Document


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 
FORM 10-Q
 
ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 For the quarterly period ended September 30, 2018
 
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
Commission file number: 001-35330
 
Lilis Energy, Inc.
(Name of registrant as specified in its charter)
 
Nevada
 
74-3231613
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
1800 Bering Drive, Suite 510, Houston, Texas 77057
(Address of principal executive offices, including zip code)
 
Registrant’s telephone number including area code: (817) 585-9001
 
Indicate by check mark if the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý    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 ý    No ¨
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company, or emerging growth company (as defined in Rule 12b-2 of the Act):
 
Large accelerated filer
¨
Accelerated filer
ý
Non-accelerated filer 
¨
Smaller reporting company  
¨
Emerging growth company 
¨
 
 
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨    No ý

As of October 31, 2018, 71,969,815 shares of the registrant’s common stock were issued and outstanding.

 




Lilis Energy, Inc.

INDEX
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


2




Forward-Looking Statements
 
This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. The statements contained in this report that are not historical facts are forward-looking statements that represent management’s beliefs and assumptions based on currently available information. Forward-looking statements include information concerning our possible or assumed future results of operations, business strategies, need for financing, competitive position, and potential growth opportunities. Our forward-looking statements do not consider the effects of future legislation or regulations. Forward-looking statements include all statements that are not historical facts and can be identified by the use of forward-looking terminology such as the words “believes,” “intends,” “may,” “should,” “anticipates,” “expects,” “could,” “plans,” “estimates,” “projects,” “targets,” or comparable terminology or by discussions of strategy or trends. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we cannot give any assurances that these expectations will prove to be correct. Such statements by their nature involve risks and uncertainties that could significantly affect expected results, and actual future results could differ materially from those described in such forward-looking statements.
 
Among the factors that could cause actual future results to differ materially are the risks and uncertainties discussed in this report and in our Annual Report (as defined in Note 2 hereafter). Should our underlying assumptions prove incorrect or the consequences of the aforementioned risks worsen, actual results could differ materially from those expected. Forward-looking statements speak only as to the date hereof. All such forward-looking statements and any subsequent written or oral forward-looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the statements contained herein or referred to in this section and any other cautionary statements that may accompany such forward-looking statements. Except as otherwise required by applicable law, we disclaim any intention or obligation to update publicly or revise such statements whether as a result of new information, future events or otherwise.

There may also be other risks and uncertainties that we are unable to predict at this time or that we do not now expect to have a material adverse impact on our business.


3




GLOSSARY
 
In this Quarterly Report, the following abbreviation and terms are used:
 
Bbl. Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude, condensate or natural gas liquids.
 
Bcf. Billion cubic feet of natural gas.
 
Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one barrel of crude oil or condensate.
 
BLM. The Bureau of Land Management of the United States Department of the Interior.
 
BOE. One barrel of crude oil equivalent, determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.
 
BOE/d. Barrels of oil equivalent per day.
 
BO/d. Barrel of oil per day.
 
BTU or British Thermal Unit. The quantity of heat required to raise the temperature of one pound mass of water by 28.5 to 59.5 degrees Fahrenheit.
 
Completion. Installation of permanent equipment for production of oil or natural gas.
 
Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure but that, when produced, is in the liquid phase at surface pressure and temperature.
 
Development well. A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.
 
Drilling locations. Total gross locations specifically quantified by management to be included in our multi-year drilling activities on existing acreage. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors.
 
Dry well or dry hole. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
 
Exploratory well. A well drilled to find a new field or to find a new reservoir. Generally, an exploratory well in any well that is not a development well, an extension well, a service well or a stratigraphic well.
 
FERC. The Federal Energy Regulatory Commission.
 
Field. An area consisting of either a single reservoir or multiple reservoirs all grouped on or related to the same geological structural feature and/or stratigraphic condition.
 
Formation. An identifiable layer of subsurface rocks named after its geographical location and dominant rock type.
 
Gross acres, gross wells, or gross reserves. A well, acre or reserve in which we own a working interest, reported at the 100% or 8/8ths level. For example, the number of gross wells is the total number of wells in which we own a working interest.
 
Lease. A legal contract that specifies the terms of the business relationship between an energy company and a landowner or mineral rights holder on a particular tract of land.
 
Leasehold. Mineral rights leased in a certain area to form a project area.
 
MBBLs. One thousand barrels of crude oil or other liquid hydrocarbons.
 


4




MBOE. One thousand barrels of crude oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
  
Mcf. One thousand cubic feet of natural gas.
 
Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
 
MMbtu. One million British Thermal Units.
 
MMcf. One million cubic feet of natural gas.
 
Net acres or net wells. The sum of fractional ownership working interests in gross acres or gross wells. The number of net acres or wells is the sum of the fractional working interests owned in gross acres or wells expressed as whole numbers and fractions of whole numbers.
 
NGL. Natural gas liquids, or liquid hydrocarbons found as a by-product of natural gas.
 
Overriding royalty interest. Is similar to a basic royalty interest except that it is created out of the working interest. For example, an operator possesses a standard lease providing for a basic royalty to the lessor or mineral rights owner of 1/8 of 8/8. This then entitles the operator to retain 7/8 of the total oil and natural gas produced. The 7/8 in this case is the 100% working interest the operator owns. This operator may assign his working interest to another operator subject to a retained 1/8 overriding royalty. This would then result in a basic royalty of 1/8, an overriding royalty of 1/8 and a working interest of 3/4. Overriding royalty interest owners have no financial or other obligation or responsibility for developing and operating the property. The only expenses borne by the overriding royalty owner are a share of the production or severance taxes and sometimes costs incurred to make the oil or gas salable.
 
Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.
 
Production. Natural resources, such as oil or gas, flowed or pumped out of the ground.
 
Productive well. A producing well or a well that is mechanically capable of production.
 
Proved developed oil and natural gas reserves. Proved developed oil and natural gas reserves are proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
 
Proved reserves. Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
 
Proved undeveloped reserves. Proved undeveloped oil and natural gas reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
 
Project. A targeted development area where it is probable that commercial oil and/or natural gas can be produced from new wells.
 
Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
 
Recompletion. The process of re-entering an existing well bore that is either producing or not producing and modifying the existing completion and/or completing new reservoirs in an attempt to establish new production or increase or re-activate existing production.
 

5



Reserves. Estimated remaining quantities of oil, natural gas and natural gas liquids anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
 
Reservoir. A subsurface formation containing a natural accumulation of producible natural gas and/or oil that is naturally trapped by impermeable rock or other geologic structures or water barriers and is individual and separate from other reservoirs.
  
Secondary Recovery. A recovery process that uses mechanisms other than the natural pressure or fluid drive of the reservoir, such as gas injection or water flooding, to produce residual oil and natural gas remaining after the primary recovery phase.
 
Shut-in. A well suspended from production or injection but not abandoned.
 
Standardized measure. The present value of estimated future cash flows from proved oil and natural gas reserves, less future development, abandonment, production and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.
 
Successful. A well is determined to be successful if it is producing oil or natural gas in paying quantities.
 
Undeveloped acreage. Leased acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas regardless of whether such acreage contains proved reserves.
 
Water-flood. A method of secondary recovery in which water is injected into the reservoir formation to maintain or increase reservoir pressure and displace residual oil and enhance hydrocarbon recovery.
 
Working interest. The operating interest that gives the lessees/owners the right to drill, produce and conduct operating activities on the property, and to receive a share of the production revenue, subject to all royalties, overriding royalties and other burdens, all development costs, and all risks in connection therewith.
 


6



PART I – FINANCIAL INFORMATION
Item 1. Financial Statements.

7



Lilis Energy, Inc. and Subsidiaries
Condensed Consolidated Balance Sheets
(In thousands, except share and per share data)
 
September 30, 2018
 
December 31, 2017
 
(Unaudited)
 
 
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
24,954

 
$
17,462

Accounts receivables, net of allowance of $25 and $39, respectively
17,758

 
7,426

Derivative instruments
532

 

Prepaid expenses and other current assets
2,259

 
584

Total current assets
45,503

 
25,472

Oil and natural gas properties, full cost method of accounting
 
 
 
Unproved
167,324

 
101,771

Proved
308,691

 
141,717

Less: accumulated depreciation, depletion, amortization and impairment
(90,583
)
 
(73,183
)
Total oil and natural gas properties, net
385,432

 
170,305

Other property and equipment, net
451

 
76

Other assets
124

 
91

Total other assets
575

 
167

Total assets
$
431,510

 
$
195,944

LIABILITIES AND STOCKHOLDERS' DEFICIT
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
30,336

 
$
10,488

Accrued liabilities
26,901

 
7,634

Revenue payable
13,445

 
6,460

Dividends payable
6,527

 

Derivative instruments - current
5,201

 
853

Total current liabilities
82,410

 
25,435

Asset retirement obligations
1,228

 
726

Long-term debt, less current maturities
166,259

 
127,794

Long-term derivative instruments
56,650

 
72,937

Long-term deferred revenue liabilities
52,515

 

Total liabilities
359,062

 
226,892

Commitments and contingencies (Note 17)


 


Redeemable Preferred Stock:
 
 
 
Series C convertible preferred stock, $0.0001 par value; stated value of $1,000; 100,000 shares authorized, 100,000 issued and outstanding with a liquidation preference of $124,923 at September 30, 2018
97,506

 

Stockholders’ deficit:
 
 
 
Common stock, $0.0001 par value per share; 150,000,000 shares authorized, 65,768,908 and 53,368,331 shares issued and outstanding as of September 30, 2018 and December 31, 2017, respectively, of which 253,598 shares are being held as treasury stock as of September 30, 2018
6

 
5

Additional paid-in capital
301,039

 
272,335

Accumulated deficit
(325,106
)
 
(303,288
)
Treasury stock (253,598 shares at cost)
(997
)
 

Total stockholders’ deficit
(25,058
)
 
(30,948
)
Total liabilities and stockholders’ deficit
$
431,510

 
$
195,944


 

8



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

9



Lilis Energy, Inc. and Subsidiaries
Condensed Consolidated Statements of Operations (Unaudited)
(In thousands, except share and per share data)
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
Revenues:
 
 
 
 
 
 
 
Oil sales
$
15,976

 
$
4,378

 
$
42,819

 
$
11,040

Natural gas sales
1,538

 
592

 
3,572

 
1,631

Natural gas liquid sales
1,968

 
420

 
4,969

 
1,108

Total revenues
19,482

 
5,390

 
51,360

 
13,779

Operating expenses:
 
 
 
 
 
 
 
Production costs
2,772

 
1,409

 
8,532

 
3,336

Gathering, processing and transportation
963

 
405

 
2,297

 
842

Production and ad valorem taxes
1,446

 
290

 
3,604

 
710

General and administrative
6,838

 
10,943

 
24,682

 
36,273

Depreciation, depletion, amortization and accretion
7,172

 
1,443

 
17,572

 
3,946

Total operating expenses
19,191

 
14,490

 
56,687

 
45,107

Operating income (loss)
291

 
(9,100
)
 
(5,327
)
 
(31,328
)
Other income (expense):
 
 
 
 
 
 
 
Other income
1

 
151

 
2

 
19

Loss from commodity derivatives
(4,811
)
 

 
(9,383
)
 

Change in fair value of financial instruments
10,612

 
6,368

 
19,499

 
4,254

Interest expense
(8,949
)
 
(3,656
)
 
(26,609
)
 
(11,084
)
Total other income (expense)
(3,147
)
 
2,863

 
(16,491
)
 
(6,811
)
Net loss before income taxes
(2,856
)
 
(6,237
)
 
(21,818
)
 
(38,139
)
Income tax expense

 

 

 

Net loss
(2,856
)
 
(6,237
)
 
(21,818
)
 
(38,139
)
Less:
 
 
 
 
 
 
 
Dividends on Series C convertible preferred stock
(2,410
)
 

 
(6,527
)
 

Dividends and deemed dividends on Series B convertible preferred stock

 

 

 
(4,635
)
Dividends on conditionally redeemable 6% preferred stock

 

 

 
(122
)
Net loss attributable to common stockholders
$
(5,266
)
 
$
(6,237
)
 
$
(28,345
)
 
$
(42,896
)
 
 
 
 
 
 
 
 
Net loss per common share-basic and diluted: (Note 14)
 
 
 
 
 
 
 
Basic
$
(0.08
)
 
$
(0.12
)
 
$
(0.47
)
 
$
(1.06
)
Diluted
$
(0.09
)
 
$
(0.12
)
 
$
(0.47
)
 
$
(1.06
)
 
 
 
 
 
 
 
 
Weighted average common shares outstanding:
 
 
 
 
 
 
 
Basic
64,572,104

 
50,785,588

 
60,082,902

 
40,596,281

Diluted
88,710,081

 
50,785,588

 
60,082,902

 
40,596,281


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


10



Lilis Energy, Inc. and Subsidiaries
Condensed Consolidated Statements of Changes in Stockholders’ Deficit
(in thousands, except share data)
(Unaudited)
 
 
Common Shares
 
Additional
Paid In Capital
 
Treasury Stock
 
Accumulated Deficit
 
Total
 
Shares
 
Amount
 
 
Shares
Amount
 
 
Balance, December 31, 2017
53,368,331


$
5


$
272,335



$


$
(303,288
)

$
(30,948
)
Stock based compensation




7,654







7,654

Common stock for restricted stock
802,860












Common stock withheld for taxes on stock-based compensation
(315,439
)



(1,051
)






(1,051
)
Common stock for acquisition of oil and gas properties
6,940,722


1


24,777







24,778

Exercise of warrants and stock options
4,972,434




3,628







3,628

Reclassification of warrant derivative liabilities




223







223

Purchase of treasury stock






(253,598
)
(997
)



(997
)
Dividends on Series C convertible preferred stock




(6,527
)






(6,527
)
Net loss









(21,818
)

(21,818
)
Balance, September 30, 2018
65,768,908


$
6


$
301,039


(253,598
)
$
(997
)

$
(325,106
)

$
(25,058
)


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


11



Lilis Energy, Inc. and Subsidiaries
Condensed Consolidated Statements of Cash Flows (Unaudited)
(In thousands) 
 
Nine Months Ended September 30,
 
2018
 
2017
Cash flows from operating activities:
 
 
 
Net loss
$
(21,818
)
 
$
(38,139
)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
 
 
 
Stock based compensation
7,654

 
14,477

Bad debt expense (recovery)
(14
)
 
12

Amortization of debt issuance cost
1,130

 
1,673

Accretion of debt discount
11,893

 
5,030

Payable in-kind interest
9,810

 
3,258

Loss from commodity derivatives, net
7,250

 

Net cash settlement paid for commodity derivative contracts
2,133

 

Change in fair value of financial instruments
(19,499
)
 
(4,254
)
Depreciation, depletion, amortization and accretion
17,572

 
3,946

Changes in operating assets and liabilities:
 
 
 
Accounts receivable
(7,818
)
 
(2,364
)
Prepaid expenses and other assets
(1,707
)
 
(13
)
Accounts payable and accrued liabilities
27,093

 
8,764

Proceeds for options associated with salt water disposal infrastructure and future gas midstream services recorded as deferred revenue in other long-term liabilities
50,000

 

Net cash provided by (used in) operating activities
83,679

 
(7,610
)
Cash flows from investing activities:
 
 
 
Net proceeds from sale of DJ Basin properties

 
1,082

Acquisition of oil and gas properties
(61,416
)
 

Capital expenditures
(129,490
)
 
(64,771
)
Net cash used in investing activities
(190,906
)
 
(63,689
)
Cash flows from financing activities:
 
 
 
Proceeds from issuance of Series C Preferred Stock
100,000

 

Proceeds from private placement

 
18,400

Proceeds from exercise of accordion features of 2016 Term Loans

 
6,706

Proceeds from Bridge Loan and Second Lien Term Loans

 
94,700

Proceeds from issuance of Riverstone Term Loans
50,000

 

Debt Issuance Costs
(2,546
)
 

Equity Financing Costs
(2,494
)
 

Repayment of debt
(31,821
)
 
(40,390
)
Repurchase of common stock
(997
)
 

Proceeds from exercise of warrants and stock options
3,628

 
392

Payment for tax withholding on stock-based compensation
(1,051
)
 
(2,427
)
Net cash provided by financing activities
114,719

 
77,381

Net increase in cash, cash equivalents and restricted cash
7,492

 
6,082

Cash, cash equivalents and restricted cash at beginning of period
17,462

 
11,738

Cash, cash equivalents and restricted cash at end of period
$
24,954

 
$
17,820

Supplemental disclosure:
 
 
 
Cash paid for interest
$
3,776

 
$
1,594


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

12



Lilis Energy, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(Unaudited)
 
NOTE 1 - ORGANIZATION
  
Lilis Energy, Inc. (“Lilis” or the “Company”) is an independent oil and natural gas exploration and production company focused on the Delaware Basin in Winkler, Loving, and Reeves Counties, Texas and Lea County, New Mexico.
 
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND ESTIMATES
 
Principles of Consolidation and Presentation
 
The condensed consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, namely Brushy Resources, Inc. ("Brushy Resources"), ImPetro Operating, LLC, ImPetro Resources, LLC, Lilis Operating Company, LLC, and Hurricane Resources LLC. All significant intercompany accounts and transactions have been eliminated in consolidation. The unaudited condensed consolidated financial statements included herein reflect all adjustments (consisting only of normal, recurring adjustments) which are, in our opinion, necessary for a fair presentation of the information as of and for the periods presented. These unaudited condensed consolidated interim financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”) for interim financial information and the instructions to Quarterly Report on Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all disclosures required under GAAP for complete consolidated financial statements.

These unaudited condensed consolidated financial statements should be read in conjunction with our annual report on Form 10–K for the twelve months ended December 31, 2017, as filed with the Securities and Exchange Commission ("SEC") on March 9, 2018 (the “Annual Report”).
   
Use of Estimates
 
The accompanying condensed consolidated financial statements are prepared in conformity with GAAP which requires the Company to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities; disclosure of contingent assets and liabilities at the date of the financial statements, the reported amounts of revenues and expenses during the reporting period; and the quantities and values of proved oil, natural gas and natural gas liquid (“NGL”) reserves used in calculating depletion and assessing impairment of its oil and natural gas properties. The most significant estimates pertain to the evaluation of unproved properties for impairment, proved oil and natural gas reserves and related cash flow estimates used in the depletion and impairment of oil and natural gas properties; the timing and amount of transfers of our unevaluated properties into our amortizable full cost pool; the fair value of embedded derivatives and commodity derivative contracts, accrued oil and natural gas revenues and expenses valuation of options and warrants, inducement transactions and common stock; and the allocation of general administrative expenses. Actual results could differ significantly from these estimates.
 
Reclassifications
 
Certain reclassifications have been made to the prior period financial statements to conform to the current period presentation. These reclassifications have no effect on the Company’s previously reported results of operations. For the three and nine months ended September 30, 2017, the income from operator’s overhead recovery of approximately $0.27 million and $0.33 million, respectively, have been reclassified from revenue to operating expense as an offset against general and administrative expenses in the condensed consolidated statement of operations.
 
Recently Adopted Accounting Standards
 
On January 1, 2018, the Company adopted the new accounting standard, Accounting Standards Codification, ASC 606, Revenue from Contracts with Customers and all the related amendments (the “New Revenue Standard”) using the modified retrospective method. In accordance with the modified retrospective method, comparative information is not restated and continues to be reported under the accounting standards in effect for those periods. The cumulative effect of initially adopting the New Revenue Standard, if any, is recorded as an adjustment to the opening balance of retained earnings. The Company’s revenue from customers is derived from production and sales of crude oil, natural gas and NGLs and recognized when control is transferred to the customer. As operator, the Company may market production on behalf of joint interest partners and various royalty owners. Under the terms of our joint operating agreements, the Company does not take control of the production attributable to our joint interest partners and the various royalty owners. Consequently, the Company recognizes revenues only for its share of the

13



production. In accordance with the New Revenue Standard requirements, the impact of adoption on our condensed consolidated statements of operations and condensed consolidated balance sheets was as follows:
Three Months Ended September 30, 2018
As Reported
 
Balances
without
Adoption of
ASC 606
 
Increase
(Decrease)
Condensed Consolidated Statements of Operations:
 

 
 

 
 

Revenues
$
19,482

 
$
19,508

 
$
(26
)
Operating expenses
$
(963
)
 
$
(989
)
 
$
(26
)
 
 
 
 
 
 
Nine Months Ended September 30, 2018
 
 
 
 
 
Condensed Consolidated Statements of Operations:
 
 
 
 
 
Revenues
$
51,360

 
$
51,451

 
$
(91
)
Operating expenses
$
(2,297
)
 
$
(2,388
)
 
$
(91
)
 
 
 
 
 
 
As of September 30, 2018
 
 
 
 
 
Condensed Consolidated Balance Sheets:
 
 
 
 
 
Accounts receivable
$
17,758

 
$
17,849

 
$
(91
)
Accrued liabilities
$
(26,901
)
 
$
(26,992
)
 
$
(91
)


As shown in this comparison table, there is no impact on the net loss from the New Revenue Standard adoption and, therefore, no adjustment to the opening balance of accumulated deficit. Prior to the adoption of the New Revenue Standard, the revenue line included the value of our natural gas gatherer’s contractual volume retainage fee, with an offsetting cost included in the gathering, processing and marketing costs line. In accordance with the New Revenue Standard, the Company will only recognize revenues for its share of the production, resulting in the removal of the retainage fee approximating $26,000 and $91,000 from both revenues and operating expenses during the three and nine months ended September 30, 2018, respectively.
 
On July 13, 2017, the Financial Accounting Standards Board (“FASB”) issued a two-part ASU 2017-11, (Part I) Accounting for Certain Financial Instruments with Down Round Features, (Part II) Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Redeemable Noncontrolling Interests with a Scope Exception (ASU 2017-11). Part I of ASU 2017-11 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 ASU 2017-11 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 ASU 2017-11 related to down rounds are effective for public business entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. Early adoption is permitted for all organizations. The Company elected to adopt ASU 2017-11 on January 1, 2018. The Company’s SOS Warrant Liability (as described in Note 6) was accounted for as a derivative instrument solely because of its down round feature. Any outstanding SOS Warrants as of the date of adoption were reclassified to equity and the Company will no longer recognize any gain or loss based on the fair value of the SOS Warrants. No other derivatives instruments were affected by the adoption of ASU 2017-11.
 
On January 5, 2017, the FASB issued ASU 2017-01 Business Combinations (Topic 805): Clarifying the Definition of a Business (ASU 2017-01), 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. ASU 2017-01 introduces a screen for determining when assets acquired are not a business and clarifies that a business must include, at a minimum, an input and a substantive process that contribute to an output to be considered a business. This standard is effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period. The Company adopted ASU 2017-01 on January 1, 2018. On March 15, 2018, the Company completed an acquisition of proved and unproved properties from OneEnergy Partners, LLC (“OEP”) (See Note 5-Acquisitions and Divestitures). As a result of the adoption of ASU 2017-01, the Company accounted for the acquisition as an asset purchase instead of a business combination. As a result, acquisition costs of approximately $1.1 million were capitalized as part of the acquisition and the purchase price was allocated to unproved and proved properties based on relative fair value.


14



On January 1, 2018, the Company retroactively adopted ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force).” This ASU requires the statements of cash flows to present the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents are now included with cash and cash equivalents when reconciling the beginning of period and end of period amounts presented on the statements of cash flows. The retrospective application of this new accounting guidance resulted in a decrease of $0.6 million in “restricted cash” in Cash Flows from Investing Activities, an increase of $0.6 million in “Cash, Cash Equivalents, and Restricted Cash, beginning of the period,” and an increase of $0.6 million in “Cash, Cash Equivalents, and Restricted Cash, end of period” in the Company's accompanying condensed consolidated statement of cash flows for the nine months ended September 30, 2017, from what was previously presented in our Quarterly Report on Form 10–Q for the quarterly period ended September 30, 2017. The $0.6 million in restricted cash was refunded to the Company during 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 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 July 30, 2018, the FASB issued ASU 2018-11, Leases (Topic 842): Targeted Improvements, which provides entities with an additional (and optional) transition method to adopt the new leases standard. Under this new transition method, an entity initially applies the new leases standard at the adoption date and recognizes a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. ASU 2018-11 also provides lessors with a practical expedient, by class of underlying asset, to not separate non-lease components from the associated lease component and, instead, to account for those components as a single component if the non-lease components otherwise would be accounted for under Topic 606 and both the timing and pattern of transfer of the non-lease component(s) and associated lease component are the same, and the lease component, if accounted for separately, would be classified as an operating lease. If the non-lease component or components associated with the lease component are the predominant component of the combined component, an entity is required to account for the combined component in accordance with Topic 606. Otherwise, the entity must account for the combined component as an operating lease in accordance with Topic 842. The Company expects to adopt the new lease standard on January 1, 2019 using the optional transition method.

On June 20, 2018, the FASB issued ASU 2018-07, Improvements to Nonemployee Share-Based Payment Accounting, which supersedes most of the prior accounting guidance on nonemployee share-based payments, and instead aligns it with existing guidance on employee share-based payments in Topic 718. As a result, nonemployee share-based payment transactions will be measured by estimating the fair value of the equity instruments that an entity is obligated to issue and the measurement date will be consistent with the measurement date for employee share-based payment awards (i.e., grant date for equity-classified awards). Probability is to be considered on nonemployee awards with performance conditions. The classification will continue to be subject to the requirements of Topic 718, Compensation - Stock Compensation, although cost recognition of nonemployee awards will remain unchanged (i.e., as if paid in cash). The ASU provides certain accounting alternatives to private companies, including the use of the calculated value method and a one-time option to apply intrinsic value to liability-classified awards. The amendments become effective for public business entities for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. For all other entities, the ASU is effective for fiscal years beginning after December 15, 2019, and interim periods within fiscal years beginning after December 15, 2020. Early adoption is permitted, but no earlier than an entity’s adoption date of Topic 606. The Company elected to early adopt the ASC 2018-07 during the quarter ended September 30, 2018. As a result, during the three and nine months ended September 30, 2018, the Company recognized $0.5 million and $2.4 million of non-employee share-based compensation, respectively.
 
On February 25, 2016, the FASB issued ASU 2016-02, Leases (Topic 842) (ASU 2016-02), 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 standard will be effective for annual and interim periods beginning after December 15, 2018, with earlier application permitted. The Company plans on adopting this guidance on January 1, 2019, using the modified retrospective approach. Oil and natural gas leases are scoped out of ASU 2016-02. The Company is currently evaluating the impact this ASU will have on the consolidated financial statements and related disclosures. As a part of the assessment work to-date, the Company has engaged an external consulting firm and is evaluating agreements under this ASU as well as assessing the completeness of the lease population. While the Company cannot currently estimate the quantitative effect that ASU 2016-02 will have on its consolidated financial statements, the adoption will increase asset and liability balances on the consolidated balance sheets due to the required recognition of right-of-use assets and corresponding lease liabilities. The quantitative effect is also dependent on active leases at the time of adoption. In addition, the Company is in the process of implementing new lease accounting software to properly account for the leases upon adoption.

15




Accrued Liabilities
 
At September 30, 2018 and December 31, 2017, the Company’s accrued liabilities consisted of the following:
 
 
September 30, 2018
 
December 31, 2017
 
($ in thousands)
Accrued bonus
$
1,234

 
$
3,000

Accrued capital expenditures
20,927

 
3,615

Other accrued liabilities
4,740

 
1,019

 
26,901

 
$
7,634

 

16



NOTE 3 – REVENUE
 
Revenue is recognized when control passes to the purchaser which generally occurs when production is transferred to the purchaser. The Company measures revenue as the amount of consideration it expects to receive in exchange for the commodities transferred. All of the Company’s revenues from contracts with customers represent products transferred at a point in time as control is transferred to the customer.
 
The Company records revenue based on consideration specified in its contracts with its customers. The amounts collected on behalf of third parties are recorded in revenue payable. The Company recognizes revenue in the amount that reflects the consideration it expects to receive in exchange for transferring control of those goods to the customer. The contract consideration in the Company’s variable price contracts is typically allocated to specific performance obligations in the contract according to the price stated in the contract. Payment is generally received one or two months after the sale has occurred.

Crude oil revenues
 
Crude oil from our operated properties is produced and stored in field tanks. The Company recognizes crude oil revenue when control passes to the purchaser. The Company’s crude oil is currently sold under a single short-term contract. The purchaser’s commitment includes all quantities of crude oil from the leases that are covered by the contract, with no quantity-based restrictions or variable terms. Pricing is based on posted indexes for crude oil of similar quality, less a fees deduction that is subject to negotiation. As of the most recent contract amendments, the negotiable fees deduction is $5.25 per barrel from June 1, 2018 through July 31, 2018, then $5.15 per barrel from August 1, 2018 through February 28, 2019, continuing on a month-to-month basis thereafter unless renegotiated or canceled upon 30 days' notice. The posted index prices change monthly based on the average of daily index price points for each sales month.
 
Natural gas and NGL revenues
 
Natural gas is produced and transported via pipelines to gas processing facilities. NGLs are extracted from the natural gas at the processing facilities and processed natural gas and NGLs are marketed and sold separately on the Company’s behalf after processing. All of our operated natural gas production is sold under one of three natural gas contracts which are long-term in nature; however, one of these natural gas contracts includes 30-day cancellation provisions, and the Company therefore classifies such contract as short-term. The processor’s commitment to sell on the Company’s behalf includes all quantities of natural gas and NGLs produced from specific wellbores or dedicated acreage as defined in the contract, with no quantity-based restrictions or variable terms. The gas contracts are generally market based pricing less adjustments for transportation and processing fees. A portion of natural gas delivered to the processing plants is used as fuel at the processing plant without reimbursement. The Company recognizes revenue for natural gas and NGLs when control passes at the tailgate of the processing plant.
 
Gathering, processing and transportation
 
Natural gas must be transported to a gas processing plant facility for treatment and to extract NGLs, then the final residue gas and liquid products are marketed for sale to end users at the tailgate of the plant. As a result of these activities, the Company incurs costs that are contractually passed to it from the gatherer per customary industry practice. Such costs include fees for gathering the gas and moving it from wellhead to plant inlet, plant electricity usage, inlet compression, carbon dioxide and hydrogen sulfide treatments, processing tax, fuel usage, and marketing at the tailgate. Gathering, processing and transportation costs are presented as operating expenses in the Company's condensed consolidated statement of operations.
 
Imbalances
 
Natural gas imbalances occur when the Company sells more or less than its entitled ownership percentage of total natural gas production. Any amount received in excess of its share is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable. The Company did not have any significant natural gas imbalance positions as of September 30, 2018 and December 31, 2017.
 
Contract balances and prior period performance obligations
 
The Company is entitled to payment from purchasers once its performance obligations have been satisfied upon delivery of the product, at which point payment is unconditional, and the Company records these invoiced amounts as accounts receivable in its condensed consolidated balance sheets.
 

17



To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and also recorded as accounts receivable in the accompanying condensed consolidated balance sheets. In this scenario, payment is unconditional, as the Company has satisfied its performance obligations through delivery of the relevant product. As a result, the Company has concluded that its product sales do not give rise to contract assets or liabilities under the New Revenue Standard.
 
The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and NGL sales may not be received for 30 to 60 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production that was delivered to the customer and the price that will be received for the sale of the product. Additionally, to the extent actual volumes and prices of oil, natural gas and NGLs are unavailable for a given reporting period because of timing or information not received from third party purchasers, the expected sales volumes and prices for those barrels of oil, cubic feet of gas and gallons of NGLs are also estimated.

The Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls in place for its estimation process, and any identified differences between its revenue estimates and actual revenue received historically have not been significant.
 
Significant judgments
 
The Company engages in various types of transactions in which midstream entities process its gas and subsequently market resulting NGLs and residue gas to third-party customers on the Company's behalf per gas purchase contracts. These types of transactions require judgment to determine whether the Company is the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net. The Company maintains control of the natural gas and NGLs during processing and consider itself the principal in these arrangements.
 
Practical expedients
 
A significant number of the Company's product sales are short-term in nature with contract terms of one year or less. For those contracts, the Company has utilized the practical expedient in the New Revenue Standard that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.
 
For the Company's product sales that have contract terms greater than one year, the Company has utilized the practical expedient in the New Revenue Standard that states that it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
 
The following table disaggregates the Company's revenue by contract type (in thousands):
  
Three Months Ended September 30, 2018
Short-term contracts
 
Long-term contracts
 
Total
Crude Oil
$
15,976

 
$

 
$
15,976

Natural Gas
264


1,274

 
1,538

NGLs
338

 
1,630

 
1,968

Gathering, processing and transportation
(165
)
 
(798
)
 
(963
)
 
 
 
 
 
 
Nine Months Ended September 30, 2018
Short-term contracts
 
Long-term contracts
 
Total
Crude oil
$
42,819

 
$

 
$
42,819

Natural gas
817

 
2,755

 
3,572

NGLs
1,136

 
3,833

 
4,969

Gathering, processing and transportation
(525
)
 
(1,772
)
 
(2,297
)


18



Customer Credit Risk
 
Our principal exposure to credit risk is through receivables from the sale of our oil and natural gas production of approximately $11.5 million and $4.7 million at September 30, 2018 and December 31, 2017, respectively, and through actual and accrued receivables from our joint interest partners of approximately $3.0 million and $2.6 million at September 30, 2018 and December 31, 2017, respectively. We are subject to credit risk due to the concentration of our oil and natural gas receivables with our most significant customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

Major Customers

During the three and nine months ended September 30, 2018, 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,
 
 
2018
 
2017
 
2018
 
2017
 
 
 
 
 
 
 
 
 
Texican Crude & Hydrocarbon, LLC
 
80
%
 
86
%
 
84
%
 
83
%
Lucid Energy Delaware, LLC
 
17
%
 
%
 
12
%
 
%
ETC Field Services LLC
 
2
%
 
14
%
 
3
%
 
15
%
Other below 10%
 
1
%
 
%
 
1
%
 
2
%
 
 
100
%
 
100
%
 
100
%
 
100
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
    
Due to availability of other purchasers, we do not believe the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations.
  
NOTE 4 - OIL AND NATURAL GAS PROPERTIES
 
The Company uses the full cost method of accounting for oil and natural gas operations. Under this method, costs related to the exploration, non-production related development and acquisition of oil and natural gas reserves are capitalized. Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling, developing and completing productive wells, and any other costs directly related to acquisition and exploration activities. Proceeds from property sales are generally applied as a credit against capitalized exploration and development costs, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of proved reserves.

Depletion of exploration and development costs and depreciation of wells and tangible production assets is computed using the units-of-production method based upon estimated proved oil and 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, and (b) estimated future development cost to be incurred in developing proved reserves, that are not otherwise included in capitalized costs.

Under the full cost method of accounting, capitalized oil and natural gas property costs less accumulated depletion (net of deferred income taxes) may not exceed an amount equal to the sum of the present value, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves and the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are not subject to amortization. Should capitalized costs exceed this ceiling, an impairment expense is recognized.   The present value of estimated future net cash flows was computed by applying a flat oil price to forecast revenues from estimated future production of proved oil and natural gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves (assuming the continuation of existing economic conditions), less any applicable future taxes. As of September 30, 2018, the ceiling value of the Company's reserves was calculated based upon SEC pricing of $63.43 per barrel for oil, $2.92 per MMBtu for natural gas and $60.26 per barrel for NGLs.
 

19



The Company accounts for its unproven long-lived assets in accordance with ASC Topic 360-10-05, Accounting for the Impairment or Disposal of Long-Lived Assets (ASC Topic 360-10-05). ASC Topic 360-10-05 requires that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the historical carrying value of an asset may no longer be appropriate. Costs associated with undeveloped acreage are excluded from the depletion base until it is determined whether proved reserves can be assigned to the properties. When proved reserves are assigned to such properties or one or more specific properties are deemed to be impaired, the cost of such properties is added to the full cost pool, which is subject to depletion.

The following table sets forth a summary of oil and natural gas property costs (net of divestitures) not being amortized at September 30, 2018 and December 31, 2017:
 
 
September 30, 2018
 
December 31, 2017
 
(In thousands)
Unproved unevaluated acreage:
 

 
 

Beginning balance
$
101,771

 
$
24,461

Lease acquisitions
89,035

 
78,110

Transfer and other reclassification to proved properties
(23,482
)
 
(800
)
Total unproved acreage
$
167,324

 
$
101,771

Unevaluated Wells:
 
 
 
Beginning balance
$

 
$
7,453

Additions

 

Reclassification to evaluated properties

 
(7,453
)
Total unevaluated wells not subject to DD&A
$

 
$

 
During the nine months ended September 30, 2018, the Company completed an assessment of its inventory of unproved acreage for impairment which resulted in $11.1 million being transferred from unproved properties to proved properties in the full cost pool due to defective titles on certain leases. During the three and nine months ended September 30, 2017, no impairment was recorded on the Company’s unproved oil and natural gas properties. 
 
For the three months ended September 30, 2018 and 2017, depreciation, depletion, amortization and accretion expense related to proved properties was $7.2 million and $1.4 million, respectively. For the nine months ended September 30, 2018 and 2017, depreciation, depletion, amortization and accretion expense related to proved properties was $17.6 million and $3.9 million, respectively.

NOTE 5 – ACQUISITIONS AND DIVESTITURES

Ameredev Leasehold Acreage Exchange Transaction

On August 1, 2018, the Company entered into a Leasehold Exchange Agreement (the "Ameredev Exchange Agreement") with Ameredev II, LLC (“Ameredev”) to exchange certain leasehold interests located in Lea County, New Mexico owned by the Company for certain leasehold interests owned by Ameredev also located in Lea County, New Mexico. The Ameredev Exchange Agreement closed on September 14, 2018, and required the Company pay Ameredev $12,500 for each net mineral acre received in excess of the Company’s net mineral acres traded to Ameredev. The Company’s payment for excess net mineral acres was $0.7 million. In connection with the Ameredev Exchange Agreement, the Company assumed the working interests in four wells pursuant to which Ameredev advanced the Company $6.5 million for the estimated costs of the four wells. At the closing of the exchange transaction, the Company refunded the $6.5 million to Ameredev. The four wells are located in Lea County, New Mexico and operated by the Company. The total proceeds paid to Ameredev was $7.2 million and was recorded as an adjustment to the full cost pool.

Felix Holdings Leasehold Acreage Exchange Transaction

On June 4, 2018, the Company entered into a Leasehold Exchange Agreement (the "Felix Exchange Agreement") with Felix Energy Holdings II, LLC (“Felix”) to exchange certain leasehold interest located in Loving and Winkler Counties in Texas owned by the Company for certain leasehold interest located in the same counties owned by Felix. The Agreement closed on August 14, 2018, with an effective date of May 1, 2018. In addition to the Felix leasehold interests, the Company acquired certain working interests in two wells operated by the Company in Winkler County, Texas. The Company paid Felix for the well costs

20



incurred by Felix to drill and complete the two wells, less any revenues paid to Felix. The final settlement was a payment of $0.4 million which was recorded as an adjustment to the full cost pool.
 
OEP Acquisition     
 
On January 30, 2018, the Company entered into a Purchase and Sale Agreement (the “Purchase and Sale Agreement”) by and between the Company and OneEnergy Partners Operating, LLC (“OEP”), pursuant to which the Company agreed to purchase from OEP, and OEP agreed to sell to the Company, certain oil and natural gas properties and related assets for a purchase price of $70 million, subject to customary purchase price adjustments (the “OEP Acquisition”). The properties acquired by the Company pursuant to the Purchase and Sale Agreement consist of leasehold acreage in the Delaware Basin in Lea County, New Mexico. On March 15, 2018, the Company completed the OEP Acquisition whereby the Company paid $40 million in cash and issued 6,940,722 shares of the Company’s common stock valued at approximately $24.8 million for a total purchase price of approximately $64.9 million, before acquisition costs and customary purchase price adjustments. The value of the shares issued was determined using the closing price of the Company’s stock on the date of closing.
 
The OEP Acquisition was accounted for as an asset purchase of proved properties and unproved properties using relative fair value of the assets acquired. The proved producing properties were valued based on internal estimates of future production using strip pricing and the present value discounted at 10%. Unproved properties acquired were valued using a market approach.
 
The purchase price and the value of the assets acquired in the OEP Acquisition were as follows: 

(in thousands, except per share amount)
 

Cash
$
40,000

Common stock issued (6,940,722 shares at $3.57)
24,778

Transaction costs and purchase price adjustments
1,074

Total purchase price
$
65,852

 
 
Proved properties
$
4,168

Unproved properties
61,684

 
$
65,852


 
VPD Acquisition
 
On February 28, 2018, the Company completed the acquisition of certain leasehold interests and other oil and gas assets in Loving and Winkler Counties, Texas from VPD Texas, L.P. ("VPD") for cash consideration of $10.6 million including $0.5 million of related acquisition costs (the "VPD Acquisition"). The VPD Acquisition was recorded at fair value which was the total cash consideration of approximately $11.1 million. VPD is an affiliate of Värde Partners, Inc. (“Värde”). Värde participated as lead lender in the Company’s Second Lien Loan (as defined below in Note 6) transaction in 2017 and as investor of the Company’s Series C Preferred Stock transaction in January 2018. As a result, the VPD Acquisition is considered a related party transaction. See Note 11 - Related Party Transactions.

In connection with the above VPD Acquisition and pursuant to Article XVI.3(b) of the Joint Operating Agreement dated February 28, 2018 (the “JOA”) entered into between VPD and ImPetro Operating, LLC (“Operator”), a subsidiary of the Company, the Company has committed to the following drilling commitments:

drill and complete two horizontal wells (“Initial Commitment Wells”) no later than December 31, 2018; and
drill and complete at least two additional horizontal wells (“Subsequent Commitment Wells”) that target the Wolfcamp A/B Formation no later than December 31, 2019.

The Company has a one-time option to extend the deadline by an additional 75 days by providing written notice to VPD of such election on or before August 31, 2018, in the case of the Initial Commitment Wells, and August 31, 2019, in the case of the Subsequent Commitment Wells.

As of September 30, 2018, the Company has spud the first two Initial Commitment Wells and is on track to fulfill its obligations ahead of the December 31, 2018 deadline.

21




The purchase price and the value of the assets acquired in the VPD Acquisition were as follows:
 
(in thousands, except per share amount)
 

Cash purchase price
$
10,611

 
 
Proved properties
$
3,185

Unproved properties
7,426

 
$
10,611


Anadarko Acquisition

On May 3, 2018, the Company completed the acquisition of certain leasehold interests and other oil and gas assets in Loving and Winkler Counties, Texas from Anadarko for cash consideration of $7.1 million. The acquisition includes unproved leaseholds and non-consent proved producing oil and natural gas properties. As a result, the transaction is accounted for as an asset acquisition using the fair value of $7.1 million.

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

Divestitures

DJ Basin Properties Divestiture

On June 30, 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 10 - Related Party Transactions. The net proceeds of $1.08 million received on June 30, 2017 included an offset against $0.7 million of severance pay and $0.22 million of net sales adjustments due to the purchaser. 

NOTE 6 - FAIR VALUE OF FINANCIAL INSTRUMENTS
 
The Company measures the fair value of its financial assets on a three-tier value hierarchy, which prioritizes the inputs used in the valuation methodologies in measuring fair value:
 
Level 1 - Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.
 
Level 2 - Other inputs that are directly or indirectly observable in the marketplace.
 
Level 3 - Unobservable inputs which are supported by little or no market activity.
 
The fair value hierarchy also requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

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

22



 
 
Fair Value Measurement Classification
 
 
 
Quoted Prices in
Active Markets for
Identical Assets or
Liabilities
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Total
 
(in thousands)
As of September 30, 2018
 

 
 

 
 

 
 

Oil and natural gas derivative swap contracts
$

 
$
(1,244
)
 
$

 
$
(1,244
)
Oil and natural gas derivative collar contracts

 
(4,163
)
 

 
(4,163
)
Oil and natural gas derivative basis swap contracts

 
(2,697
)
 

 
(2,697
)
Second Lien Term Loan conversion features

 

 
(53,215
)
 
(53,215
)
Total
$

 
$
(8,104
)
 
$
(53,215
)
 
$
(61,319
)
As of December 31, 2017
 
 
 
 
 
 
 
Oil and natural gas derivative swap contracts
$

 
$
(706
)
 
$

 
$
(706
)
Oil and natural gas derivative collar contracts

 
(147
)
 

 
(147
)
Warrant liabilities

 

 
(223
)
 
(223
)
Second Lien Term Loan conversion features

 

 
(72,714
)
 
(72,714
)
Total
$

 
$
(853
)
 
$
(72,937
)
 
$
(73,790
)
 
The Company’s derivative liability associated with the Second Lien Loan (as defined below) 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 ., 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 “Second Lien Loan”) under the Second Lien Credit Agreement, together with accrued paid-in-kind interest and the make-whole premium on such principal amount (together the “Conversion Sum”) into shares of common stock. The make-whole premium is the cash amount representing the excess of (a) the present value at such repayment, prepayment or acceleration date or the date the obligations otherwise become due and payable in full of (1) the sum of the principal amount repaid, prepaid or accelerated plus (2) the interest accruing on such principal amount from the date of such repayment, prepayment or acceleration through the maturity date (excluding accrued but unpaid paid-in-kind interest to the date of such repayment, prepayment or acceleration), such present value to be computed using a discount rate equal to the Treasury Rate plus 50 basis points discounted to the repayment, prepayment or acceleration date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months), over (b) the principal amount of the Second Lien Loan repaid, prepaid or accelerated. The number of shares of common stock 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 Second Lien 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 in Note 9) then in effect for at least 20 of the 30 immediately preceding trading days. The features of the make-whole premium in the Second Lien Loan require the conversion features to be recorded as embedded derivatives and bifurcated from its host contracts, the Second Lien Loan, and accounted for separately from the debt. The conversion features contained in the Second Lien 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 Second Lien Loan under the Second Lien Credit Agreement. Change in fair value is accounted for in the condensed consolidated statement operations. As of September 30, 2018, the fair value of the embedded derivative liability was $53.2 million. As of December 31, 2017, the fair value of the embedded derivative under the Second Lien Credit Agreement associated with the Second Lien Loan conversion features was a liability of approximately $72.7 million. As a result, the Company recorded an unrealized gain of $10.6 million and an unrealized gain of $19.5 million on the change in fair value of derivative liabilities associated with the Second Lien Loan conversion features for the three and nine months ended September 30, 2018, respectively. During the three and nine months ended September 30, 2017, the Company recorded an unrealized loss of $6.2 million and $3.5 million, respectively, on the change in fair value of derivative liabilities associated with the Second Lien Loan conversion features.

23



 
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 Second Lien Loan.
 
SOS Warrant Liability. On June 23, 2016, in conjunction with the merger with Brushy Resources, the Company issued to SOS Investment LLC ("SOS") warrants to purchase up to 200,000 shares of the Company’s common stock at an exercise price of $25.00 (the "SOS Warrants"). The SOS Warrants contain a price protection feature that will automatically reduce the exercise price if the Company enters into another agreement pursuant to which warrants are issued with a lower exercise price. As of December 31, 2017, the fair value of the SOS Warrant liability was approximately $0.2 million. As a result of the Company’s early adoption of ASU 2017-11, “Accounting for Financial Instruments with Down Round Features” on January 1, 2018, the $0.2 million on the SOS Warrants were reclassified from current liabilities to stockholders’ equity at January 1, 2018. During the three and nine months ended September 30, 2017, the Company recorded an unrealized gain of approximately $0.3 million on the SOS Warrant liability.
 
NOTE 7 - ASSET RETIREMENT OBLIGATIONS ("ARO")
 
The Company’s ARO represent the present value of the estimated cash flows expected to be incurred to plug, abandon and remediate producing properties, excluding salvage values, at the end of their productive lives in accordance with applicable laws. Revisions in estimated liabilities during the period relate primarily to changes in estimates of asset retirement costs. Revisions in estimated liabilities can also include, but are not limited to, revisions of estimated inflation rates, changes in property lives and expected timing of settlement.
 
The following table summarizes the changes in the Company’s ARO for the nine months ended September 30, 2018 and year ended December 31, 2017: 
 
 
Nine Months Ended September 30, 2018
 
Year Ended December 31, 2017
 
(In thousands)
ARO, beginning of period
$
952

 
$
1,257

Additional liabilities incurred
295

 
20

Accretion expense
77

 
82

Liabilities settled
(87
)
 
(288
)
Revision in estimates
7

 
(119
)
ARO, end of period
1,244

 
952

Less: current portion of ARO
(16
)
 
(226
)
ARO, non-current
$
1,228

 
$
726


NOTE 8 - DERIVATIVES

The Company's derivative instruments include the following:


24



 
September 30, 2018
 
December 31, 2017
 
(in thousands)
Current assets:
 
 
 
Commodity derivatives
532

 

Total
532

 

 
 
 
 
Current liabilities:
 
 
 
Commodity derivatives
5,201

 
853

Total
5,201

 
853

 
 
 
 
Long-term liabilities:
 
 
 
Embedded derivatives
53,215

 
72,714

Warrant derivatives

 
223

Commodity derivatives
3,435

 

Total
56,650

 
72,937

 
 
 
 

 Embedded Derivatives

As discussed in Note 6, the Second Lien Loan contains conversion features that are exercisable at the option of the Lead Lender or the Company. The conversion features have been identified as embedded derivatives which (i) contain economic characteristics that are not clearly and closely related to the host contract, the Second Lien 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 Loan. The conversion features are recorded at fair value for each reporting period with changes in fair value included in the Company's condensed consolidated statement of operations for each reporting period. As of September 30, 2018 and December 31, 2017, the fair value of the derivative liability was $53.2 million and $72.7 million, respectively. As a result, the Company recognized an unrealized gain of $10.6 million and $19.5 million in its condensed consolidated statement of operations for the three and nine months ended September 30, 2018, respectively. During the three and nine months ended September 30, 2017, the Company recognized unrealized gains of approximately $6.4 million and approximately $3.5 million, respectively, in its consolidated statement of operations.

Warrant Derivatives

As of September 30, 2017, the warrant derivatives included $0.2 million fair value of 200,000 underlying warrants which were issued to SOS as of June 23, 2016 at an exercise price of $25.00. The warrants contained 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. However, as of September 30, 2018, following the adoption of ASU 2017-11 on January 1, 2018, the outstanding balance of the SOS Warrants as of the date of adoption were reclassified to equity and the Company no longer recognizes any gain or loss based on the fair value of the SOS Warrants. The SOS Warrants expired on June 23, 2018. During the three and nine months ended September 30, 2017, the Company recognized a net unrealized gain of approximately $0.01 million and $0.8 million, respectively, on the SOS Warrant and other warrants that were no longer classified as derivative instruments as of September 30, 2018.
 
Commodity Derivatives

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

25



to a fixed ceiling price for a notional quantity of production).
  
These hedging activities, which are governed by the terms of our Second Lien Credit Agreement, are intended to support oil and natural gas prices at targeted levels and manage exposure to oil and natural gas price fluctuations. It is our policy to enter into derivative contracts only with counterparties that are creditworthy and competitive market makers. All of our derivatives are with non-lender counterparties and are designated as unsecured. Certain of our derivative counterparties may require the posting of cash collateral under certain conditions. It is never the Company’s intention to enter into derivative contracts for speculative trading purposes.
 
All of our derivatives are accounted for as mark-to-market activities. Under ASC Topic 815, “Derivatives and Hedging,” these instruments are recorded on the Company's condensed consolidated balance sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. The Company nets derivative assets and liabilities by commodity for counterparties where a legal right to such offset exists. Changes in the derivatives’ fair values are recognized in current earnings since the Company has elected not to designate its current derivative contracts as cash flow hedges for accounting purposes. 

The following table presents the Company’s derivative position for the production periods indicated as of September 30, 2018:
Description
 
 
 Notional Volume (Bbls/d)
 
Production Period
 
 Weighted Average Price ($/Bbl)
Oil Swaps
 
 
900

 
 October 2018 - December 2018
 
$
57.68

 
 
 
 
 
 
 
 
Basis Swaps (1)
 
 
1,500

 
 October 2018 - December 2018
 
$
(5.62
)
Basis Swaps (1)
 
 
2,492

 
 January 2019 - December 2019
 
$
(6.85
)
Basis Swaps (1)
 
 
1,500

 
 January 2020 - December 2020
 
$
(5.62
)
 
 
 
 
 
 
 
 
3 Way Collar
Floor sold price (put)
 
1,252

 
 January 2019 - December 2019
 
$
45.00

3 Way Collar
Floor purchase price (put)
 
1,252

 
 January 2019 - December 2019
 
$
55.00

3 Way Collar
Ceiling sold price (call)
 
1,252

 
 January 2019 - December 2019
 
$
70.61

 
 
 
 
 
 
 
 
Oil Collar
Floor purchase price (put)
 
1,723

 
 October 2018 - December 2018
 
$
58.35

Oil Collar
Ceiling sold price (call)
 
1,723

 
 October 2018 - December 2018
 
$
70.02

Oil Collar
Floor purchase price (put)
 
1,000

 
 January 2019 - June 2019
 
$
52.50

Oil Collar
Ceiling sold price (call)
 
1,000

 
 January 2019 - June 2019
 
$
67.60

 
 
 
 
 
 
 
 

(1) 
The weighted average price under these basis swaps is the fixed price differential between the index prices of Midland WTI and the Cushing WTI.
 
Nine Months Ended
September 30, 2018
 
Year Ended
December 31, 2017
 
(in thousands)
Beginning fair value of commodity derivatives
$
(853
)
 
$

Change in fair value of derivative instruments
(9,383
)
 
(1,063
)
Net settlements paid on crude oil derivative contracts
1,940

 
96

Change in settlements accrued on crude oil derivative contracts
192

 
114

Ending fair value of commodity derivatives, net
$
(8,104
)
 
$
(853
)
  
  The following information summarizes the gross fair values of derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Company’s condensed consolidated balance sheets:
  

26



 
As of September 30, 2018
 
Gross Amount of Recognized Assets and Liabilities
 
Gross Amounts Offset in the Condensed Consolidated Balance Sheets
 
Net Amounts Presented in the Condensed Consolidated Balance Sheets
 
(in thousands)
Offsetting Derivative Assets:
 
 
 
 
 
Current asset
$
532

 
$

 
$
532

Long-term asset

 

 

Total asset
$
532

 
$

 
$
532

Offsetting Derivative Liabilities:
 
 
 
 
 
Current liability
$
5,201

 
$

 
$
5,201

Long-term liability
3,435

 

 
3,435

Total liability
$
8,636

 
$

 
$
8,636

 
 
 
 
 
 


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

 
$

 
$

Long-term asset

 

 

Total asset
$

 
$

 
$

Offsetting Derivative Liabilities:
 
 
 
 
 
Current liability
$
853

 
$

 
$
853

Long-term liability

 

 

Total liability
$
853

 
$

 
$
853

 
 
 
 
 
 
 

27



NOTE 9 – LONG-TERM DEBT
 
 
September 30, 2018
 
December 31, 2017
 
(In thousands)
Riverstone First Lien Loans associated with the Amended and Restated Senior Secured Term Loan Credit Agreement, due 2021, net of debt issuance costs and debt discount
$
48,018

 
$

6% Bridge Loans associated with the amended First Lien Term Loan, due 2019, net of debt issuance costs

 
30,363

8.25% Second Lien Term Loans, due 2021, net of debt issuance costs and debt discount
118,241

 
96,431

6% note payable to SOS Investment, LLC, due 2019

 
1,000

Other notes payable, due 2018

 
11

Total long-term debt
$
166,259

 
$
127,805

Less: current portion

 
(11
)
Total long-term debt, net of current portion
$
166,259

 
$
127,794

 
As of September 30, 2018 and December 31, 2017, the carrying amounts of the Company's Riverstone First Lien Loans and Second Lien Term Loans were as follows (in thousands)
 
 
Principal
Amount
 
Paid-in-
kind
Interest
 
Unamortized
Debt
Issuance
Costs & Debt
Discount
 
Carrying
Amount
September 30, 2018:
 

 
 

 
 

 
 

Riverstone First Lien Loans, due January 2021
$
50,000

 
$

 
$
(1,982
)
 
$
48,018

Second Lien Term Loans, due April 2021
150,000

 
15,561

 
(47,320
)
 
118,241

Total:
$
200,000

 
$
15,561

 
$
(49,302
)
 
$
166,259

December 31, 2017:
 
 
 
 
 
 
 
Bridge Loans associated with the amended First Lien Term Loan, due September 2019
$
30,000

 
$
807

 
$
(444
)
 
$
30,363

Second Lien Term Loans, due April 2021
150,000

 
5,752

 
(59,321
)
 
96,431

Total:
$
180,000

 
$
6,559

 
$
(59,765
)
 
$
126,794


Second Lien Credit Agreement
 
On April 26, 2017, the Company entered into the Second Lien Credit Agreement comprised of convertible loans in an aggregate initial principal amount of up to $125 million available in two separate tranches. The first tranche consists of an $80 million term loan (the “Second Lien 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 Loan 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 of 8.25% per annum, compounded quarterly in arrears and payable only in-kind by increasing the principal amount of the loan by the amount of the interest due on each interest payment date.
 
On October 3, 2017, the Company, the Guarantors, the Agent and the Lenders entered into Amendment No. 1 to the Second Lien Credit Agreement (“Amendment No. 1 to the Second Lien Credit Agreement”). The purpose of Amendment No. 1 to the Second Lien Credit Agreement is to waive certain conditions precedent to the drawing of the Delayed Draw Term Loan under the Second Lien Credit Agreement and to provide for the funding of such Delayed Draw Term Loan upon the signing of the lease acquisition agreement with KEW. The Company borrowed the full $45.0 million available under the Delayed Draw Term Loan on October 4, 2017.
 

28



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 ("Bridge Loan").
 
On November 10, 2017, the Company entered into a third amendment to the Second Lien Credit Agreement (“Amendment No. 3 to the Second Lien Credit Agreement”), by and among the Company, the Guarantors, the Agent and the Lenders, including the Lead Lender. Amendment No. 3 to the Second Lien Credit Agreement increased by $25.0 million the amount of delayed draw term loans available for borrowing under the Second Lien Credit Agreement. The additional $25.0 million of Delayed Draw Term Loan was drawn on November 10, 2017. The $25.0 million of proceeds from these loans may be used to fund oil and natural gas property acquisitions, subject to certain limitations, to fund drilling and completion costs or for other general corporate purposes.
 
On January 31, 2018, the Company entered into a fourth amendment to the Second Lien Credit Agreement with the Guarantors, the Lenders, including the Lead Lender, and the Agent (“Amendment No. 4 to the Second Lien Credit Agreement”).
 
The purpose of Amendment No. 4 to the Second Lien Credit Agreement was to, among other matters:
  
permit the Company to enter into the Riverstone First Lien Credit Agreement and incur the Riverstone First Lien Loans and related liens;
permit the Company to issue the Series C Preferred Stock; and
after the issuance of the Series C Preferred Stock, reduce from two to one the maximum number of members of the Board of Directors, the lenders under the Second Lien Credit Agreement will have the right to appoint following the conversion of the convertible loans under the Second Lien Credit Agreement.

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 Second Lien 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 Second Lien Loans prior to March 31, 2019, except (a) in connection with a Change of Control (as defined in the Second Lien Credit Agreement) or (b) if the closing price of our common stock on the principal exchange on which it is traded has been equal to or greater than 110% of the Conversion Price (as defined below) for at least 20 of the 30 trading days immediately preceding the prepayment. The Company will be required to pay a make-whole premium in connection with any mandatory or voluntary prepayment of the Second Lien 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 Company's 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 Lenders' option.

The Second Lien Loans contains certain customary representations and warranties and affirmative and negative covenants, including covenants relating to: maintenance of books and records, financial reporting and notification, compliance with laws;

29



maintenance of properties and insurance; limitations on incurrence of indebtedness, investments, dividends and other restricted payments, lease obligations, hedging and capital expenditures; and maintenance of a specified asset coverage ratio. The Second Lien Loans also provide for events of default, including failure to pay any principal or interest when due, failure to perform or observe covenants, cross-default on certain outstanding debt obligations, the failure of a Guarantor to comply with the provisions of its Guaranty, and bankruptcy or insolvency events, subject to certain specified cure periods. The amounts under the Second Lien Loans could be accelerated and be due and payable upon an event of default. As of September 30, 2018, the Company was in compliance with all restrictive covenants.
 
As discussed in Note 6, Fair Value of Financial Instruments, and Note 8, Derivatives, the Company separately accounts for the embedded conversion features of the Second Lien Loans 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 Loan. The debt discount is amortized over the term of the Second Lien Loans using effective interest rate. A portion of the Second Lien Loans were extinguished on October 10, 2018 (see Note 18, Subsequent Events).
 
Riverstone First Lien Credit Agreement
 
On January 30, 2018, the Company entered into an Amended and Restated Senior Secured Term Loan Credit Agreement (the “Riverstone First Lien Credit Agreement”), by and among the Company, the subsidiaries of the Company party thereto as guarantors, Riverstone Credit Management LLC, as administrative agent and collateral agent, and the lenders party thereto. Effective at closing under the Riverstone First Lien Credit Agreement, which occurred on January 31, 2018, the Riverstone First Lien Credit Agreement amended and restated the Company's First Lien Credit Agreement, which was entered into by the Company on September 29, 2016, and subsequently amended on April 26, 2017, July 25, 2017, and October 19, 2017 (the "First Lien Credit Agreement").
 
Pursuant to the Riverstone First Lien Credit Agreement, the lenders thereunder agreed to make term loans to the Company in the aggregate principal amount of $50 million (the “Riverstone First Lien Loans”), all of which were funded in full at closing at an original issue discount of 1.0% of the principal amount. The Riverstone First Lien Credit Agreement provides the potential for additional term loans of up to $30 million, as requested by the Company and subject to certain conditions, which additional loans were uncommitted at closing.

The Company used approximately $31.5 million of the proceeds of the Riverstone First Lien Loans to repay in full its obligations under and retire the First Lien Credit Agreement during the first quarter of 2018. The Riverstone First Lien Credit Agreement was subsequently paid and settled on October 10, 2018 (see Note 18, Subsequent Events).
 
Amendments to Riverstone First Lien Credit Agreement and Second Lien Credit Agreement
 
On February 20, 2018, the Company entered into the following amendments to its existing credit agreements (collectively, the “Amendments”): (i) Amendment No. 1 to the Riverstone First Lien Credit Agreement and (ii) Amendment No. 5 to the Second Lien Credit Agreement. Pursuant to the Amendments and a consent letter received from the Purchasers (as defined in Note 12 below), in their capacity as the holders of all of the issued and outstanding shares of Series C Preferred Stock, the Company has been granted the right to repurchase shares of its common stock for an aggregate purchase price up to $10 million (subject to certain exceptions and conditions).
 
The commencement of any repurchase of shares of common stock is subject to compliance with applicable law, Board approval, and market conditions.
 

30



Interest Expense
 
The components of interest expense are as follows (in thousands):
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
Interest on term loans
$
1,238

 
$
229

 
$
3,776

 
$
1,086

Interest on notes payable

 
17

 

 
36

Paid-in-kind interest on term loans
3,373

 
1,917

 
9,810

 
3,258

Amortization of debt financing costs
249

 
51

 
1,130

 
1,673

Amortization of discount on term loans
4,089

 
1,442

 
11,893

 
5,031

Total
$
8,949

 
$
3,656

 
$
26,609

 
$
11,084

   
NOTE 10 - LONG-TERM DEFERRED REVENUE LIABILITIES

SCM Water LLC's Option to Exercise Purchase of Salt Water Disposal Assets

In July 2018, the Company entered into a water gathering and disposal agreement with SCM Water, LLC ("SCM Water"). The water gathering project will complement the Company's existing water disposal infrastructure, and the Company has reserved the right to recycle its produced water. SCM Water will commence, upon receipt of regulatory approval, to build out new gathering and disposal infrastructure to all of the Company's current and future well locations in Lea County, New Mexico, and Winkler County, Texas. All future capital expenditures will be fully funded by SCM Water and will be designed to accommodate all water produced by the Company’s operations. The Company will act as contract operator of SCM Water’s salt water disposal wells ("SWD wells"). The Company has sold to SCM Water an option to acquire the Company’s existing water infrastructure, a system which is comprised of approximately 14 miles of pipeline and one SWD well for cash consideration upon closing, with additional payments based on reaching certain milestones. The Company is actively working on permitting additional SWD well locations and the option is expected to be exercised once permits are obtained. The Company anticipates that the majority of its water will eventually be disposed through the future SCM Water system at a competitive gathering rate under the agreement. Total cash consideration for the water gathering and disposal infrastructure is $20.0 million. On July 25, 2018, the Company received an upfront non-refundable payment of $10.0 million for the option to acquire its existing water infrastructure for the firm transportation and pricing for crude oil and $5.0 million for a prefunded drilling bonus. Additionally, the Company received $2.5 million on October 1, 2018 as a bonus for the grant of area right-of-way/easement and will receive an additional $2.5 million bonus upon hitting the target of 40,000 barrels per day of produced water. As of September 30, 2018, the Company accounted for the $17.5 million as deferred revenue liability until SCM Water exercise its option to acquire the Company's salt water disposal infrastructure.

Crude Oil Gathering Agreement and Option Agreement

On May 21, 2018, the Company entered into a crude oil gathering agreement and option agreement with Salt Creek Midstream, LLC (“SCM”). The crude oil gathering agreement (the “Gathering Agreement”) enables SCM to (i) design, engineer, and construct a gathering system which will provide gathering services for the Company’s crude oil and (ii) gather the Company’s crude oil on the gathering system in certain production areas located in Winkler and Loving Counties, Texas and Lea County, New Mexico. Construction of the gathering system has commenced and is expected to be completed in November 2018. The Gathering Agreement has a term of 12 years that automatically renews on a year to year basis until terminated by either party.
SCM and the Company also entered into an option agreement (the “Option Agreement”) whereby the Company granted an option to SCM to provide certain midstream services related to natural gas in Winkler and Loving Counties, Texas and Lea County, New Mexico, subject to the expiration and terms of the Company’s existing gas agreement. The Option Agreement has a term commencing May 21, 2018 and terminating January 1, 2027, pursuant to its one-time option. As consideration for this option, the Company received a one-time of payment $35.0 million which was recorded in long-term deferred revenue.
NOTE 11 - RELATED PARTY TRANSACTIONS
 
During the nine months ended September 30, 2018 and 2017, the Company was engaged in the following transactions with certain related parties:  

31



 
 
 
 
Nine Months Ended September 30,
Related Party
 
Transactions
 
2018
 
2017
 
 
 
 
($ in thousands)
Directors and Officers:
 
 
 
 

 
 

Ronald D. Ormand (Chief Executive Officer)
 
Receivable for tax withholding on vested restricted shares. Additional shares will be canceled to cover this tax withholding.
 
$
441

 
$

 
 
Total:
 
$
441

 
$

Brennan Short (former Chief Operating Officer)
 
Consulting fees paid to MMZ Consulting, Inc. (“MMZ”) which is owned by Mr. Short.  Mr. Short is the sole member of MMZ.
 
$

 
$
204

 
 
Total:
 
$

 
$
204

Kevin Nanke (former Chief Financial Officer)
 
Purchased the DJ Basin properties from the Company through Nanke Energy, LLC
 
$

 
$
2,000

 
 
Total:
 
$

 
$
2,000

Värde Partners, Inc. (“Värde”)(1)
 
The Company acquired oil and natural gas interests from VPD, an affiliate of Värde
 
$
10,705

 
$

 
 
Total:
 
$
10,705

 
$



(1)
Värde is the lead lender in the Company’s Second Lien Loans (see Note 9 – Long-term Debts) and also participated in the issuance of Series C 9.75% Convertible Preferred Stock in January 2018 (see Note 12 – Shareholders’ Equity and Redeemable Preferred Stock).

NOTE 12 - SHAREHOLDERS’ EQUITY AND REDEEMABLE PREFERRED STOCK
 
Preferred Stock Issuance
 
On January 30, 2018, the Company entered into a Securities Purchase Agreement (the “Securities Purchase Agreement”) by and among the Company and certain private funds affiliated with Värde (the “Purchasers”), pursuant to which the Company agreed to issue and sell to the Purchasers, and the Purchasers agreed to purchase from the Company, 100,000 shares of a newly created series of preferred stock of the Company, designated as “Series C 9.75% Convertible Participating Preferred Stock”(the Series C Preferred Stock”), for a purchase price of $1,000 per share, or an aggregate of $100.0 million. Värde is the lead lender, and certain private funds affiliated with Värde are lenders, under the Company’s Second Lien Credit Agreement (as defined above in Note 9 – Long Term Debt).
 
Closing of the issuance and sale of the shares of Series C Preferred Stock pursuant to the Securities Purchase Agreement occurred on January 31, 2018.
 
The terms of the Series C Preferred Stock are set forth in the Certificate of Designation for the Series C Preferred Stock (the “Certificate of Designation”) filed by the Company with the Secretary of State of the State of Nevada on January 31, 2018. The following is a description of the material terms of the Series C Preferred Stock and the Securities Purchase Agreement. Series C Preferred Stock were not designated as Series C-1 4.75% Convertible Participating Preferred Stock, see Note 18, Subsequent Events.
 
Ranking. The Series C Preferred Stock ranks senior to the common stock with respect to dividends and rights on the liquidation, dissolution or winding up of the Company.
 
Dividends. Holders of shares of Series C Preferred Stock are entitled to receive cumulative preferential dividends, payable and compounded quarterly in arrears on January 1, April 1, July 1 and October 1 of each year, commencing April 1, 2018, at an annual rate of 9.75% of the Stated Value (as defined below) until April 26, 2021, after which the annual dividend rate will increase to 12.00% if paid in full in cash or 15.00% if not paid in full in cash. Dividends are payable, at the Company’s option, (i) in cash, (ii) in kind by increasing the Stated Value by the amount per share of the dividend, or (iii) in a combination thereof. In addition to these preferential dividends, holders of shares of Series C Preferred Stock will be entitled to participate in any dividends paid on the common stock on an as-converted basis. As of September 30, 2018, the Company had $6.5 million of dividends in arrears on the Series C Preferred Stock. These dividends have not been declared by the Company’s Board of Directors.

32



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

Conversion. Each share of Series C Preferred Stock is convertible at any time at the option of the holder into a number of shares of common stock equal to (i) the applicable Optional Redemption Amount divided by (ii) a conversion price of $6.15, subject to adjustment (the “Series C Preferred Stock Conversion Price”). The Series C Preferred Stock Conversion Price will be subject to proportionate adjustment in connection with stock splits and combinations, dividends paid in stock and similar events affecting the outstanding common stock. Additionally, the Series C Preferred Stock Conversion Price will be adjusted, based on a broad-based weighted average formula, if the Company issues, or is deemed to issue, additional shares of common stock for consideration per share that is less than the lesser of (i) $5.25 and (ii) the Series C Preferred Stock Conversion Price then in effect, subject to certain exceptions and to the Share Cap (as defined below).
 
The Company has the right to force the conversion of any or all of the outstanding shares of Series C Preferred Stock if (i) the volume-weighted average price per share of the common stock on the principal exchange on which it is then traded has been at least 140% of the Series C Preferred Stock Conversion Price then in effect for at least 20 of the 30 consecutive trading days immediately preceding the exercise by the Company of the forced conversion right and (ii) certain trading and other conditions are satisfied.
 
Change of Control. Upon the occurrence of a Change of Control (as defined in the Certificate of Designation), each holder of shares of Series C Preferred Stock will have the option to:
 
cause the Company to redeem all of such holder’s shares of Series C Preferred Stock for cash in an amount per share equal to (i) the Optional Redemption Amount plus (ii) 2.5% of the Stated Value, in each case as in effect immediately prior to the Change of Control;
convert all of such holder’s shares of Series C Preferred Stock into the number of shares of common stock into which such shares are convertible immediately prior to the Change of Control; or
continue to hold such holder’s shares of Series C Preferred Stock, subject to any adjustments to the Series C Preferred Stock Conversion Price or the number and kind of securities or other property issuable upon conversion resulting from the Change of Control and to the Company’s or its successor’s optional redemption rights described above.

Liquidation Preference. Upon any liquidation, dissolution or winding up of the Company, holders of shares of Series C Preferred Stock will be entitled to receive, prior to any distributions on the common stock or other capital stock of the Company ranking junior to the Series C Preferred Stock, an amount per share of Series C Preferred Stock equal to the greater of (i) the Optional Redemption Amount then in effect and (ii) the amount such holder would receive in respect to the number of shares of common stock into which a share of Series C Preferred Stock is then convertible.
 
Voting Rights; Negative Covenants. In addition to the Board designation rights described in the Certificate of Designation, holders of shares of Series C Preferred Stock will be entitled to vote with the holders of shares of common stock, as a single class, on all matters submitted for a vote of holders of shares of common stock. When voting together with the common stock, each share of Series C Preferred Stock will entitle the holder to a number of votes equal to (i) the Stated Value as of the applicable record date or other determination date divided by (ii) $4.42 (the closing price of the common stock on the NYSE American on January 30, 2018).
 
Common Stock Repurchase
 
In March 2018, the Company entered into a share-repurchase agreement (the “SRA”) with an investment brokerage company (“Broker”) to repurchase $1.0 million of the Company’s common stock as part of the Share Repurchase Plan (the “Plan”). Under the terms of the SRA, the Company paid cash directly to the Broker and received delivery of shares of the Company’s common stock. All of the shares acquired by the Company under the SRA are recorded as treasury stock. For the nine months ended September 30, 2018, the Company purchased 253,598 shares of the Company’s common stock for approximately $1.0 million.




33




Warrants
 
The following table provides a summary of the Company's warrant activity for the nine months ended September 30, 2018:
 
 
Warrants
 
Weighted-
Average
Exercise Price
Outstanding at January 1, 2018
11,882,800

 
$
3.46

Exercised
(3,975,957
)
 
$
2.21

Expired or canceled
(2,769,514
)
 
$
3.38

Outstanding at September 30, 2018
5,137,329

 
$
3.80

  
NOTE 13 - SHARE BASED AND OTHER COMPENSATION
 
The Company’s share-based compensation consisted of the following (dollars in thousands):
 

 
Nine Months Ended September 30, 2018
 
Nine Months Ended September 30, 2017
 
Stock  
Options
 
Restricted  Stock
 
Total
 
Stock  
Options
 
Restricted Stock
 
Total
Share-based compensation expensed
$
1,796

 
$
5,858

 
$
7,654

 
$
6,550

 
$
7,927

 
$
14,477

Unrecognized share-based compensation costs
$
970

 
$
5,069

 
$
6,039

 
$
5,217

 
$
1,133

 
$
6,350

Weighted average amortization period remaining (in years)
0.44

 
0.50

 


 
0.75

 
0.68

 



 
Restricted Stock
 
A summary of restricted stock grant activity pursuant to the Lilis 2012 Omnibus Incentive Plan (the “2012 Plan”) and the 2016 Omnibus Incentive Plan (the “2016 Plan”) for the nine months ended September 30, 2018, is presented below:
 
 
Number of
Shares
 
Weighted
Average Grant
Date Price
Outstanding at January 1, 2018
2,475,266

 
$
4.22

Granted
1,134,944

 
$
4.60

Vested and issued
(1,095,099
)
 
$
(2.98
)
Forfeited or canceled (1)
(971,145
)
 
$
(4.26
)
Outstanding at September 30, 2018
1,543,966

 
$
4.75


(1) Forfeitures are accounted for as and when incurred.


Restricted Stock Units    
 
A summary of restricted stock unit grant activity pursuant to the 2012 Plan for the nine months ended September 30, 2018, is presented below:
 

34



 
Number of
Shares
 
Weighted
 Average Grant
Date Price
Outstanding at January 1, 2018
9,999

 
$
6.57

Vested and issued
(9,999
)
 
$
(6.57
)
Outstanding at September 30, 2018

 
$

 
Stock Options
 
A summary of stock option activity pursuant to the 2016 Plan for the nine months ended September 30, 2018, is presented below:
 
 
 
 
 
 
Stock Options Outstanding
and Exercisable
 
Number
of Options
 
Weighted
Average
Exercise
Price
 
Number
of Options
Vested/
Exercisable
 
Weighted
Average
Remaining
Contractual Life
(Years)
Outstanding at January 1, 2018
7,305,000

 
$
3.74

 
3,534,484

 
8.9

Granted
352,500

 
$
4.07

 

 

Exercised
(1,049,150
)
 
$
(2.06
)
 

 

Forfeited or canceled (1)
(1,508,900
)
 
$
(4.20
)
 

 

Outstanding at September 30, 2018
5,099,450

 
$
3.83

 
3,128,033

 
6.8

 
(1) Forfeitures are accounted for as and when incurred.

During the nine months ended September 30, 2018, options to purchase 352,500 shares of the Company’s common stock were granted under the 2016 Plan. The weighted average fair value of these options was $4.07. During the nine months ended September 30, 2018, the Company received $2.6 million from the exercise of vested stock options.
 
The fair value of stock option awards is determined using the Black-Scholes-Merton option-pricing model based on several assumptions. These assumptions are based on management’s best estimate at the time of grant. The Company used the following weighted average of each assumption based on the grants in each fiscal year:
 
 
2018
Expected Term in Years
6

Expected Volatility
58.8% - 72.6%

Expected Dividends
%
Risk-Free Interest Rate
2.59% - 2.71%



35




NOTE 14 - LOSS PER COMMON SHARE
 
The following table shows the computation of basic and diluted net loss per share for the three and nine months ended September 30, 2018 and 2017 (in thousands):

 
Three Months Ended September 30,
 
Nine Months Ended
September 30,
 
2018
 
2017
 
2018
 
2017
Net loss
(2,856
)

(6,237
)

(21,818
)

(38,139
)
Less: dividends on redeemable preferred stock






(122
)
Less: dividends and deemed dividends on Series B convertible preferred stock






(4,635
)
Less: dividends on Series C convertible preferred stock
(2,410
)



(6,527
)


Net loss attributable to common stockholders
(5,266
)

(6,237
)

(28,345
)

(42,896
)
 







Weighted average common shares outstanding - basic
64,572,104


50,785,588


60,082,902


40,596,281

 
 
 
 
 
 
 
 
Net loss per common share – basic
$
(0.08
)
 
$
(0.12
)
 
$
(0.47
)
 
$
(1.06
)
 
 
 
 
 
 
 
 
Numerator for diluted loss per share:
 
 
 
 
 
 
 
Net loss attributable to common stockholders
$
(5,266
)
 
$
(6,237
)
 
$
(28,345
)
 
$
(42,896
)
Add: interest expense on convertible Second Lien Loans
7,499

 

 

 

Less: gain on fair value change of embedded derivatives associated with Second Lien Loan
(10,612
)
 

 

 

Net loss attributable to common stockholders
$
(8,379
)
 
$
(6,237
)
 
$
(28,345
)
 
$
(42,896
)
 
 
 
 
 
 
 
 
Denominator for diluted net loss per share:
 
 
 
 
 
 
 
Weighted average number of common shares outstanding - basic
64,572,104

 
50,785,588

 
60,082,902

 
40,596,281

Dilution effect of if-converted Second Lien Loans
24,137,977

 

 

 

Weighted average number of common shares outstanding - diluted
88,710,081

 
50,785,588

 
60,082,902

 
40,596,281

 
 
 
 
 
 
 
 
Net loss per share - diluted:
 
 
 
 
 
 
 
Common shares (diluted)
$
(0.09
)
 
$
(0.12
)
 
$
(0.47
)
 
$
(1.06
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

36



The Company excluded the following shares from the diluted loss per share calculations above because they were anti-dilutive for the three and nine months ended September 30, 2018 and 2017:
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,