, and (ii) in a sale (or a series of sales) of undeveloped Interests within the Dedicated Acreage in which the total net acres sold does not exceed [**] percent ([**]%) of the total net acres dedicated and committed under this Agreement.

 

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** Text Omitted and Filed Separately Confidential Treatment Requested Under 17 C.F.R. §§ 80(b)(4) and 240.24b-2

 

Article 2.6              Memorandum. Contemporaneously with the execution of this Agreement and from time to time during the term of this Agreement, the Parties will execute, acknowledge, deliver and record a “short form” memorandum of this Agreement in the form of Exhibit F attached hereto identifying the Dedicated Acreage and identifying the lands, leases and wells in which Seller and its Affiliates own Interests, which will be placed of record in each county within the Dedicated Acreage.

 

ARTICLE III
QUANTITY

 

Article 3.1              Nominations. Seller must provide Buyer written notice that Seller is prepared to flow Committed Gas at least ten (10) Business Days prior to Seller’s estimated date of initial flow, and will include in such notice Seller’s good faith estimate of Daily quantities (stated in both MMBtu and Mcf) of Committed Gas that will be available for sale to Buyer under this Agreement during the initial Month of deliveries. Each Month thereafter, at least ten (10) Business Days before the end of such Month, Seller must estimate the quantities of Committed Gas that will be available for sale to Buyer each Day during the next Month.

 

Article 3.2              Curtailment. Buyer will use reasonable efforts to provide timely notification to Seller by telephone, with subsequent e-mail notification, of the potential size and duration of any unscheduled capacity disruption.

 

Article 3.3              Objectionable Material. In order to ensure that the Gathering System is kept free of water, liquids and solids that could impede free flow of Gas, Buyer may collect or remove from the Gas in the Gathering System any water, liquids or solids which could accumulate in the Gathering System, and in that event Buyer will be responsible for disposal of and liable for the water, liquids and solids so collected and removed, and will own them. The quantities of Gas attributable to the water, liquids and solids so collected or removed from Gas will be retained by Buyer and are hereby conveyed and transferred to Buyer by Seller free and clear of all liens, encumbrances and Claims.

 

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ARTICLE IV
PRICE OF GAS; GAS PURCHASE PAYMENT

 

Article 4.1              Pricing. The purchase price for Seller’s Residue Gas will be a price per MMBtu of Seller’s Residue Gas equal to that described in Paragraph 1 of Exhibit B. The purchase price for Seller’s Plant Products will be a price per gallon of Seller’s Plant Products equal to that described in Paragraph 2(f) of Exhibit B.

 

Article 4.2              Gas Purchase Payment. Buyer’s monthly payment for the purchase of Seller’s Residue Gas and Plant Products will equal the price per MMBtu determined in accordance with Article 4.1 above, multiplied by Seller’s Residue Gas (determined in accordance with Exhibit B) plus the price per gallon determined in accordance with Article 4.1 above, multiplied by Seller’s Plant Products for each component as determined in accordance with Paragraph 2(c) of Exhibit B (the “Gas Purchase Payment”). The Gas Purchase Payment will be reduced by the following, if applicable: (i) the H2S Treating Fee; (ii) the CO2 Treating Fee; (iii) the Processing Fee; (iv) the Inlet Compression Fee; (v) the Electric Power Fee; (vi) the Gathering Fee; (vii) the Maintenance and Meter Fee and (viii) the Nitrogen Fee.

 

Article 4.3              Low Volume at Receipt Points. If the average Daily quantity of Committed Gas delivered by Seller at a Receipt Point over any calendar Month is less than [**] MMBtu per Day for any reason (other than Force Majeure or Buyer’s unexcused failure to accept deliveries from Seller), then Buyer will charge Seller a “Maintenance and Meter Fee” of $[**] per Month for each such Receipt Point for administration, maintenance and meter servicing.

 

Article 4.4              Marketing of Gas. Notwithstanding any other provision in this Agreement to the contrary, Buyer is obligated to sell Seller’s Residue Gas and Seller’s Plant Products but is not obligated to sell Seller’s Residue Gas and Seller’s Plant Products at any particular downstream point or at any particular price, provided however, Buyer shall use commercially reasonable efforts to obtain the best price and terms for the sale of Seller’s Residue Gas and Seller’s Plant Products with unaffiliated third parties.

 

Article 4.5              Take-In-Kind.

 

(a)               Residue Gas. For any calendar [**] during the term of this Agreement, Seller will have the right to elect, by providing Buyer written notice thirty (30) Days’ prior to the beginning of the calendar [**], to take Seller’s Residue Gas “in-kind” at the Delivery Point.  For any calendar [**] that Seller elects to take Seller’s Residue Gas “in-kind”, Buyer will not be required to pay the Gas Purchase Payment to Seller for such “in-kind” Residue Gas, Buyer will list on its monthly statement the fees and other charges owed by Seller pursuant to this Agreement for Buyer’s processing of the Gas related to such “in-kind” Residue Gas, and Seller will pay Buyer for any such fees and other charges pursuant to the terms of Section 8.01 of Exhibit A.  Additionally, during any such calendar [**], the “Take In-Kind Terms” set forth in Exhibit G, as well as the applicable Title, Possession and Responsibility provisions of Section IX of Exhibit A, will apply.

 

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(b)               Plant Products. For any calendar [**] during the term of this Agreement, Seller will have the right to elect, by providing Buyer written notice thirty (30) Days’ prior to the beginning of the calendar [**], to take Seller’s Plant Products “in-kind” at the Plant Products Delivery Point.  For any calendar [**] that Seller elects to take Seller’s Plant Products “in-kind”, Buyer will not be required to pay the Gas Purchase Payment to Seller for such “in-kind” Plant Products, Buyer will list on its monthly statement the fees and other charges owed by Seller pursuant to this Agreement relating to such “in-kind” Plant Products, and Seller will pay Buyer for any such fees and other charges pursuant to the terms of Section 8.01 of Exhibit A.  Additionally, during any such calendar [**] that Seller takes Seller’s Plant Products “in-kind”, the “Take In-Kind Terms” set forth in Exhibit G, as well as the applicable Title, Possession and Responsibility provisions of Section IX of Exhibit A, will apply.

 

ARTICLE V
FEES; FUEL AND ELECTRICITY

 

Article 5.1              Seller will pay to Buyer each of the fees and other amounts, as applicable, set forth on Exhibit C, attached hereto, for the gathering and processing of Committed Gas and other services provided under this Agreement. Buyer shall provide dehydration and compression services with respect to Gas delivered by Seller to the Crittendon Field Station HP and Crittendon Field Station LP Receipt Points (the “Crittendon Receipt Points”), subject to the payment of the Inlet Compression Fee. Initially, Gas delivered by Seller to the Prizehog BWZ Receipt Point, Wildhog BWX Receipt Point and the Crittenden North Receipt Point shall be at high pressure (the “PWC Receipt Points”) and shall not require dehydration or compression services or be subject to the Inlet Compression Fee. At any time prior to the beginning of the sixth (6th) Year of the Agreement Seller may elect, by providing ninety (90) Days prior written notice to have any of the PWC Receipt Points converted to a Low Pressure Receipt Point and Exhibit D will be amended to reflect such election by Seller. To the extent Seller elects such option, Buyer shall provide dehydration and compression services with respect to the Gas delivered by Seller to any such Low Pressure Receipt Point(s), subject to the payment of the Inlet Compression Fee.

 

Article 5.2              System Fuel, Lost and Unaccounted for Gas. Subject to the terms and conditions set forth in this Article 5.2, Buyer will deduct from the volumes of Committed Gas delivered by Seller hereunder, at no cost to Buyer, [**] percent ([**]%) of such Gas in MMBtus delivered by Seller at the Receipt Point(s), which will be attributed to Buyer’s use as (i) Plant Fuel, and (ii) Field Fuel (collectively, “Seller’s Fixed FL&U”). Seller’s Fixed FL&U is comprised of, (a) [**] percent ([**]%) Field Fuel (“Seller’s Fixed Field Fuel”) and (b) [**] percent ([**]%) Plant Fuel (“Seller’s Fixed Plant Fuel”). To the extent Buyer utilizes electric compression to compress Committed Gas, Seller will be responsible, and pay Buyer for, its ratable share of Electrical Power Charges. Notwithstanding anything to the contrary set forth herein, Seller shall not be subject to a deduction for Seller’s Fixed Field Fuel at the High Pressure Receipt Points, and shall only be subject to a deduction for Seller’s Fixed Plant Fuel with respect to the Gas delivered by Seller at the High Pressure Receipt Point(s).

 

Article 5.3              Adjustment of Fees. On the first anniversary of the first Day of the Month following the Effective Date and on each anniversary date thereafter, each fee set forth in this Agreement will be automatically adjusted, by multiplying the current fee by a fraction, the numerator of which will be the [**], and the denominator of which will be [**]; provided however, no such adjustment to any such fee shall exceed [**] percent ([**]%) for any given Year.  Notwithstanding the above, in no event will any fee set forth in this Agreement be adjusted below the fees listed in Exhibit C.

 

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ARTICLE VI
RECEIPT AND DELIVERY POINTS

 

Article 6.1              Receipt Points. Each Receipt Point for Committed Gas delivered by Seller under this Agreement will be at the inlet flange of the measurement facilities located at a mutually agreed point of interconnection between Seller’s facilities and Buyer’s, or its designee’s, Gathering System as further described on Exhibit D attached hereto.

 

Article 6.2              Delivery Points. Each Delivery Point for Residue Gas delivered by Buyer for its own account under this Agreement will be at the inlet flange of the measurement facilities of each Delivery Point that is set forth on Exhibit D. The foregoing notwithstanding, Buyer may, at its sole discretion, add a Delivery Point to Exhibit D at any time; provided that, any such addition shall not adversely affect the price and terms for the sale of Seller’s Residue Gas and Seller’s Plant Products.

 

Article 6.3              Plant Products Delivery Points. Each Plant Products Delivery Point for recovered Plant Products delivered by Buyer for its own account under this Agreement will be at the inlet flange of the measurement facilities of each Plant Products Delivery Point that is set forth on Exhibit D. The foregoing notwithstanding, Buyer may, at its sole discretion, add a Plant Products Delivery Point to Exhibit D at any time.

 

Article 6.4              Receipt Point Connections.

 

(a)               Completion Deadline. Buyer, at its sole risk, cost and expense, shall construct and connect and shall cause the following Receipt Points, each as more particularly described on Exhibit D, to be installed and fully operational for the receipt of Committed Gas on or before the following dates (each such date, a “Completion Deadline”):

 

Prizehog BWZ: November 1, 2017;

 

Wildhog BWX: November 1, 2017;

 

Crittendon Field Station LP: December 15, 2017;

 

Crittendon Field Station HP: December 15, 2017; and

 

Crittendon North: April 1, 2018.

 

The Prizehog BWZ and Wildhog BWX Receipt Point(s) shall be designed and constructed for capacities ranging from 0 Mcf/day to 10,000 Mcf/Day, and the Crittendon Field Station LP, Crittendon Field Station HP, and Crittendon North Receipt Point(s) shall be designed and constructed for capacities ranging from 0 Mcf/Day to 50,000 Mcf/day. Such Receipt Point(s) shall be expanded from time to time as necessary for Buyer to receive all of Committed Gas delivered by Seller.

 

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(b)               Force Majeure Delay. To the extent the delay in causing any Receipt Point completion to occur by the respective Completion Deadline is due to a properly noticed Force Majeure event, then for each Day of the Force Majeure event, Buyer shall have one additional Day within which to cause any such Receipt Point completion to occur, and such Completion Deadline shall be extended accordingly.

 

(c)               Receipt Point Completion Delays.

 

(i)       If Buyer fails to cause any Receipt Point completion to occur on or before the respective Completion Deadline, but Buyer causes such Receipt Point completion to occur on or before the [**] Day after such Completion Deadline, then for a period equal to [**] times the number of Days after such Completion Deadline until Buyer causes such Receipt Point completion to occur, the fee(s) payable by Seller set forth on Exhibit C shall be reduced by [**]% for such Receipt Point.

 

(ii)       If Buyer fails to cause any Receipt Point completion to occur on or before the [**] Day after the respective Completion Deadline, then for a period equal to [**] times the number of Days after such Completion Deadline until Buyer causes such Receipt Point completion to occur, the fee(s) payable by Seller set forth on Exhibit C shall be reduced by [**]% for such Receipt Point.

 

(iii)       Without limiting Seller’s rights above, if Buyer fails to cause the Receipt Point completion for any such Receipt Point to occur on or before the [**] Day after the respective Completion Deadline, then Seller may elect to permanently release from the Dedication any such Receipt Point, the affected Interests and all existing and future wells that would have otherwise been delivered to such Receipt Point, and all of such Committed Gas produced or producible therefrom. Prior to Seller’s election to permanently release under this Article 6.4(c)(iii), Seller must provide Buyer reasonable documentation evidencing the Receipt Point, the affected Interests and all existing and future wells that would have been delivered to such Receipt Point. Seller’s right to permanent release pursuant to this Article 6.4(c)(iii) shall expire when the Receipt Point completion for each such Receipt Point has occurred.

 

ARTICLE VII
TERM

 

This Agreement is effective as of the Effective Date, and, unless terminated earlier in accordance with any express provision of this Agreement, will remain in full force and effect for a primary term of ten (10) Years following the Effective Date and, unless terminated by either Party upon at least ninety Days’ written notice prior to the end of such primary term, will continue year to year until ninety (90) Days’ written notice is provided by a Party prior to the end of any term extension. Termination will be effective on the last Day of the primary term or yearly term extension, whichever is applicable. Upon final termination under this Article VII, the Dedication hereunder shall terminate.

 

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** Text Omitted and Filed Separately Confidential Treatment Requested Under 17 C.F.R. §§ 80(b)(4) and 240.24b-2