UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 
FORM 10-K
 
ý
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 For the fiscal year ended December 31, 2019
 
¨
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.)
 
201 Main St, Suite 700, Fort Worth, TX 76102
(Address of principal executive offices, including zip code)
 
Registrant’s telephone number including area code (817) 585-9001
Securities registered pursuant to Section 12(b) of the Act
Title of each Class
Trading Symbol(s)
Name of each exchange on which registered
Common Stock, $0.0001 par value
LLEX
NYSE American
 

Securities registered pursuant to Section 12(g) of the Exchange Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act:
Yes ¨   No ý

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15 (d) of the Act: Yes [  ] No ý

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 every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T 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
¨
Non-accelerated filer 
ý
Smaller reporting company  
ý
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 June 28, 2019, the aggregate market value of the voting and non-voting shares of common stock of the registrant issued and outstanding on such date, excluding shares held by affiliates of the registrant as a group was $35,554,508 based on the closing sales price of $0.61 per share of the registrant’s common stock on June 28, 2019 on the NYSE American.

As of April 30, 2020, 95,422,277 shares of the registrant’s common stock were issued and outstanding.
 










TABLE OF CONTENTS
 
 
 
Page
 
7
20
36
36
 
 
 
 
37
37
38
55
56
57
57
57
 
 
 
 
58
63
71
73
75
 
 
 
 
77
82



2







SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
 
This Annual Report on Form 10-K (this “Annual Report”) contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. Forward-looking statements may include the words “may,” “should,” “could,” “estimate,” “intend,” “plan,” “project,” “continue,” “believe,” “predict,” “expect,” “anticipate,” “goal,” “forecast,” “target” or other similar words.
 
All statements, other than statements of historical fact, that are included in this Annual Report, including such statements that address activities, events or developments that we expect or anticipate will or may occur in the future are forward-looking statements, including, but not limited to, the potential impact of epidemics and pandemics, including the COVID-19 coronavirus (“COVID-19”), any projections of earnings, revenue or other financial items; any statements of the plans, strategies and objectives of management for future operations; any statements concerning future production, reserves or other resource development opportunities; any projected well performance or economics, or potential joint ventures or strategic partnerships; any statements regarding future economic conditions or performance; any statements regarding future capital-raising activities; any statements of belief; commodity price risk management activities and the impact on our average realized price; and any statements of assumptions underlying any of the foregoing.
 
Although we believe that the expectations, plans, and intentions reflected in or suggested by our forward-looking statements are reasonable, we can give no assurance that these plans, intentions, or expectations will be achieved, and our actual results could differ materially from those projected or assumed in any of our forward-looking statements.
 
Our future financial condition and results of operations, as well as any forward-looking statements, are subject to inherent risks and uncertainties, many of which are beyond our control. Some of the factors, which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include but are not limited to, the impacts of COVID-19 on our business, financial condition and results of operations, the significant fall in the price of oil since the beginning of 2020, other conditions and events that raise doubts about our ability to continue as a going concern, and the other Risk Factors set forth in this Annual Report in Part I, “Item 1A. Risk Factors.” Should one or more of the risks or uncertainties described in this Annual Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those in any forward-looking statements.
 
The forward-looking statements in this Annual Report present our estimates and assumptions only as of the date of this Annual Report. Except as required by law, we specifically disclaim all responsibility to publicly update any information contained in any forward-looking statement and, therefore, disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by this cautionary statement.
 
Unless the context otherwise requires, all references in this report to “Lilis,” “we,” “us,” “our,” “ours,” or “the Company” are to Lilis Energy, Inc. and its subsidiaries.


3







GLOSSARY
 
In this Annual 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 reserves 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.

Liquids. Crude oil and natural gas liquids, or NGLs.

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
Items 1 and 2. Business and Properties

Overview

Lilis is an independent oil and natural gas company focused on the exploration, development, production, and acquisition of oil, natural gas and NGLs from properties in the Permian Basin. Our operations are focused in the Delaware Basin of the Permian in Winkler, Loving, and Reeves Counties, Texas and Lea County, New Mexico, where the production is approximately 74% Liquids, a relatively high liquid production ratio compared to many of our peers. Over 90% of our revenues are generated from the sale of Liquids.

Our History

The Company was incorporated in the State of Nevada in 2007. The name of the corporation was changed from Recovery Energy, Inc. to “Lilis Energy, Inc.” in December 2013, and at such time, the Company was primarily focused on the exploration, development and production of oil and natural gas properties in the Denver-Julesburg (DJ) Basin.

In June 2016, we completed a transformative merger transaction with Brushy Resources, Inc. (“Brushy Resources” or “Brushy”), which resulted in the acquisition of the Company’s initial assets in the Permian Basin. Given the stacked-pay opportunities and high rates of return in the Permian Basin, the Company determined that it would focus exclusively on expanding and developing its core Permian Basin assets and completed the divestiture of all of its oil and natural gas properties located in the DJ Basin in March 2017.

Our Business/Strategy

We are a pure play Permian Basin company focused on the production of Liquids. In each of the past two years, over 90% of our revenues have been generated from the sale of Liquids.

We are actively working on increasing liquidity including seeking strategic financing options. There is no assurance that our efforts will be successful and as a result there is substantial doubt about our ability to continue as a going concern. See Note 2 - Liquidity and Going Concern to our consolidated financial statements included in this Annual Report for additional information regarding our plans to improve our liquidity and our ability to continue to comply with the financial covenants under our Revolving Credit Agreement.

Oil and Natural Gas Properties

As of December 31, 2019, we owned leasehold acreage in approximately 27,920 gross (19,562 net) acres in the Delaware Basin, comprised of approximately 16,012 net acres in Winkler, Loving, and Reeves Counties, Texas and approximately 3,550 net acres in Lea County, New Mexico. Average net sales production volumes from our properties increased approximately 3% to 5,102 BOE/d in 2019 from 4,965 BOE/d in 2018.

Our undeveloped leasehold acreage at December 31, 2019 was 15,250 gross (8,050 net) acres, of which 5,670 net acres have expiration dates in 2020 and will expire if the Company does not obtain necessary funding to either extend the leases or begin drilling before their expiration dates. As a result, we have recorded an impairment of unproved leasehold of $56.2 million during the year ended December 31, 2019.

On February 28, 2020, the Company closed the sale of approximately 1,185 undeveloped net acres in Lea County, New Mexico, for net cash proceeds of approximately $24.1 million, subject to customary purchase price adjustments (the “Marlin Disposition”).

We currently estimate our properties include at least five to seven productive zones and hold more than 1,000 future drilling locations across all of the productive zones within this position.

7







Reserves Data

Proved Reserves

The following table presents our estimated net proved oil and natural gas reserves based on the reserves report prepared by LaRoche Petroleum Consultants, Ltd. (“LaRoche”) as of December 31, 2019, and the reserves reports prepared by Cawley, Gillespie & Associates, Inc. (“CG&A”) for the years 2018 and 2017. Each reserves report has been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”). All of our proved reserves included in the reserves reports are located in the Delaware Basin of the Permian Basin:
Summary of Oil and Natural Gas Reserves
 
For the Year Ended December 31,
 
2019
 
2018
 
2017
Proved Developed Reserves
 
 
 
 
 
Oil (MBbls)
5,335

 
6,278

 
2,531

NGLs (MBbls)
2,278

 
2,654

 
645

Total Liquids (MBbls)
7,613

 
8,932

 
3,176

Natural Gas (MMcf)
29,445

 
27,046

 
6,594

Total MBOE
12,521

 
13,440

 
4,275

 
 
 
 
 
 
Proved Undeveloped Reserves
 
 
 
 
 
Oil (MBbls)

 
14,927

 
4,640

NGLs (MBbls)

 
5,723

 
960

Total Liquids (MBbls)

 
20,650

 
5,600

Natural Gas (MMcf)

 
51,703

 
9,466

Total MBOE

 
29,267

 
7,178

 
 
 
 
 
 
Total Proved Reserves
 
 
 
 
 
Oil (MBbls)
5,335

 
21,205

 
7,171

NGLs (MBbls)
2,278

 
8,377

 
1,605

Total Liquids (MBbls)
7,613

 
29,582

 
8,776

Natural Gas (MMcf)
29,445

 
78,749

 
16,060

Total MBOE
12,521

 
42,707

 
11,453


Proved Undeveloped Reserves

As of December 31, 2019, we did not recognize any proved undeveloped reserves. During 2019, our proved undeveloped (“PUD”) reserves decreased 29,267 MBOE primarily due to capital constraints, as discussed below, and the conversion of one PUD to proved developed producing (“PDP”) reserves in 2019. Costs incurred to develop the PUD were approximately $7.5 million during 2019.

All of our PUD reserves were reclassified as unproved due to our inability to meet the Reasonably Certain criteria for recognizing PUD reserves because of the uncertainty regarding the availability of capital to us for the development of these reserves as of December 31, 2019, which was driven by further pricing declines during the fourth quarter of 2019. See Note 2 - Liquidity and Going Concern to our consolidated financial statements in this Annual Report. As a result, the Company recognized approximately $75.3 million of impairment relating to the value of PUD reserves which were reclassified as unproved in the fourth quarter of 2019.

For additional information regarding the changes in our proved reserves, see our “Supplementary Information on Oil and Natural Gas Exploration, Development and Production Activities” to our consolidated financial statements in Item 15 of this Annual Report.


8







Control over Reserve Estimates

The Company’s estimated proved oil and gas reserves have been prepared by the independent petroleum engineering firm LaRoche as of December 31, 2019 and CG&A as of December 31, 2018, assisted by the engineering and operations departments of the Company. For the year ended December 31, 2019, LaRoche estimated reserves for our properties comprising 100% of the PV-10 of our proved oil and gas reserves as described in more detail herein, in compliance with SEC definitions and guidance and in accordance with generally accepted petroleum engineering principles.

Internal Controls over Reserves Estimate

Our policy regarding internal controls over the recording of reserves is structured to objectively and accurately estimate our oil and natural gas reserves quantities and values in compliance with the regulations of the SEC. Responsibility for compliance in reserves bookings is delegated to our Chief Executive Officer with assistance from our Vice President of Reservoir Engineering.

Technical reviews are performed by our Vice President of Reservoir Engineering, our senior geologist and other consultants who evaluate all available geological and engineering data. This data, in conjunction with economic data and ownership information, is used in making a determination of estimated proved reserves quantities. Indranil (Neil) Barman, our Vice President of Reservoir Engineering, has more than 23 years of industry experience and has been evaluating oil and natural gas properties since 2004. He received his Ph.D. degree in Petroleum Engineering from Texas A&M University and is a registered professional engineer licensed in the State of Texas.

For the year ended December 31, 2019, our Reserves Committee, a committee of our Board of Directors, assisted management and the Board of Directors with their oversight of our reserves estimation and certification process and the work of our independent reserves engineer. Following the resignation of three directors, effective as of April 15, 2020, the Board of Directors dissolved the Reserves Committee as a result of a reduction in the size of the Board of Directors.

Our reserves estimates and the corresponding report from LaRoche, along with the process for developing such estimates, are also reviewed by our geologist and the Audit Committee of our Board of Directors to ensure compliance with SEC disclosure and internal control requirements and to verify the independence of our third-party consultants. The Audit Committee of our Board of Directors reviews the final reserves estimate in conjunction with LaRoche’s reserves report.

Third-Party Reserves Study

Our controls over reserves estimates include retaining an independent third-party consultant, LaRoche, as our independent petroleum engineering consulting firm to perform a reserves report of our proved reserves for 2019. We provided LaRoche with information about our oil and natural gas properties, including production information, prices and costs, and LaRoche performed reserves studies using its own engineering assumptions and the economic data provided by us. All of our total calculated proved reserves value was estimated by LaRoche for 2019, and all of the information regarding our 2019, 2018, and 2017 reserves in this Annual Report is derived from the third party reports of LaRoche and CG&A.

LaRoche is an independent petroleum engineering consulting firm that has been providing petroleum engineering consulting services for over 40 years. The technical personnel responsible for preparing the reserves estimates at LaRoche meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. LaRoche is an independent firm of petroleum engineers, geologists, geophysicists, and petrophysicists. They do not own an interest in any of our properties and are not employed on a contingent fee basis. All reports by LaRoche were developed utilizing their own geological and engineering data, supplemented by data provided by Lilis  

Oil and natural gas reserves and the estimates of the present value of future net cash flows therefrom were determined based on prices and costs as prescribed by the SEC and Financial Accounting Standards Board (“FASB”) guidelines. Reserves calculations involve the estimate of future net recoverable reserves of oil and natural gas and the timing and amount of future net cash flows to be received therefrom. Such estimates are not precise and are based on assumptions regarding a variety of factors, many of which are variable and uncertain. Proved reserves were estimated in accordance with guidelines established by the SEC and the FASB, which require that reserves estimates be prepared under existing economic and operating conditions with no provision for price and cost escalations except by contractual arrangements. For the years ended December 31, 2019, 2018, and 2017, we based the estimated discounted future net cash flows from proved reserves on the trailing 12-month averages of oil and natural gas index prices, calculated as the un-weighted arithmetic average for the first-day-of-the-month price for each month and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties.


9







The price of oil and natural gas has fallen significantly since the beginning of 2020, due in part to failed OPEC negotiations as well as concerns about the COVID-19 pandemic, which has significantly decreased worldwide demand for oil. If these reduced prices continue or if prices of oil, natural gas and NGLs experience additional substantial decline, our oil, natural gas and NGL reserves may be materially and adversely affected.

Oil and Natural Gas Production, Production Prices, and Production Costs

Production Volumes and Sales Prices

The following table summarizes the average volumes and realized prices of oil and natural gas produced from our properties during the periods indicated:
 
For the Years Ended December 31,
 
2019
 
2018
 
2017
Production
 
 
 
 
 
Oil (Bbls)-net production
1,131

 
1,090

 
372

Oil (per Bbl)-average realized price
$
52.19

 
$
53.26

 
$
47.92

Natural gas liquids (Bbls)-net production
221

 
246

 
74

Natural gas liquids (per Bbl)-average realized price
$
17.52

 
$
28.11

 
$
22.49

Natural Gas (Mcf)-production
3,064

 
2,856

 
776

Natural Gas (per Mcf)-average realized price
$
1.04

 
$
1.84

 
$
2.74

Barrels of oil equivalent (BOE)
1,862

 
1,812

 
575

Average daily net production (BOE)
5,102

 
4,965

 
1,576

Average Sales Price per BOE
$
35.47

 
$
38.75

 
$
37.57


The average oil and NGL sales prices above are calculated by dividing revenue from oil sales by volume of oil sold, in “Bbls.” The average natural gas sales prices above are calculated by dividing revenue from natural gas sales by the volume of natural gas sold, in “Mcf.” The total average sales price amounts are calculated by dividing total revenues by total volume sold, in BOE. The average production costs above are calculated by dividing production costs by total production in BOE.

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

The following table sets forth certain information regarding oil and natural gas production costs, production taxes, and depreciation, depletion and amortization:
 
For the Years Ended December 31,
 
2019
 
2018
 
2017
Production costs per BOE
$
10.79

 
$
9.51

 
$
12.21

Production taxes per BOE
1.77

 
2.05

 
2.06

Depreciation, depletion, and amortization per BOE
17.85

 
14.00

 
12.21

Impairment of oil and gas properties per BOE
122.60

 

 
18.26

Total operating costs per BOE
$
153.01

 
$
25.56

 
$
44.74


Acreage

The following table sets forth our approximate gross and net developed and undeveloped leasehold acreage as of December 31, 2019:
 
Undeveloped Acreage
 
Developed Acreage
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Delaware Basin
15,250

 
8,050

 
12,670

 
11,512

 
27,920

 
19,562



10







On February 28, 2020, the Company closed the sale of approximately 1,185 undeveloped net acres in Lea County, New Mexico, for net cash proceeds of approximately $24.1 million, subject to customary purchase price adjustments.

Undeveloped Acreage Expirations

Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. The following table sets forth the net undeveloped acreage, as of December 31, 2019, that will expire over the next three years unless production is established within the spacing units covering the acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates:

 
2020
 
2021
 
2022
Delaware Basin
5,670

 
1,570

 
90


As of the date of this Annual Report, leases holding 1,285 net acres in Reeves County and 593 net acres in Winkler County have expired in 2020. We have additional acreage that may expire depending on the timing and availability of capital for continued development of our leasehold acreage and lease renewals.

Our undeveloped leasehold acreage at December 31, 2019 was 15,250 gross (8,050 net) acres, of which 5,670 net acres have expiration dates in 2020 and will expire if the Company does not obtain necessary funding to either extend the leases or begin drilling before their expiration dates, less 560 net leasehold acres as part of the February 28, 2020 Lea County, New Mexico leasehold divestiture. As a result of the uncertainty regarding the availability of capital to fund drilling operations or extend leases holding undeveloped acreage, we recorded $56.2 million of impairments for undeveloped acreage for the year ended December 31, 2019.

Productive Wells

As of December 31, 2019, we had 18 gross (14.8 net) oil wells and 23 gross (19.8 net) natural gas wells. A net well is our percentage ownership interest in a gross well.

Productive wells are either wells producing in commercial quantities or wells capable of commercial production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Multiple completions in the same wellbore are counted as one well. A well is categorized under state reporting regulations as an oil well or a natural gas well based on the ratio of natural gas to oil produced when it first commenced production, and such designation may not be indicative of current production.

Drilling Activity

For the year ended December 31, 2019, we drilled 5 gross (4.4 net) horizontal wells in the Delaware Basin. We completed and placed on production 7 gross (5.4 net) horizontal wells. As of December 31, 2019, 4 gross (3.8 net) wells were drilled but not yet completed. All of these wells were successful, and none were a dry hole.


11







The following table sets forth information with respect to the number of wells drilled during the years indicated. Each of these wells was drilled in the Delaware Basin in the Permian Basin.
 
2019
 
2018
 
2017
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Exploratory:
 
 
 
 
 
 
 
 
 
 
 
Productive
5

 
4.4

 
9

 
8.7
 
5

 
4.2
Dry

 

 

 

 

 

Development:
 
 
 
 
 
 
 
 
 
 
 
Productive

 

 
6

 
5.6
 

 

Dry

 

 

 

 

 

Total:
 
 
 
 
 
 
 
 
 
 
 
Productive
5

 
4.4

 
15

 
14.3
 
5

 
4.2
Dry

 

 

 

 

 


Present Activities

As of December 31, 2019, we had no wells in the process of drilling, completing, dewatering or shut-in awaiting infrastructure.

Title to Properties

We generally conduct a preliminary title examination prior to the acquisition of properties or leasehold interests. Prior to commencement of operations on such acreage, a thorough title examination will usually be conducted, and any significant defects will be remedied before proceeding with operations. We believe the title to our leasehold properties is good, defensible and customary with practices in the oil and natural gas industry, subject to such exceptions that we believe do not materially detract from the use of such properties. We have identified title defects during 2018 and 2019 which resulted in impairment of undeveloped acreage costs and further title defects may exist which would result in impairment of undeveloped acreage costs. Our properties are potentially subject to customary royalty and other interests, liens for current taxes, and other burdens which do not materially interfere with the use of or affect our carrying value of the properties. The majority of our Delaware Basin leasehold position is also subject to mortgages securing indebtedness under our credit and guarantee agreement.

With respect to our properties of which we are not the record owner, we rely on contracts with the owner or operator of the property or assignment of leases, pursuant to which, among other things, we generally have the right to have our interest placed on record.

Competitive Business Conditions

The oil and natural gas industry is intensely competitive, particularly with respect to acquiring prospective oil and natural gas properties. We face intense competition from a substantial number of major and independent oil and natural gas companies, many of which have larger technical staffs and greater financial and operational resources. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects. We also compete with other oil and natural gas companies to secure drilling rigs and other equipment and services necessary for the drilling, completion, production, processing and maintenance of our wells, and we could face shortages or delays in securing these services from time to time if availability is limited. In addition, we compete to hire and retain professionals, including experienced geologists, geophysicists, engineers, and other professionals and consultants. We believe the location of our acreage, our technical expertise, available technologies, our financial resources, and the experience and knowledge of our management enables us to compete effectively in our core operating areas, but we recognize that many of our competitors have greater financial and operational resources.

The oil and natural gas industry also faces competition from alternative fuel sources, including other fossil fuels such as coal and imported liquefied natural gas. Competitive conditions may also be affected by future new energy, climate-related, financial, and other policies, legislation, and regulations.


12







Marketing and Pricing

We derive our revenue and cash flow principally from the sale of oil, natural gas and NGLs. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil, natural gas and NGLs. We sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts. Because some of our operations are located outside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTI or other major market pricing. The market price for oil, natural gas and NGLs is dictated by supply and demand; consequently, we cannot accurately predict or control the price we may receive for our oil, natural gas and NGLs. The price of oil and natural gas has fallen significantly since the beginning of 2020, due in part to failed Organization of Petroleum Exporting Countries (“OPEC”) negotiations as well as concerns about the COVID-19 pandemic and its impact on the worldwide economy and global demand for oil and gas. The resulting precipitous decline in oil and gas pricing experienced during March 2020, through the date of this Annual Report, if prolonged. or a further deterioration of the market price for oil and natural gas, will further negatively impact our ability to continue to operate as a going concern.

We have an active hedging program to mitigate risk regarding our cash flow and to protect returns from our development activity in the event of decreases in the prices received for our production; however, hedging arrangements may expose us to risk of significant financial loss in some circumstances and may limit the benefit we would receive from increases in the prices for oil, natural gas and NGLs.

Major Customers

We sell our production to a small number of customers which is common in the oil and natural gas industry. The following table outlines our major customers and their percentage contribution to our total revenues for the years ended December 31, 2019 and 2018:
 
Year Ended December 31,
 
2019
 
2018
Texican Crude & Hydrocarbon, LLC
 
19
%
 
87
%
ARM Energy Management, LLC
 
68
%
 
%
Lucid Energy Delaware, LLC
 
12
%
 
10
%
ETC Field Services LLC
 
1
%
 
2
%
 
 
100
%
 
100
%

Delivery Commitments

ARM Sales Agreement

On August 2, 2018, the Company executed a five-year agreement with SCM Crude, LLC, an affiliate of Salt Creek Midstream, LLC (“SCM”), to secure firm takeaway pipeline capacity and pricing on a long-haul pipeline to the Gulf Coast region commencing July 1, 2019. On March 11, 2019, the agreement was replaced with a five-year agreement between the Company and ARM Energy Management, LLC (“ARM”), a related company to SCM. The new agreement accelerated the start date to March 2019 and guarantees firm takeaway capacity on a long-haul pipeline to Corpus Christi, Texas, once completed, at a specified price. Under the terms of the new contract, the Company received pricing differentials on the crude oil sales contract subject to minimum quantities of crude oil to be delivered as follows:
Date
Quantity (Barrels per Day)
March 2019 - June 2019
5,000
July 2019 - December 2019
4,000
January 2020 - June 2020
5,000
July 2020 - June 2021
6,000
July 2021 - December 2024 (1)
7,500
(1) Extending to the later of December 2024 or 5 years from the EPIC Crude Oil pipeline in-service date (no later than June 2025).

Further, ARM has agreed to purchase crude from the Company based upon Magellan East Houston pricing with a fixed “differential basis”. As of December 31, 2019, the agreement no longer meets the criteria for the “normal purchase normal sales” exception under ASC 815, “Derivatives and Hedging”, due to the Company not meeting the minimum quantities deliverable under

13







the contract and the net settlement criteria being met. See Note 9 - Derivatives to our consolidated financial statements for information regarding the recognition of the net settlement mechanism as an embedded derivative over the remainder of the contract.

Regulation of the Oil and Natural Gas Industry

General

Our oil and natural gas exploration, production, and related operations are subject to extensive federal, state and local laws and regulations. These laws and regulations, which are under continual review for amendment, include matters relating to drilling and production practices; the disposal of water from operations and the processing, handling and disposal of hazardous materials; bonding, permitting and licensing, and reporting requirements; taxation; and marketing, transportation and pricing practices.

The failure to comply with these laws and regulations could result in substantial penalties, including administrative, civil, or criminal penalties. These laws and regulations increase our cost of doing business and can potentially affect our profitability.

Regulation of Production of Oil and Natural Gas

The production of oil and natural gas is subject to regulation under a wide range of federal, state and local laws, orders and regulations. These statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. The states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing or density, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations so as to have reductions in well spacing or density. We believe we are in substantial compliance with these laws and regulations; however, should we fail to comply with these laws and regulations, we could face substantial penalties.

Environmental, Health, and Safety Regulations

Our operations are subject to stringent federal, state, and local laws and regulations relating to the protection of the environment and human health and safety. There are various governmental agencies, including the U.S. Environmental Protection Agency (“EPA”), the U.S. Occupational Safety and Health Administration (“OSHA”) and analogous state agencies, that have the authority to enforce compliance with these laws and regulations. Environmental laws and regulations may require that permits be obtained before drilling commences or facilities are commissioned; restrict the types, quantities, and concentration of various substances that can be released into the environment in connection with drilling and production activities; govern the handling and disposal of waste material; and limit or prohibit drilling and exploitation activities on certain lands lying within wilderness, wetlands, and other protected areas, including areas containing threatened or endangered animal species.

We do not believe that our environmental risks are materially different from those of comparable companies in the oil and natural gas industry. We believe our present activities substantially comply, in all material respects, with existing environmental laws and regulations. Nevertheless, environmental laws may result in a curtailment of production or material increases in the cost of production, development or exploration, and may otherwise adversely affect our financial condition and results of operations. Although we maintain liability insurance coverage for liabilities from pollution, environmental risks are generally not fully insurable. We are committed to strict compliance with these regulations. During the years ended December 31, 2019 and 2018, we incurred approximately $220,000 and approximately $38,000, respectively, related to compliance with environmental laws for our oil and natural gas properties.

The following is a summary of the more significant existing and proposed environmental and occupational health and safety laws and regulations to which our business operations are or may be subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position:

The Resource Conservation and Recovery Act. The Resource Conservation and Recovery Act, as amended (“RCRA”), and the comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. The RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility. The RCRA includes an exemption for certain oil and natural gas exploration and production waste from regulation as hazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. As a

14







result, we are not required to comply with a substantial portion of RCRA’s hazardous waste requirements. At various times in the past, proposals have been made to amend the RCRA to rescind the exemption that excludes oil and natural gas exploration and production wastes from regulation as hazardous waste. Most recently, in April 2019, EPA concluded that rescinding the RCRA exploration and production waste exemption was not necessary “at this time”.

In the event that we fail to comply with requirements for the management of hazardous waste, administrative, civil and/or criminal penalties can be imposed. We believe that we are in substantial compliance with current applicable requirements related to hazardous waste management. Repeal or modification of the RCRA oil and natural gas exemption, or modification of similar exemptions in applicable state statutes, could increase the volume of hazardous waste we are required to manage and dispose of and could cause us to incur potentially significant increased operating expenses.

Water Discharges. The Federal Water Pollution Control Act (also known as the Clean Water Act), the Safe Drinking Water Act, the Oil Pollution Act and analogous state laws and regulations impose restrictions and controls on the discharge of produced waters and other oil and natural gas wastes into navigable waters of the United States as well as state waters. Permits must be obtained to discharge pollutants into state and federal waters and to discharge pollutants into regulated waters and wetlands. Spill Prevention, Control, and Countermeasure requirements of the Clean Water Act require appropriate secondary containment loadout controls, piping controls, berms and other measures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon spill, rupture or leak. In June 2015, the EPA and the U.S. Army Corps of Engineers jointly promulgated rules redefining the scope of waters protected under the Clean Water Act, and in October 2015, the U.S. Court of Appeals for the Sixth Circuit stayed them nationwide. The EPA and U.S. Army Corps of Engineers have resumed nationwide use of the agencies’ prior regulations defining the term “waters of the United States.” On February 28, 2017, President Trump directed the EPA to review the rules and “publish for notice and comment a proposed rule rescinding or revising the rules, as appropriate and consistent with law.” The Clean Water Act and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges of crude oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release.

The Oil Pollution Act of 1990 (“Oil Pollution Act”) and regulations thereunder are the primary federal law for oil spill liability. The Oil Pollution Act contains numerous requirements relating to the prevention of and response to petroleum releases into waters in the United States and imposes a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. The Oil Pollution Act subjects each responsible party to strict liability for oil removal costs and a variety of public and private damages, including all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters and natural resource damages.

The Safe Drinking Water Act, as amended, establishes a regulatory framework for the underground injection of a variety of wastes, including brine produced and separated from crude oil and natural gas production, with the main goal being the protection of usable aquifers. The primary objective of injection well operating permits and requirements is to ensure the mechanical integrity of the wellbore and to prevent migration of fluids from the injection zone into underground sources of drinking water.

In response to recent seismic events near underground injection wells used for the disposal of oil and natural gas-related wastewaters, federal and state agencies have been investigating whether such wells have caused increased seismic activity, and some states have shut down or imposed moratoria on the use of such injection wells. In Texas, the Texas Railroad Commission (“RRC”) regulates the disposal of produced water by injection well. The RRC requires operators to obtain a permit for the operation of saltwater disposal wells and establishes minimum standards for injection well operations. The RRC has adopted permit rules for injection wells to address these seismic activity concerns within the state. These rules could impact the availability of injection wells for disposal of wastewater from our operations. Increased costs associated with the transportation and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may reduce our profitability; however, we do not believe that the costs associated with the disposal of produced water will have a material adverse effect on our operations.

Failure to comply with these regulations may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws.

Air Pollutant Emissions. The federal Clean Air Act (the “Clean Air Act”), and comparable state and local air pollution laws, provide a framework for national, state and local efforts to protect air quality. Our operations utilize equipment that emits air pollutants which may be subject to federal and state air pollution control laws. These laws generally require utilization of air emissions control equipment to achieve prescribed emissions limitations and ambient air quality standards, as well as operating permits for existing equipment and construction permits for new and modified equipment. In May 2016, the EPA issued a final rule regarding the criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major

15







source, which would subject operators to more stringent air permitting processes and requirements. These laws and regulations may increase our costs of compliance, and we may face administrative, civil and criminal penalties if we fail to comply with the requirements of the Clean Air Act and associated state laws and regulations. We believe that we are in compliance in all material respects with the requirements of applicable federal and state air pollution control laws.

Regulation of “Greenhouse Gas” Emissions.     The EPA has adopted regulations that, among other things, establish Prevention of Significant Deterioration (“PSD”), construction, and Title V operating permit requirements for certain new and modified large stationary sources to address findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHG”) present an endangerment to public health and the environment. Facilities required to comply with PSD requirements for their GHG emissions will be required to meet “best available control technology” standards for those emissions, which will be established on a case-by-case basis. The EPA has also issued rules requiring the monitoring and reporting of GHG emissions, which include the reporting of GHG emissions from gathering and boosting systems, completions and workovers of oil wells using hydraulic fracturing, and blowdowns of natural gas transmission pipelines.

While Congress has from time to time considered legislation to reduce emissions of GHG, there has not been significant activity in the form of adopted federal legislation to reduce GHG emissions in recent years. In the absence of such federal climate legislation, a number of state and regional cap and trade programs have emerged that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting GHG. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHG from, our equipment and operations could require us to incur costs to reduce emissions of GHG associated with our operations.

Restrictions on GHG emissions that may be imposed could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources, as well as increase our costs of operations.

Hydraulic Fracturing Activities. Hydraulic fracturing is a common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight unconventional formations. Federal and state occupational safety and health laws require us to organize and maintain information about hazardous materials used, released, or produced in our operations. Some of this information must be provided to our employees, state and local governmental authorities, and local citizens. We are also subject to the requirements and reporting framework set forth in the federal workplace standards.

Several states and local jurisdictions have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, the Texas Legislature adopted legislation requiring oil and natural gas operators to publicly disclose the chemicals used in the hydraulic fracturing process. The RRC adopted rules and regulations implementing this legislation that apply to all wells for which the RRC issues an initial drilling permit. The law requires that the well operator disclose the list of chemical ingredients subject to the requirements of OSHA for disclosure on an internet website and also file the list of chemicals with the RRC with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the RRC. The RRC also adopted rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular.

We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities; however, if new or more stringent federal, state, or local restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells. For additional information about hydraulic fracturing and related regulatory matters, see “Risk Factors-Risks Relating to the Oil and natural gas Industry.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “superfund law,” imposes joint and several liabilities, regardless of fault or the legality of the original conduct, on some classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of a disposal site or sites where the release occurred and companies that transport, dispose, or arrange for disposal of the hazardous substance(s) released. Persons who are or were responsible for releases of hazardous substances under CERCLA may be jointly and severally liable for the costs of cleaning up the hazardous substances and for damages to natural resources.


16







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

Endangered Species Act and Migratory Birds. The Endangered Species Act (“ESA”) restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. We may conduct operations under oil and natural gas leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species that potentially could be listed as threatened or endangered under the ESA may exist.

The U.S. Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.

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

State Laws. There are numerous state laws and regulations in the states where we operate that relate to the environmental aspects of our business. Some of those laws and regulations are discussed above. They relate to, among other things, requirements to remediate spills of deleterious substances associated with oil and natural gas activities, the conduct of salt water disposal operations, and the methods of plugging and abandonment of oil and natural gas wells which have been unproductive. Numerous state laws and regulations also relate to air and water quality. We believe that we are in substantial compliance with all state laws governing environmental matters and all permitting requirements; however, in the event that we fail to comply with such laws, we may face substantial penalties and incur significant costs.

Natural Gas Sales and Transportation

Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. The Federal Energy Regulatory Commission (“FERC”) has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies.

Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and release of our natural gas pipeline capacity. FERC has also promulgated a series of orders, regulations and rules to foster competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company.

17








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

Additionally, we are required to comply with anti-market manipulation laws and regulations promulgated by FERC and the Commodity Future Trading Commission with regard to our physical purchases and sales of energy commodities and any related hedging activities, and, if we fail to comply, we could be subject to penalties and potential third-party damage claims.

Oil Sales and Transportation

Sales of crude oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Our crude oil sales are affected by the availability, terms and cost of transportation.

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

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

Federal Income Tax and State Severance Taxes

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

Additionally, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. Texas and New Mexico currently impose a severance tax on oil production of 4.60% and 8.39%, respectively, and a severance tax on natural gas production of 7.50% and 9.24%, respectively.

Federal Leases

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

Some of our operations are conducted on federal lands pursuant to oil and natural gas leases administered by the Bureau of Land Management (“BLM”). These leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. In addition to permits required from other regulatory agencies, lessees must obtain a permit from the BLM before drilling and comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, the valuation of production and payment of royalties, the removal of facilities, and the posting of bonds to ensure that lessee obligations are met. Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated.

18








Other Laws and Regulations

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

Seasonal Nature of Business

Generally, the demand for oil and natural gas fluctuates depending on the time of year. Generally, demand for oil increases during the summer months and decreases during the winter months while natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers may sometimes lessen this fluctuation. Further, pipelines, utilities, local distribution companies, and industrial end users utilize oil and natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can also lessen seasonal demand.

Operational Hazards and Insurance

The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, blow outs, hydrogen sulfide emissions or releases, pipe failures and, in some cases, abnormally high pressure formations which could lead to environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. If any of these should occur, we could be required to pay amounts due to injury; loss of life; damage or destruction to property, natural resources and equipment; pollution or environmental damage; regulatory investigation; and penalties and suspension of operations.

In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We evaluate the purchase of insurance, coverage limits and deductibles on an annual basis.

Current Employees

As of December 31, 2019, we had 43 employees, all of whom were full-time employees. Our employees are not represented by any labor union or covered by any collective bargaining agreements.

As a result of layoffs and furloughs in response to COVID-19 and current commodity market conditions, the Company currently has 20 active employees.

We also retain certain independent consultants and contractors to provide various professional services, including additional land, legal, engineering, geology, environmental and tax services on a contract or fee basis as necessary for our operations.

Principal Executive Office and Corporate Offices

Our principal executive offices are in leased office space located at 201 Main St, Suite 700, Fort Worth, TX 76102, and our telephone number is (817) 585-9001.

Availability of Company Reports

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act of 1934 will be available through our Internet website at https://www.lilisenergy.com as soon as reasonably practical after we electronically file such material with, or furnish it to, the SEC. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at www.sec.gov. The information on, or that can be accessed through, our website is not incorporated by reference into this Annual Report and should not be considered part of this Annual Report or incorporated into any of our other filings with the SEC.


19







Item 1A. Risk Factors

Our business involves a high degree of risk. You should carefully consider all of the risks described in this Annual Report, in addition to the other information contained in this Annual Report. If any of the following risks, or any risk described elsewhere in this Annual Report, actually occur, our business, prospects, financial condition, results of operations, or cash flows could be materially adversely affected. In any such case, the trading price of our common stock could decline. Additional risks not presently known to us or that we currently deem immaterial may also adversely affect our business.

Risks Relating to Our Business

Failure to comply with any of the financial covenants contained in our Revolving Credit Agreement could cause an event of default and have a material adverse effect on our business.

Our Revolving Credit Agreement (hereinafter defined and described in more detail) requires the Company to maintain a ratio of Total Debt to EBITDAX (each as defined in the Revolving Credit Agreement) (the “Leverage Ratio”) of not more than 4.00 to 1.00 and a ratio of Current Assets to Current Liabilities (each as defined in the Revolving Credit Agreement) (the “Current Ratio”) of not less than 1.00 to 1.00 as of the last day of each fiscal quarter. See Note 10 to our consolidated financial statements in this Annual Report for a more detailed description of these financial covenants. Failure to comply with these covenants could cause an event of default under our Revolving Credit Agreement and have a material adverse effect on our business.

As of March 31, 2020, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants. Pursuant to the Fourteenth Amendment (as defined in Note 11 - Long-Term Debt), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants as of March 31, 2020. A failure to comply with the covenants, ratios or tests in our Revolving Credit Agreement, or any future indebtedness, including borrowing base deficiency payments, could result in an event of default. If an event of default occurs and is not cured or waived, our lenders, (i) would not be required to lend any additional amounts to us, (ii) could elect to declare all outstanding borrowings, together with accrued and unpaid interest and fees to be due and payable, (iii) could require us to apply all of our available cash to repay these borrowings and (iv) could prevent us from making debt service payments under our other agreements. A potential event of default and subsequent acceleration of indebtedness would have a material adverse effect on our business, financial condition and results of operations, and raises substantial doubt about our ability to continue as a going concern.

We have identified conditions and events that raise doubt about our ability to continue as a going concern.

We have incurred losses and negative cash flows from operating activities for the years ended December 31, 2019 and 2018 and, as of December 31, 2019, and we had a stockholders’ deficit of $238.2 million. We anticipate negative operating cash flows to continue for the foreseeable future due to, among other things, significant uncertainty in the outlook for oil and gas development and external market pressures due to the effects of pandemics, epidemics and other global health concerns such as the COVID-19 pandemic and its impact on the worldwide economy and global demand for oil and gas that are not within our control. For example, the price of oil and natural gas has fallen significantly since the beginning of 2020, due in part to failed OPEC negotiations and to concerns about the COVID-19 pandemic, which has significantly decreased worldwide demand for oil. As of December 31, 2019, our cash and cash equivalents was $3.8 million and our working capital deficit was $143.5 million. As of December 31, 2019, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants. Pursuant to the Twelfth Amendment (as defined in Note 11 - Long-Term Debt), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants, among other waivers of default, as of December 31, 2019. In addition, we currently have no availability for borrowing under our Revolving Credit Agreement.

As of March 31, 2020, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants. Pursuant to the Fourteenth Amendment (as defined in Note 11 - Long-Term Debt), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants as of March 31, 2020. The Company does not expect to be in compliance with debt covenants in future periods without additional sources of liquidity or future amendments to the Revolving Credit Agreement.

We have been unable to secure further sources of liquidity, and as a result, substantial doubt exists about our ability to continue as a going concern as of the date of the filing of this Annual Report and our auditors have included a going concern paragraph in their Report of Independent Registered Public Accounting Firm. The accompanying consolidated financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of recorded assets, or the amounts and classification of liabilities that might be different should we be unable to continue as a going concern based on the outcome of these uncertainties described above. If we are unable to continue as a going concern, we may have to liquidate our assets and may receive less than the value at which those assets are carried on our audited financial statements, and it is likely

20







that investors will lose all or a part of their investment. See Note 2 - Liquidity and Going Concern to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” in this Annual Report for further detail.

Our ability to continue as a “going concern” contemplates the realization of assets and satisfaction of liabilities in the normal course of business, including the effective implementation and success of management’s plans to mitigate the conditions that raise substantial doubt about our ability to continue as a going concern.

Our consolidated financial statements included in Item 8 of this Annual Report have been presented on the basis that we would continue as a going concern, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business. Our liquidity and ability to comply with debt covenants under our Revolving Credit Agreement have been negatively impacted by the recent decrease in commodity prices, which have fallen significantly since the beginning of 2020, due in part to failed OPEC negotiations as well as concerns about the COVID-19 pandemic and its impact on the worldwide economy and global demand for oil and gas. As of March 31, 2020, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants and the Company will not be in compliance in future periods without additional sources of liquidity. Pursuant to the Fourteenth Amendment (as defined in Note 11 - Long-Term Debt Concern to our consolidated financial statements in this Annual Report), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants as of March 31, 2020. The uncertainty related to our continued operations, liquidity, and compliance with the financial covenants under our Revolving Credit Agreement raises substantial doubt regarding our ability to continue as a going concern. The consolidated financial statements do not reflect any adjustments that might result if we are unable to continue as a going concern.

In order to continue to improve our leverage position and current ratio to meet the financial covenants under the Revolving Credit Agreement and satisfy the borrowing base deficiency payment, we are currently pursuing or considering a number of actions, which in certain cases may require the consent of current lenders and stockholders. In November 2019, our board of directors formed a committee of independent directors (the “Special Committee”) tasked with reviewing and evaluating strategic alternatives that may enhance the value of the Company, including alternatives that may be available to identify and access further sources of liquidity. The Special Committee hired financial and legal advisors to advise the Special Committee on these matters.

The Special Committee continues to explore other financing alternatives and deleveraging transactions. We are also addressing operational matters such as adjusting our capital budget and improving cash flows from operations by continuing to reduce costs, and we intend to continue to pursue and consider other strategic alternatives.

There can be no assurance that we will be able to implement any of these plans successfully, or that such plans, if executed, will result in compliance with our Revolving Credit Agreement covenants or allow us to continue as a going concern.

Oil, natural gas and NGL prices are highly volatile. If commodity prices continue to experience substantial decline, our operations, financial condition, and level of expenditures for the development of our oil, natural gas and NGL reserves may continue to be materially and adversely affected.

The prices we receive for our oil, natural gas, and NGL production heavily influence our revenue, operating results, profitability, access to capital, future rate of growth and carrying value of our properties. Oil, natural gas, and NGLs are commodities, and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand.

Historically, the commodities markets have been volatile, and these markets will likely continue to be volatile in the future. The price of oil has fallen approximately $43.00 a barrel based on WTI from December 31, 2019 to the date of this Annual Report, due in part to failed OPEC negotiations as well as concerns about the COVID-19 pandemic, which has significantly decreased worldwide demand for oil. If these reduced prices continue or if prices of oil, natural gas and NGLs experience additional substantial decline, our operations, financial condition and level of expenditures for the development of our oil, natural gas and NGL reserves may continue to be materially and adversely affected. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control, including:

changes in global supply and demand for oil and natural gas;
the ability and willingness of the OPEC and non-OPEC countries, such as Russia, to set and maintain production levels and prices for oil and the other actions of OPEC;
the price and quantity of imports of foreign oil and natural gas;
political conditions, including embargoes, affecting oil-producing activity;
the level of global oil and natural gas exploration and production activity;
the level of global oil and natural gas inventories;
weather conditions;

21







technological advances affecting energy consumption
the price and availability of alternative fuels; and
epidemics, pandemics or other major public health issues, such as COVID-19.

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

We are analyzing and evaluating strategic alternatives to address our capital structure and there can be no assurance that we will be successful in identifying, undertaking or completing any strategic alternative, that any such strategic alternative will address our capital structure and not have a negative impact on our stockholders or that the process will not have an adverse impact on our business.

In November 2019, we formed the Special Committee as part of a process to analyze and evaluate various strategic alternatives to address our capital structure and to position us for future success. The Special Committee continues to explore other financing alternatives and deleveraging transactions. The process of reviewing strategic alternatives may be time consuming and disruptive to our business operations and, if we are unable to effectively manage the process, our business, financial condition and results of operations could be adversely affected. We could incur substantial expenses associated with identifying and evaluating potential strategic alternatives. No decision has been made with respect to any strategic alternative and we cannot assure you that we will be able to identify, undertake and complete any strategic alternative that will address our capital structure and not have a negative impact on our stockholders or provide any guidance on the timing of such action, if any.

Any potential strategic alternative would be dependent upon a number of factors that may be beyond our control. We do not intend to comment regarding the evaluation of strategic alternatives until such time as we have determined that further disclosure is necessary or appropriate. As a consequence, perceived uncertainties related to our future may result in the loss of potential business opportunities and may make it more difficult for us to attract and retain qualified personnel and business partners.

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

We entered into the Revolving Credit Agreement in 2018. As of December 31, 2019, $115.0 million was outstanding under our Revolving Credit Agreement. As provided for in the Seventh Amendment to the Revolving Credit Agreement, and as a result of a decrease in commodity prices, on January 17, 2020, the borrowing base was decreased to $90.0 million. The reduction in the borrowing base resulted in a borrowing base deficiency of $25.0 million. We have made scheduled repayments of $17.3 million and pursuant to the Fourteenth Amendment to the Revolving Credit Agreement, the remaining $7.8 million is due on June 5, 2020.

We may incur additional debt, including secured indebtedness, or issue preferred stock in order to maintain adequate liquidity and develop and acquire properties to the extent desired. If we are able to utilize our credit facilities in the future or if we obtain additional financing, our level of indebtedness could affect our operations, including limiting our ability to obtain additional debt or equity financing for working capital, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes. Additionally, if we increase our indebtedness, the debt service requirements of the additional indebtedness could make it more difficult for us to satisfy our financial obligations; and a substantial portion of our cash flows from operations would be dedicated to the payment of principal and interest on our indebtedness and would not be available for other purposes, including our operations, capital expenditures and future business opportunities. A higher level of indebtedness and/or preferred stock also increases the risk that we may default on our obligations.

The UK’s Financial Conduct Authority, or FCA, which regulates LIBOR, stated on July 27, 2017, that following 2021 it will no longer encourage panel banks to contribute to LIBOR, as it has done to date. Borrowings under our Revolving Credit Agreement bear interest at a floating rate of either LIBOR or a specified base rate plus a margin determined based upon the usage of the borrowing base. In the event LIBOR becomes unavailable prior to the maturity of our Revolving Credit Agreement, the rate of interest payable on our Revolving Credit Agreement may change. Uncertainty regarding the future of or changes to LIBOR or the unavailability of LIBOR could adversely affect our financial condition.


22







The Revolving Credit Agreement and Second Lien Credit Agreement, guaranteed and further secured by substantially all our assets, contain restrictive covenants that may limit our ability to respond to changes in market conditions or pursue business opportunities.

Our Revolving Credit Agreement and Second Lien Credit Agreement contain restrictive covenants that limit our ability to, among other things:

incur additional indebtedness;
create additional liens;
incur fundamental changes;
sell certain of our assets;
merge or consolidate with another entity;
pay dividends or make other distributions;
engage in transactions with affiliates; and
enter into certain swap agreements.

The requirement that we comply with these provisions may have a material adverse effect on our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.

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

In addition, our Revolving Credit Agreement requires us to maintain certain financial ratios. We may from time to time be out of compliance with covenants under our debt agreements, which will require us to seek waivers from our lenders. In connection with the preparation of this Annual Report and the associated financial statements, the Company became aware, and promptly informed its Lenders, that it did not satisfy the current ratio and leverage ratio covenants in the Revolving Credit Agreement, as of the fiscal quarter ended December 31, 2019. Accordingly, the Company requested that our lenders consent to a waiver with respect to such provision. On March 30, 2020, the Company entered into that certain Twelfth Amendment and Waiver to Second Amended and Restated Credit Agreement, whereby our lenders granted a waiver with respect to the breach of the leverage ratio and current ratio covenants, among other waivers of default. As of March 31, 2020, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants. Pursuant to the Fourteenth Amendment (as defined in Note 11 - Long-Term Debt), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants as of March 31, 2020. If we fail to comply with these provisions or other financial and operating covenants in the Revolving Credit Agreement, we could be in default under the terms of the agreement. In the event of such default, our lenders could elect to declare all the funds borrowed thereunder to be due and payable, together with the accrued and unpaid interest, and the lenders under or Revolving Credit Agreement could elect to terminate their commitments thereunder.

If we are unable to access additional capital, it could negatively impact our production, our income and ultimately our ability to retain our leases.

Our principal sources of liquidity historically have been equity contributions, borrowings under our credit facilities, net cash provided by operating activities, and net proceeds from the issuance of preferred stock. Our capital program may require additional financing above the level of cash generated by our operations to fund our growth. If our expected cash flow from operations decreases as a result of lower commodity prices or otherwise, our ability to expend the capital necessary to replace our proved reserves, maintain our leasehold acreage or maintain production may be limited, resulting in decreased production and proved reserves over time.

We plan to finance our capital expenditures with cash on hand, cash flow from operations and future issuances of debt and/or equity securities. Our cash flow from operations and access to capital is subject to a number of factors, including:

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

23







our ability to access the equity and debt capital markets.

Our operations and capital resources may not provide cash in sufficient funds to maintain planned or future levels of capital expenditures. Further, our actual capital expenditures in 2020 could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount of capital we have available, we could be required to seek additional sources of capital, which may include refinancing existing debt, joint venture partnerships, production payment financings, offerings of debt or equity securities or other means.

Our undeveloped leasehold acreage with expiration dates in 2020 at December 31, 2019 was 5,670 net acres and will expire if the Company does not obtain necessary funding to either extend the leases or begin drilling before their expiration dates. As a result, we have recorded an impairment of unproved leasehold of $56.2 million during the year ended December 31, 2019.

As of the date of this Annual Report, leases holding 1,285 net acres in Reeves County and 593 net acres in Winkler County have expired in 2020. We have additional acreage that may expire depending on the timing and availability of capital for continued development of our leasehold acreage and lease renewals.

Värde Partners, Inc., its portfolio companies, and its affiliates (collectively, “Värde”) beneficially own a significant portion of our common stock. Värde is not limited in their ability to compete with us, and the waiver of the corporate opportunity provisions in the certificates of designation relating to our Series C Preferred Stock, Series D Preferred Stock, Series E Preferred Stock, and Series F Preferred Stock, may allow Värde to benefit from corporate opportunities that might otherwise be available to us. As a result, conflicts of interest could arise in the future between us and Värde concerning conflicts over our operations or business opportunities.

Värde is a family of private investment funds that beneficially owns a significant portion of our common stock as a result of the conversion rights available to them under the Series E Preferred Stock (as hereinafter defined and described). Värde also has investments in other companies in the energy industry. The certificates of designation governing the preferences, rights and limitations of the Series E Preferred Stock provide that Värde is not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. In particular, subject to the limitations of applicable law, if Värde, or any agent, shareholder, member, partner, director, officer, employee, investment manager or investment advisor of Värde who is also one of our directors or officers, becomes aware of a potential business opportunity, transaction or other matter, they will have no duty to communicate or offer that opportunity to us.

As such, Värde may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to other businesses in which they have invested, in which case those opportunities may not be available to us or may be more expensive for us to pursue. Additionally, any actual or perceived conflicts of interest with respect to the foregoing could have an adverse impact on the trading price of our common stock. As of March 5, 2019, we converted our outstanding Second Lien Loans under our Second Lien Credit Agreement to a combination of two newly created series of preferred stock, Series E convertible preferred stock (“Series E Preferred Stock”) and Series F non-convertible preferred stock (“Series F Preferred Stock”), and common stock and eliminated the conversion features and voting rights on our existing Series C Preferred Stock and Series D Preferred Stock, reducing potential dilution of our common stockholders. Our Series E Preferred Stock is convertible and, if converted, could result in dilution to our common stockholders.

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

Our disclosure controls and procedures and internal controls may not prevent all possible errors and fraud. A control system, no matter how well conceived and operated, can provide only reasonable assurance that the objectives of the control system are being met. In addition, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls are evaluated relative to their costs. Because of the inherent limitations in all control systems, no evaluation of our controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur without detection, which could have a material adverse effect on our business.


24







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

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

Effective internal controls are necessary for us to provide reasonable assurance with respect to our financial reports and to effectively prevent fraud. If we cannot provide reasonable assurance with respect to our financial reports and effectively prevent fraud, our reputation and operating results could be harmed. Further, the complexities of our quarter-end and year-end closing processes increase the risk that a weakness in internal controls over financial reporting may go undetected. Therefore, even effective internal controls can provide only reasonable assurance with respect to the preparation and fair presentation of financial statements.

A material weakness in our internal control over financial reporting could adversely impact our ability to provide timely and accurate financial information. If we are unable to report financial information timely and accurately or to maintain effective disclosure controls and procedures, we could be subject to, among other things, regulatory or enforcement actions by the SEC and the NYSE American, including a delisting from the NYSE American, securities litigation, debt rating agency downgrades or rating withdrawals, any one of which could adversely affect the valuation of our common stock and could adversely affect our business prospects.

Decreases in oil and natural gas prices may require us to take write-downs of the carrying values of our oil and natural gas properties, potentially requiring earlier than anticipated debt repayment and negatively impacting the trading value of our securities.

Accounting rules require that we periodically review the carrying value of our oil and natural gas properties for possible impairment through the performance of a ceiling test. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties.

We perform the ceiling test at least quarterly and, in the event capitalized costs of the full cost pool exceed this ceiling, we would recognize an impairment expense. We recognized an impairment expense of approximately $228.3 million for the year ended December 31, 2019. We did not recognize an impairment expense for the year ended December 31, 2018.

Future write-downs will likely occur for reasons, including, but not limited to, continued reductions in oil and natural gas prices that lower the estimate of future net revenues from proved oil and natural gas reserves, revisions to reserves estimates, or from the addition of non-productive capitalized costs to the full cost pool that do not result in a corresponding increase in oil and natural gas reserves. Impairments of plugging and abandonment of wells in progress are other areas where costs may be capitalized into the full cost pool, without any corresponding increase in reserves values. As such, these situations could result in additional impairment expenses in the future. Impairment charges would not affect cash flow from operating activities but could have a material adverse effect on our net income and stockholders’ equity.

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

Oil and natural gas reserves engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Any material inaccuracies in these reserves estimates or underlying assumptions could materially affect the quantities and present value of our reserves which could adversely affect our business, results of operations, and financial condition.


25







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

Further, the present value of future net cash flows from proved reserves may not be the current market value of estimated oil and natural gas reserves. If our reserves estimates or the underlying assumptions prove inaccurate, it could have a negative impact on our earnings and net income, as well as the trading price of our securities.

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

In order to comply with the requirements of our Revolving Credit Agreement and to manage our exposure to price risks in the marketing of our oil and natural gas, we have entered into derivative contracts that economically hedge our oil and natural gas price on a portion of our production. These contracts may limit our potential gains if oil and natural gas prices were to rise substantially over the price established by the contract. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received; our production and/or sales of oil or natural gas are less than expected; payments owed under derivative hedging contracts come due prior to receipt of the hedged month’s production revenue; or the other party to the hedging contract defaults on its contract obligations.

Hedging transactions that we have entered into, or may enter into in the future, may not adequately protect us from declines in the prices of oil and natural gas. In addition, the counterparties under our current or future derivatives contracts may fail to fulfill their contractual obligations to us.

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

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

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

Our success will depend on the success of our drilling program. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities as such studies are merely an interpretive tool.

Drilling for oil and natural gas involves numerous risks, including the risk that no commercially productive natural gas or oil reservoirs will be discovered. The cost of drilling, completing, and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors beyond our control, including:

unexpected or adverse drilling conditions;
elevated pressure or irregularities in geologic formations;
equipment failures or accidents;
adverse weather conditions;
compliance with governmental requirements; and
shortages or delays in the availability of drilling rigs, crews, and equipment, including as the result shortages of personnel due to epidemics, pandemics or other major public health issues, such as COVID-19.

Additionally, the budgeted costs of planning, drilling, completing and operating wells are often exceeded and such costs can increase significantly due to various complications that may arise during the drilling and operating processes. If actual drilling

26







and development costs are significantly more than the current estimated costs, we may not be able to continue operations as proposed and could be forced to modify our drilling plans. A productive well may become uneconomical if water or other deleterious substances are encountered which impair or prevent the production of oil and/or natural gas from the well. Unsuccessful drilling activities could result in a significant decline in production and revenues and materially affect our operations and financial condition by reducing available cash and resources.

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

We derive essentially all of our revenues from the sale of our oil, natural gas and NGLs to unaffiliated third-party purchasers, independent marketing companies and midstream companies. Any delays in payments from such purchasers caused by their financial difficulties, including those resulting from the impacts of COVID-19 and its impact on the global economy, will have an immediate negative effect on our results of operations and cash flows.

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

Our industry is highly competitive, which may adversely affect our operations and performance.

We operate in a highly competitive environment. In addition to capital, the principle resources necessary for the exploration and production of oil and natural gas include: leasehold prospects under which oil and natural gas reserves may be discovered; drilling rigs and related equipment to explore for such reserves; and knowledgeable personnel to conduct all phases of oil and natural gas operations. We must compete for such resources with both major oil and natural gas companies and independent operators.

Many of our competitors have financial and other resources substantially greater than ours. The capital, materials and resources needed for our operations may not be available when needed. If we are unable to access capital, material and resources when needed, we may face various consequences, including the breach of our obligations under our oil and natural gas leases and the potential loss of those leasehold interests; damage to our reputation in the oil and natural gas community; inability to retain personnel or attract capital; a slowdown in our operations and decline in revenue; and a decline in the market price of our common stock.

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

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

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

Prior to the drilling of an oil and natural gas well, it is customary practice in the oil and natural gas industry for the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed oil and natural gas well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and such curative work entails expense. Failure to cure any title defects may adversely impact our ability in the future to increase production and reserves. In the future, we may suffer a monetary loss from title defects or title failure. Additionally, unproved and unevaluated acreage has greater risk of title

27







defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest or acquire, we will suffer a financial loss which could adversely affect our financial condition, results of operations and cash flows.

Our producing properties are all located in the Delaware Basin, making us vulnerable to risks associated with operating in one major geographic area.

As of December 31, 2019, all of our estimated proved reserves were located in the Delaware Basin in Winkler, Loving, and Reeves Counties, Texas and Lea County, New Mexico. As a result of this concentration, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil or natural gas produced from the wells in this area.

In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas, which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

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

Currently, we are the operator of approximately 99% of our acreage. As we carry out our exploration and development programs, we may enter into arrangements with respect to existing or future drilling locations that result in wells being operated by others. As a result, we may have limited ability to exercise influence over the operations of the drilling locations operated by our partners. Dependence on the operator could prevent us from realizing target returns for those locations. The success and timing of exploration and development activities operated by our partners will depend on a number of factors that will be largely outside of our control and may adversely affect our financial condition and results of operation.

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

The marketability of our production depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems, rail service, and processing facilities in addition to competing oil and natural gas production available to third-party purchasers. We deliver our produced crude oil and natural gas through trucking, gathering systems and pipelines. The lack of availability of capacity on third-party systems and facilities has impacted our ability to sell natural gas and could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of our development plans.

Although we have contractual control over the transportation of our production through firm transportation arrangements, third-party systems and facilities may be temporarily unavailable due to market conditions, mechanical issues, adverse weather conditions, work-loads, epidemics, pandemics or other major public health issues, such as COVID-19, or other reasons outside of our control. Additionally, if our natural gas contains levels of hydrogen sulfide that require treatment prior to transportation, it could cause delays in the transportation and marketing of our production. Any significant changes affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities, could delay our production, which could negatively impact our results of operations, cash flows, and financial condition.

The shut-in of our wells could negatively impact our production, liquidity, and, ultimately, our operations, results, and performance.

Our production depends, in part, upon our wells that are capable of commercial production not being shut-in (i.e., suspended from production). The lack of availability of capacity on third-party systems and facilities or the shut-in of an oil field’s production could result in the shut-in of our wells. As of December 31, 2019, we had two wells shut-in.

In response to recent commodity prices and our efforts to strengthen our capital through reducing operating costs, during April 2020 the Company elected to shut-in 12 wells which were identified as uneconomic as a result of the continued decline in

28







commodity prices in 2020 and 19 additional wells have been identified for short term shut-in through May and June. The 19 wells identified for short term shut-in are naturally flowing wells and could be turned back to sales quickly as market conditions dictate.

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

If we experience low oil production volumes due to the shut-in of our wells or other mechanical failures or interruptions, it would impact our ability to generate cash flows from operations and we could experience a reduction in our available liquidity. A decrease in our liquidity could adversely affect our ability to meet our anticipated working capital, debt service, and other liquidity needs.

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

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

Any future plans for exploratory and development drilling are subject to drilling and completion execution risks, and drilling results may not meet our economic expectations for reserves or production.

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

The success of our drilling and completion techniques can only be developed over time as more wells are drilled and production profiles are established. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems or otherwise, the return on our investment in these areas may not be as attractive as we anticipate and we could incur material write-downs of undeveloped properties and the value of our undeveloped acreage could decline in the future.

The unavailability or high cost of drilling rigs, equipment supplies, or personnel could adversely affect our ability to execute our exploration and development plans, if and when we are able to resume drilling and completions activity.

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


29







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

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

We are exposed to operating hazards and uninsured risks.

Our oil and natural gas exploration and production activities are subject to the operating risks and hazards associated with drilling for and producing oil and natural gas, including fires, explosions and blowouts; negligence of personnel; inclement weather; equipment or pipeline failure; abnormally pressured formations; and environmental pollution. These events may result in substantial losses or costs to us, including losses and costs resulting from injury or loss of life; severe damage to or destruction of property, natural resources or equipment; pollution or environmental damage; clean-up responsibilities; regulatory investigations; penalties and/or suspension of operations; or fees and other expenses incurred in the prosecution or defense of litigation relating to such events.

In accordance with customary industry practices, we maintain insurance against some, but not all, of these risks. Our insurance may not be adequate to cover all losses or liabilities. We do not carry business interruption insurance, and we cannot fully insure against pollution and environmental risks. We may elect not to carry certain types of insurance if our management believes that the cost of available insurance is excessive relative to the risks presented. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial condition and results of operations. The impact of natural disasters or weather events in the areas where we operate has resulted in escalating insurance costs and less favorable coverage terms. Losses and liabilities arising from uninsured or underinsured events may have a material adverse effect on our financial condition and operations, including the loss of our total investment in a particular prospect.

A failure of technology systems, data breach or cyberattack could materially affect our operations.

Our information technology systems may be vulnerable to security breaches, including those involving cyberattacks using viruses, worms or other destructive software, process breakdowns, phishing or other malicious activities, or any combination of the foregoing. Such breaches could result in unauthorized access to information, including customer, employee, or other confidential data. We do not carry insurance against these risks, although we do invest in security technology, perform penetration tests, and design our business processes to attempt to mitigate the risk of such breaches. However, there can be no assurance that security breaches will not occur. Moreover, the development and maintenance of these measures requires continuous monitoring as technologies change and security measures evolve. We have experienced, and expect to continue to experience, cyber security threats and incidents, none of which has been material to us to date. However, a successful breach or attack could have a material negative impact on our operations or business reputation and subject us to consequences such as litigation and direct costs associated with incident response.

Information technology solution failures, network disruptions, breaches of data security and cyberattacks could disrupt our operations by causing delays, impeding processing of transactions and reporting financial results, resulting in the unintentional disclosure of customer, employee or our information, or damage to our reputation. A system failure, data security breach or cyberattack could have a material adverse effect on our financial condition, results of operations or cash flows. In the past, we have experienced data security breaches resulting from unauthorized access to our e-mail systems, which to date have not had a material impact on our business; however, there is no assurance that such impacts will not be material in the future.

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

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

30








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

As of December 31, 2019, we had 43 full-time employees. As a result of layoffs and furloughs in response to COVID-19 and current commodity market conditions, the Company currently has 20 active employees. We leverage the services of independent consultants and contractors to perform various professional services, including engineering, oil and natural gas well planning and supervision, and land, legal, environmental, accounting and tax services. We also pursue alliances with partners in the areas of geological and geophysical services and prospect generation, evaluation and prospect leasing.

Our dependence on third-party consultants and service providers creates a number of risks, including but not limited to, the possibility that such third parties may not be available to us as and when needed and the possibility that we may not be able to properly control the timing and quality of work conducted with respect to our projects. If we experience significant delays in obtaining the services of such third parties or poor performance by such parties, our results of operations and stock price could be materially adversely affected.

Our business may suffer with the loss of key personnel or changes to our Board of Directors.

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

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

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

Our business strategy is based on our ability to acquire additional reserves, oil and natural gas properties, prospects and leaseholds. If and when we are able to do this, significant acquisitions and other strategic transactions may involve risks, including:

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

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

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

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


31







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

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

The EPA has determined that emissions of carbon dioxide, methane and other “greenhouse gases,” or “GHGs,” endanger public health and the environment because emissions of such gases are, according to the EPA, contributing to climatic changes. Based on these findings, the EPA, under the Clean Air Act, has adopted and implemented regulations to restrict emissions of greenhouse gases.

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

The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil, natural gas and NGLs we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business.

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

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations, and we routinely implement hydraulic fracturing techniques in many of our drilling and completion programs. The process is typically regulated by state oil and natural gas commissions, but the EPA, under the federal Safe Drinking Water Act (“SDWA”), has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel.

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. Additionally, local government may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in our exploration, development, or production activities, and perhaps even be precluded from drilling wells.

In addition, a number of federal agencies are analyzing, or have been requested to review, environmental issues associated with hydraulic fracturing. These types of studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.

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

Hydraulic fracturing can require between three to five million gallons of water per horizontal well. We may face regulatory concerns in both the sourcing and the discharge of water used in hydraulic fracturing.

In order to source water from the local water supply for hydraulic fracturing we may need to pay premium rates and be subject to a lower priority if the local area becomes subject to water restrictions. We may also seek water from alternative providers

32







supporting the hydraulic fracturing industry. If we have an insufficient water supply, we will be unable to engage in hydraulic fracturing until such supply is located.

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

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

Our operations are subject to extensive federal, state and local laws and regulations relating to the exploration, production and sale of oil and natural gas. Future laws or regulations, any adverse change in the interpretation of existing laws and regulations or our failure to comply with existing legal requirements may result in substantial penalties and harm to our business and could affect our results of operations and financial condition. We may be required to make large and unanticipated capital expenditures to comply with applicable laws and governmental regulations, including regulations governing land use restrictions; lease permit restrictions; drilling bonds and other financial responsibility in connection with operations, such as plugging and abandonment bonds; well spacing; unitization and pooling of properties; safety precautions; operational reporting; eminent domain and government takings; and taxation.

Our operations could be significantly delayed or curtailed and our cost of operations could significantly increase as a result of future changes in federal, state or local laws, regulatory requirements or restrictions.

We may incur substantial expenses, and potentially resulting liabilities, to ensure our operations are in compliance with environmental laws and regulations.

Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to environmental protection, including laws and regulations relating to the release and disposal of materials into the environment. These laws and regulations, among other things, require a permit to be obtained before drilling or facility mobilization and commissioning, or injection or disposal commences; limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and impose substantial liabilities for pollution resulting from our operations.

Changes in environmental laws and regulations occur frequently and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to reach and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination or if our operations met previous standards in the industry at the time they were performed.

The Company may be adversely affected by the recent COVID-19 outbreak.

The spread of COVID-19 has caused severe disruptions in the worldwide economy, including the global demand for oil and natural gas, which has disrupted our business and operations. Moreover, since the beginning of January 2020, the COVID-19 outbreak has caused significant disruption in the financial markets both globally and in the United States. The continued spread of COVID-19 has resulted in a significant decrease in business and/or cause our oil and natural gas purchasers to be unable to meet existing payment or other obligations to us, particularly in the event of a spread of COVID-19 in our market areas. The continued spread of COVID-19 could also negatively impact the availability of our key personnel necessary to conduct our business. Such a spread could also negatively impact the business and operations of third party service providers who perform critical services for our business. If COVID-19 continues to spread or the response to contain COVID-19 is unsuccessful, we could continue to experience a material adverse effect on our business, financial condition, and results of operations.


33







Certain of our assets, including our oil and natural gas interests, may be or become subject to mechanic’s and materialman’s liens if we are unable to pay our oilfield service providers on a timely basis.

We enter into contracts with providers of oilfield services as part of our business. Under state laws, liens to secure payment for certain contractors and subcontractors performing certain mineral activities may be attached to certain of our assets, including our oil and natural gas interests. Due to existing economic conditions, we have been unable to, and may in the future continue to be unable to, pay certain of our oilfield service providers on a timely basis. As a result of not making such payments, certain of our assets have become subject to statutory mechanic’s and materialman’s liens, and additional statutory mechanic’s and materialman’s liens may be filed. As of the most recent date available, statutory mechanic's and materialman’s liens which remain unpaid in the amount of $8.7 million have been filed against the related assets.

Risks Relating to Our Securities

The market price of our common stock may be volatile, which may depress the market price of our securities and result in substantial losses to investors if they are unable to sell their securities at or above their purchase price.

The market price of our securities may fluctuate substantially for the foreseeable future, primarily due to a number of factors, including:

our status as a company with a limited operating history and limited revenues to date, which may make risk-averse investors more inclined to sell their shares on the market more quickly and at greater discounts than would be the case with the shares of a seasoned issuer in the event of negative news or lack of progress;
announcements of technological innovations or new products by us or our existing or future competitors;
the timing and development of our products;
general and industry-specific economic conditions;
actual or anticipated fluctuations in our operating results;
liquidity and loan covenants;
actions by our stockholders;
changes in our cash flow from operations or earnings estimates;
changes in market valuations of similar companies;
our capital commitments;
the sale or attempted sale or a large amount of common stock into the market;
the loss of any of our key management personnel; and
epidemics, pandemics or other major public health issues, such as COVID-19.

Many of these factors are beyond our control and may decrease the market price of our common stock, regardless of our operating performance.

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

Our articles of incorporation authorize our board of directors to issue one or more series of preferred stock and set the terms of the preferred stock without seeking any further approval from our stockholders. Any preferred stock that is issued may rank ahead of our common stock, in terms of dividends, liquidation rights and voting rights. We currently have four series of preferred stock issued and outstanding, which ranks senior to our common stock with respect to dividends and rights on the liquidation, dissolution or winding up of the Company, amongst other preferences and rights.

There may be future dilution of our common stock.

We have a significant amount of derivative securities outstanding, which upon exercise or conversion, would result in substantial dilution of our common stock. To the extent outstanding restricted stock units, warrants or options to purchase our common stock under our 2016 Omnibus Incentive Plan or our 2012 Equity Incentive Plan are exercised, the price vesting triggers under the performance shares granted to our executive officers are satisfied, or additional shares of restricted stock are issued to our employees, holders of our common stock will experience dilution. Furthermore, the sale of additional equity or convertible debt securities could result in further dilution to our existing stockholders and cause the price of our outstanding securities to decline.


34







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

We have never paid dividends with respect to our common stock, and we do not expect to pay any dividends, in cash or otherwise, in the foreseeable future. We intend to retain any earnings for use in our business. In addition, our credit facilities and preferred stock prohibit us from paying any dividends. In the future, we may agree to further restrictions. Any return to stockholders will therefore be limited to the appreciation of their stock.

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

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

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

The existence of certain provisions under Nevada law could delay or prevent a change in control of the Company, which could adversely affect the price of our common stock. Additionally, Nevada law imposes certain restrictions on mergers and other business combinations between us and any holder of 10% or more of our outstanding common stock.

We are currently not in compliance with the NYSE American listing standards. If our common stock is delisted, the market price and liquidity of our common stock and our ability to raise additional capital would be adversely impacted.

Our common stock is currently listed on the NYSE American. Continued listing of a security on the NYSE American is conditioned upon compliance with various continued listing standards. On November 21, 2019, we received a deficiency letter (the “First Deficiency Letter”) from the NYSE American stating that we were below compliance with the continued listing standards as set forth in Section 1003(a)(i)-(iii) of the NYSE American Company Guide (the “Company Guide”) because we had reported a stockholders’ equity deficiency as of September 30, 2019 and net losses in our five most recent fiscal years ended December 31, 2018. On December 3, 2019 we received another deficiency letter (the “Second Deficiency Letter” and, together with the First Deficiency Letter, the “Deficiency Letters”) from the NYSE American stating we were below compliance with the continued listing standards as set forth in Section 1003(f)(v) of the Company Guide because our common stock had been selling for a low price per share for a substantial period of time. The Second Deficiency Letter stated that we must effect a reverse stock split of our common stock or otherwise demonstrate sustained price improvement no later than June 3, 2020.

The Deficiency Letters had no immediate effect on our listing on the NYSE American and, therefore, our common stock will continue to be listed on the NYSE American, subject to our compliance with other continued listing requirements of the NYSE American. On December 20, 2019, we submitted a plan of compliance to the NYSE American addressing how we intend to regain compliance with Sections 1003(a)(i)-(iii) of the Company Guide by May 21, 2021. On February 7, 2020, the Company received a letter from the NYSE American stating that our compliance plan has been accepted and that we have been granted a plan period through May 21, 2021.

By May 21, 2021, we must either be in compliance or must have made progress that is consistent with the plan during the plan period. In addition, during the plan period, we must provide quarterly updates to the NYSE American concurrent with our interim and annual SEC filings. Failure to meet the requirements to regain compliance could result in the initiation of delisting proceedings.

The Deficiency Letters do not affect our business operations or our reporting obligations under the rules and regulations of the SEC, nor do the Deficiency Letters conflict with or cause an event of default under any of the Company’s material agreements.

If we cannot meet the NYSE American continued listing requirements by the end of our compliance period, the NYSE American may delist our common stock resulting in our common stock trading in the less liquid over-the-counter market, which could have an adverse impact on us and the liquidity and market price of our stock. The delisting of our stock from the NYSE American could result in even further reductions in our stock price, substantially limit the liquidity of our common stock, and materially adversely affect our ability to raise capital or pursue strategic restructuring, refinancing or other transactions on acceptable

35







terms, or at all. Delisting from the NYSE American could also have other negative results, including the potential loss of confidence by vendors and employees, the loss of institutional investor interest and fewer business development opportunities. Our management is considering alternatives to ensure continued compliance with NYSE American listing standards, but there is no assurance that we will continue to maintain compliance with NYSE American continued listing standards.

Item 3. Legal Proceedings

We may from time to time be involved in various legal actions arising in the normal course of business. However, we do not believe there is any currently pending litigation that could have, individually or in the aggregate, a material adverse effect on our results of operations or financial condition.

Item 4. Mine Safety Disclosures

Not applicable.


36







PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market Information

Our common stock trades on the NYSE American under the symbol “LLEX.”

Holders

As of April 30, 2020, there were 107 holders of record of our common stock.

Dividend Policy

Holders of shares of preferred stock are entitled to receive cumulative preferential dividends, payable and compounded quarterly in arrears. Dividends on our preferred stock are payable, at the Company’s option, (i) in cash, (ii) in kind, or (iii) in a combination thereof. In 2019, we did not pay cash dividends on our outstanding preferred stock. For the year ended December 31, 2019, the paid-in-kind dividends is $25.4 million. See Note 15 - Preferred Stock to our consolidated financial statements included in this Annual Report.

We have never paid cash dividends on our common stock and do not anticipate paying dividends in the foreseeable future. Our current business plan is to retain any future earnings to finance the expansion and development of our business. Any future determination to pay cash dividends will be at the discretion of our Board of Directors, and will be dependent upon our financial condition, results of operations, capital requirements and other factors as our Board of Directors may deem relevant at that time.

Recent Sales of Unregistered Securities

None

Equity Compensation Plan Information

The following table summarizes information regarding the number of shares of our common stock that are available for issuance under all of our existing equity compensation plans as of December 31, 2019:
໿
Plan Category
 
Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights
(a)
 
Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights
(b)
 
Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (excluding securities reflected in column (a))
(c)
Equity compensation plans approved by security holders
 
3,588,350
 
4.05
 
5,372,127
Equity compensation plans not approved by security holders
 

 

 

Total
 
3,588,350
 
4.05
 
5,372,127

For additional information regarding the Company’s benefit plans and share-based compensation expense, see Note 17 - Share Based and Other Compensation to our consolidated financial statements.

Item 6.     Selected Financial Data

As a smaller reporting company, we are not required to provide the information required by this Item 6.


37







Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes included elsewhere in this Annual Report. The following discussion includes forward-looking statements, including, without limitation, statements relating to our plans, strategies, objectives, expectations, intentions and resources. Our actual results could differ materially from those discussed in these forward-looking statements as a result of many factors, including those discussed under “Risk Factors” and elsewhere in this Annual Report.
 
Overview
 
We are a Permian Basin focused company engaged in the exploration, production, development, and acquisition of oil, natural gas, and NGLs, with all of our properties and operations in the Delaware Basin. Our focus is on the production of “Liquids”. In each of the past two years, over 90% of our revenues have been generated from the sale of Liquids. We have a largely contiguous acreage position with significant stacked-pay potential, which we believe includes at least five to seven productive zones and more than 1,000 future drilling locations.

As of December 31, 2019, we were fully drawn against the borrowing base under our Revolving Credit Agreement (as defined in Note 11 - Long-Term Debt to our consolidated financial statements), with $115 million of indebtedness outstanding under our Revolving Credit Agreement. As provided for in the Seventh Amendment to our Revolving Credit Agreement and as a result of a decrease in commodity prices, on January 17, 2020, the borrowing base was decreased to $90.0 million. The reduction in the borrowing base resulted in a borrowing base deficiency of $25.0 million. We have made scheduled repayments of $17.3 million and pursuant to the Fourteenth Amendment to our Revolving Credit Agreement, the remaining $7.8 million is due on June 5, 2020. Refer to Note 11 - Long-Term Debt to our consolidated financial statements for additional information. Our next borrowing base redetermination is scheduled to occur on or around June 5, 2020. If the borrowing base is further reduced by the lenders in connection with this redetermination, we will be required to repay borrowings in excess of the borrowing base as we do not have sufficient additional oil and natural gas properties to eliminate the borrowing base deficiency by pledging additional oil and natural gas properties to secure our obligations under the Revolving Credit Agreement. Under the Revolving Credit Agreement, we have the option to affect such repayment either in full within 30 days after the redetermination or in monthly installments over a six-month period after the redetermination.

Our liquidity and ability to comply with debt covenants under our Revolving Credit Agreement have been negatively impacted by the recent decrease in commodity prices, which have fallen approximately $43.00 a barrel based on WTI from December 31, 2019 to the date of this Annual Report, due in part to failed OPEC negotiations as well as concerns about the COVID-19 pandemic, which has significantly decreased worldwide demand for oil and natural gas. Our Revolving Credit Agreement contains financial covenants requires the Company to maintain a ratio of Total Debt to EBITDAX (each as defined in the Revolving Credit Agreement) (the “Leverage Ratio”) of not more than 4.00 to 1.00 and a ratio of Current Assets to Current Liabilities (each as defined in the Revolving Credit Agreement) (the “Current Ratio”) of not less than 1.00 to 1.00 as of the last day of each fiscal quarter thereafter. See Note 11 - Long-term Debt to our consolidated financial statements for additional information regarding the financial covenants under our Revolving Credit Agreement. As of December 31, 2019, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants. Pursuant to the Twelfth Amendment (as defined in Note 11 - Long-Term Debt to our consolidated financial statements), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants as of December 31, 2019.

As of March 31, 2020, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants. Pursuant to the Fourteenth Amendment (as defined in Note 11 - Long-Term Debt), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants as of March 31, 2020. If we are not able to pay or defer the $7.8 million Borrowing Base Deficiency due on June 5, 2020 or do not maintain compliance with our debt covenants, the obligations of the Company under the Revolving Credit Agreement may be accelerated, which would have a material adverse effect on our business.

In order to improve our liquidity, leverage position and current ratio to meet the financial covenants under the Revolving Credit Agreement, we are currently pursuing or considering a number of actions, which in certain cases may require the consent of current lenders and stockholders. In November 2019, our board of directors formed a Special Committee tasked with reviewing and evaluating strategic alternatives that may enhance the value of the Company, including alternatives that may be available to identify and access further sources of liquidity through financing alternatives or deleveraging transactions. The Special Committee hired financial and legal advisors to advise the Special Committee on these matters.   

38







The Special Committee continues to explore financing alternatives and deleveraging transactions. We are also addressing operational matters such as adjusting our capital budget and improving cash flows from operations by continuing to reduce costs, and intend to continue to pursue and consider other strategic alternatives.
There can be no assurance that we will be able to implement any of these plans successfully, or that such plans, if executed, will result in the ability to pay borrowing base deficiencies, generate sufficient liquidity or comply with our Revolving Credit Agreement covenants. These factors raise substantial doubt about our ability to continue as a going concern within twelve-month period following the date of issuance of these consolidated financial statements.

2019 Operational and Financial Highlights

Increased our net sales production by 3% to 5,102 BOE/d, for 2019 as compared to 2018, despite planned well shut-ins and temporary suspensions of our drilling and completions program throughout 2019. Net sales production for 2019 of 5,102 BOE/d was consistent with guidance for the year.

Significantly reduced general and administrative expenses by completing the closing of the Houston and San Antonio offices, consolidating all operations to a single location in Fort Worth, and reducing full-time equivalent employees (corporate, operations and field personnel) by approximately 23%. These efforts contributed to reductions of general and administrative expenses by 15% for the year ended December 31, 2019 when compared to the year ended December 31, 2018.

Reduced general and administrative expenses per BOE by 17% for 2019 as compared to 2018

Reduced our crude transportation costs per Bbl by 85% from $5.15 per Bbl in January and February 2019, to $0.75 per Bbl beginning in March 2019 through year-end, resulting in a 2019 weighted average crude transportation cost of $1.49 per Bbl. This resulted in a total annual crude transportation cost savings of $3.0 million in 2019 versus 2018.

Reduced our saltwater disposal costs by 25% to approximately $1.93 per Bbl as of December 2019 through our sales agreements and access to infrastructure.

Increased saltwater disposal capacity through third party access by 380% to 46,600 bbl/d, compared to 2018.

Added seasoned oil and gas professionals to our operations and land departments.

Significantly reduced our cycle times by reducing average drilling days for longer lateral wells (> 1.5 miles) from approximately 45 days (spud to total depth) to approximately 17 days.

Successfully completed 7 gross wells (5.4 net) during 2019, despite temporary suspensions in the Company’s drilling and completions program.

Reduced average drilling costs per well by 26% compared to wells drilled by previous operations management in 2018.

Secured necessary power commitments to begin full electrification of our Texas field and currently in the process of securing the necessary power commitments for our New Mexico field.

Received 2-year extended flaring permits to mitigate the need for future shut-ins associated with regulatory flaring compliance and have implemented solutions for delivering all produced natural gas to sales by the end of the second quarter of 2020.

Received three drilling permits from the Bureau of Land Management in New Mexico. In addition, the Company has 13 submitted permits in various stages of review.

Completed two significant transactions that brought approximately $56 million of capital into the Company
Sold 513 net undeveloped acres in New Mexico, noncontiguous to the Company’s core operational area, for approximately $33,000 per net acre
Completed an overriding royalty interest and working interest transaction
 
Realized oil pricing of 91% of WTI for 2019 versus 82% of WTI as compared to 2018.

Achieved commodity volume mix of 73% Liquids, including 61% crude oil, resulting in 95% of revenue attributable to Liquids sales during 2019

39








2020 Updates

Brought additional capital of $24.1 million into the Company through the sale of certain undeveloped leasehold assets in New Mexico.

Successfully installed gas treating system on certain well locations and are now in the final stages of testing the treated gas that will flow to sales.  We anticipate all treated natural gas production to be flowing to sales during the second quarter of 2020.

In 2020, the Company has entered into the Seventh Amendment through the Fourteenth Amendment to the Revolving Credit Agreement which, among other things, amended the following (Refer to Note 11 - Long-Term Debt for additional information):
Reduced our borrowing base to $90.0 million, resulting in a borrowing base deficiency of $25.0 million,
Extended the due date for the final borrowing base deficiency payment to June 5, 2020, and
Waived compliance with the Leverage Ratio and Current Ratio covenants as of December 31, 2019 and March 31, 2020.

In response to recent commodity prices and our efforts to strengthen our capital through reducing operating costs, during April 2020 the Company elected to shut-in 12 wells which were identified as uneconomic as a result of the continued decline in commodity prices in 2020 and 19 additional wells have been identified for short term shut-in through May and June. The 19 wells identified for short term shut-in are naturally flowing wells and could be turned back to sales quickly as market conditions dictate.
The Company has also implemented an employee furlough program to further reduce general and administrative costs.  The furloughed employees will not receive compensation from the Company during the furlough period; however, subject to local regulations, these employees will be eligible for unemployment benefits.  The furlough period is uncertain at this time and will be reassessed as business conditions dictate.

Access to Infrastructure

We entered into an amendment to our previously negotiated water gathering and disposal agreement and entered into a new crude oil sales contract to support the sales of our production of Liquids and natural gas, including transportation and sales agreements and salt water gathering and disposal agreements. We believe these agreements secure us cost effective movement of our Liquids and natural gas production in Texas and Mexico. Our agreements and relationships with SCM and ARM also provide the company with optionality in production storage capacity and down-stream transportation capacity.

On March 11, 2019, the Company, SCM Water, and ARM Energy Management, LLC (“ARM”), a related company to SCM Water, agreed to amend the terms of the previously negotiated water gathering and disposal agreement and entered into a new crude oil sales contract. Under the terms of such agreements, the Company agreed to an increase in salt water disposal rates in exchange for more favorable pricing differentials on the crude oil sales contract, modification on the minimum quantities of crude oil required under the crude oil sales contract, an upfront payment of $2.5 million and the elimination of the potential bonus for hitting a target of 40,000 barrels of produced water per day.

Market Conditions and Commodity Pricing

Our financial results depend on many factors, including the price of oil, natural gas and NGLs and our ability to market our production on economically attractive terms. We generate the majority of our revenues from sales of Liquids and, to a lesser extent, sales of natural gas. The price of these products are critical factors to our success and volatility in these prices could impact our results of operations. In addition, our business requires substantial capital to acquire properties and develop our non-producing properties. The price of oil, natural gas and NGLs have fallen significantly since the beginning of 2020, due in part to failed OPEC negotiations and to concerns about the COVID-19 pandemic, which has significantly decreased worldwide demand for oil and natural gas. This significant decline and any further declines in the price of oil, natural gas and NGLs have reduced our revenues and result in lower cash inflow which have made it more difficult for us to pursue our plans to acquire new properties and develop our existing properties. Such declines in oil, natural gas, and NGL prices also adversely affect our ability to obtain additional funding on favorable terms.

Commodity prices continued to significantly decrease during first quarter 2020, through the date of filing. As of March 31, 2020, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants and received a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants as of March 31, 2020. 


40







Results of Operations – For the Years Ended December 31, 2019 and 2018
 
Current Operations Update

During the year ended December 31, 2019, seven horizontal wells were placed on production. As of December 31, 2019, we have 41 gross operated wells, of which 30 horizontal wells and 9 legacy vertical wells were producing and flowing to sales. We received three drilling permits from the Bureau of Land Management in New Mexico and are nearing completion on several additional New Mexico permits.

To enhance performance, the Company has installed artificial lift on select wells.  Currently, eleven wells have been placed on artificial lift.

In July 2019, we self-elected to temporarily shut-in four of our wells to remain within Texas flaring regulations. By the end of the third quarter, we brought all four of those previously shut-in wells back online and flowing to sales, received extended flaring permits in Texas to mitigate the need for future shut-ins due to regulatory compliance, and continue to advance efforts with the implementation of field treating solutions.  The treating systems involve chemical intervention, upgrades to the surface facilities at each tank battery and upgrades to natural gas handling facilities for specific wells that do not meet quality specifications. The facility upgrades necessary for the crude oil treating implementation has been completed and our third-party crude gathering system is currently capable of flowing treated crude to all receipt points. The natural gas treating solution continues to be advanced and began delivering treated natural gas, that was previously being flared, to sales in the first quarter of 2020.

Effective March 1, 2019, the Company began selling its crude oil under a single long-term contract with a term that extends to at least December 31, 2024. The purchaser’s commitment has a quantity-based limit set forth in the contract, measured in barrels per day, with the maximum quantity commitment increasing at periodic intervals over the life of the contract to coincide with the Company’s expected growth in production. Pursuant to the long-term contract, pricing is based on posted indexes for crude oil of similar quality, with a differential based on pipeline delivery to Houston.

In May 2018, we engaged SCM to implement a gathering system to transport our crude oil production.  Due to ongoing matters involving construction and use of the gathering system, we have not been able to use the system as expected, which has delayed our realization of efficiencies in getting our production to sales and has increased our transportation costs on sales.

Sales Volumes and Revenues

The following table sets forth selected revenue and sales volume data for the years ended December 31, 2019 and 2018
 
Years Ended December 31,
 
 
 
 
 
2019
 
2018
 
Variance
 
%
Net sales volume:
 
 
 
 
 
 
 
Oil (Bbl)
1,130,855

 
1,089,724

 
41,131

 
4
 %
Natural gas (Mcf)
3,063,927

 
2,855,739

 
208,188

 
7
 %
NGL (Bbl)
220,832

 
246,425

 
(25,593
)
 
(10
)%
Total (BOE)
1,862,342

 
1,812,106

 
50,236

 
3
 %
Average daily sales volume (BOE/d)
5,102

 
4,965

 
137

 
3
 %
Average realized sales price:
 
 
 
 
 
 
 
Oil ($/Bbl)
$
52.19

 
$
53.26

 
$
(1.08
)
 
(2
)%
Natural gas ($/Mcf)
1.04

 
1.84

 
(0.80
)
 
(44
)%
NGL ($/Bbl)
17.52

 
28.11

 
(10.59
)
 
(38
)%
Total ($/BOE)
$
35.47

 
$
38.75

 
$
(3.28
)
 
(8
)%
Oil, natural gas and NGL revenues (in thousands):
 
 
 
 
 
 
 
Oil revenue
$
59,015

 
$
58,042

 
$
973

 
2
 %
Natural gas revenue
3,180

 
5,246

 
(2,066
)
 
(39
)%
NGL revenue
3,868

 
6,928

 
(3,060
)
 
(44
)%
Total revenue
$
66,063

 
$
70,216

 
$
(4,153
)
 
(6
)%

41







Total sales volume increased 3% to 1,862,342 BOE during the year ended December 31, 2019, compared to 1,812,106 BOE during 2018, an increase of 50,236 BOE. The increase in total sales volume was primarily due to 7 gross (5.4 net) additional wells placed on production since the third quarter of 2018. Total revenue decreased $4.2 million to $66.1 million for the year ended December 31, 2019, as compared to $70.2 million for the year ended December 31, 2018, representing a 6% decrease. The decrease was primarily attributable to lower realized prices partially offset by increased volumes.

Operating Expenses

The following table shows a comparison of operating expenses for the years ended December 31, 2019 and 2018
 
Years Ended December 31,
 
 
 
2019
 
2018
 
Variance
 
%
Operating Expenses per BOE:
 

 
 

 
 

 
 

Production costs
$
8.66

 
$
7.64

 
$
1.02

 
13
 %
Gathering, processing and transportation 
2.13

 
1.87

 
0.26

 
14
 %
Production taxes
1.77

 
2.05

 
(0.28
)
 
(14
)%
General and administrative
15.23

 
18.35

 
(3.12
)
 
(17
)%
Depreciation, depletion, amortization and accretion
17.85

 
14.00

 
3.85

 
28
 %
Impairment of oil and natural gas properties
122.60

 

 
122.60

 
100
 %
Total operating expenses per BOE
$
168.24

 
$
43.91

 
$
124.33

 
283
 %
 
 
 
 
 
 
 
 
Operating Expenses (in thousands):
 

 
 
 
 
 
 
Production costs
$
16,127

 
$
13,843

 
$
2,284

 
16
 %
Gathering, processing and transportation 
3,960

 
3,392

 
568

 
17
 %
Production taxes
3,302

 
3,709

 
(407
)
 
(11
)%
General and administrative
28,371

 
33,251

 
(4,880
)
 
(15
)%
Depreciation, depletion, amortization and accretion
33,252

 
25,367

 
7,885

 
31
 %
Impairment of oil and natural gas properties
228,324

 

 
228,324

 
100
 %
Total operating expenses
$
313,336

 
$
79,562

 
$
233,774

 
294
 %

Production Costs

Production costs increased by $2.3 million, or 16%, to $16.1 million for the year ended December 31, 2019, compared to $13.8 million for the year ended December 31, 2018, due, in part, to the 7 gross (5.4 net) increase in producing wells during 2019. Our production costs on a per BOE basis increased by $1.02, or 13%, to $8.66 for the year ended December 31, 2019, as compared to $7.64 per BOE for the year ended December 31, 2018. The increase in production costs per BOE was primarily the result of increased equipment rentals related to artificial lift and workover charges.

Gathering, Processing and Transportation
    
Gathering, processing and transportation costs increased by $0.6 million to $4.0 million for the year ended December 31, 2019, compared to $3.4 million for the year ended December 31, 2018. This cost increase was primarily the result of higher sales volumes of natural gas. The cost on a per BOE basis increased 14% from $1.87 for the year ended December 31, 2018, to $2.13 for the year ended December 31, 2019, primarily attributable to higher per BOE costs under our long-term natural gas purchase contract as compared to the short-term natural gas contract in the comparative period.
 
Production Taxes

Production taxes decreased $0.4 million to $3.3 million for the year ended December 31, 2019, compared to $3.7 million for the same period in 2018. On a per BOE basis, production taxes decreased to $1.77 per BOE for the year ended December 31, 2019, a 14% decrease from the $2.05 per BOE for the year ended December 31, 2018, primarily due to lower revenue for 2019 as compared to 2018.


42







General and Administrative Expenses (“G&A”)

G&A decreased by $4.9 million to $28.4 million for the year ended December 31, 2019, as compared to $33.3 million for the year ended December 31, 2018. The decrease of $4.9 million in G&A was primarily attributable to a decrease in stock-based compensation of $2.5 million, a decrease in personnel costs of $1.0 million including severance costs and directors fees, and a $1.4 million decrease in professional services.

Depreciation, Depletion, Amortization and Accretion (“DD&A”)

DD&A expense was $33.3 million for the year ended December 31, 2019, compared to $25.4 million for the year ended December 31, 2018; resulting in an increase of $7.9 million, or 31%. Our DD&A rate increased by 28% to $17.85 per BOE during the year ended December 31, 2019 from $14.00 per BOE for the year ended December 31, 2018. To a smaller degree, DD&A expense increased as a result of a 3% increase in sales volumes for the year ended December 31, 2019 as compared to the year ended December 31, 2018. The increase was primarily due to a net increase of proved oil and natural gas net book value, prior to impairment, and a 71% decrease in total proved reserves volumes on a BOE basis.

Impairment of Oil and Natural Gas Properties

The Company recorded charges for impairment of oil and natural gas properties of $228.3 million for the year ended December 31, 2019.  The net book value of the Company’s oil and natural gas properties exceeded the ceiling limitation calculated as required under the full cost method of accounting at December 31, 2019 and September 30, 2019December 31, 2019 discounted future net cash flows and proved reserves volumes decreased 63% and 71%, respectively, from our December 31, 2018 proved reserves report. As a result of the uncertainty in our ability to fund future development costs associated with proved undeveloped reserves, all proved undeveloped reserves were reclassified to unproved. The reclassification represented nearly 23%, or $75.3 million, of the decrease in discounted future net cash flows and approximately 50% of the decrease in proved volumes, or 21,487 MBOE. Oil and natural gas pricing, calculated as required by the SEC, decreased approximately 16% from December 31, 2018 as compared to December 31, 2019. Proved reserve volumes reported in the December 31, 2019 proved reserves report were over 20%, or 8,699 MBOE, lower due to the decrease in pricing.  Discounted future net cash flows decreased more than 40%, or $131.5 million, as a result of the decrease in pricing used in estimating proved reserves.
 
Other Income (Expenses)

The following table shows a comparison of other expenses for the years ended December 31, 2019 and 2018:
 
Years Ended December 31,
 
 
 
 
 
2019
 
2018
 
Variance
 
%
 
(In Thousands)
 
 
 
 
Other income (expense):
 

 
 

 
 

 
 

Loss on early extinguishment of debt
$
(1,299
)
 
$
(20,370
)
 
$
19,071

 
(94
)%
Gain (Loss) from commodity derivatives, net
(8,985
)
 
55

 
(9,040
)
 
(16,436
)%
Change in fair value of financial instruments
(3,573
)
 
58,343

 
(61,916
)
 
(106
)%
Interest expense
(11,426
)
 
(32,827
)
 
21,401

 
(65
)%
Other income
435

 
2

 
433

 
21,650
 %
Total other income (expenses)
$
(24,848
)
 
$
5,203

 
$
(30,051
)
 
(578
)%
 
Loss on Early Extinguishment of Debt

In 2019, the Company repurchased certain overriding royalty interests in the acreage previously sold under the ORRI Agreement (as defined in Note 5 - Acquisitions and Divestitures to our consolidated financial statements), resulting in a $1.3 million loss on extinguishment of a portion of the financing arrangement.

On October 10, 2018, we converted approximately $68.3 million of our Second Lien Credit Agreement into a combination of 39,254 shares of Series D Preferred Stock, stated value of $1,000 per share, and 5,952,763 shares of common stock. As a result, we recorded a loss of approximately $12.3 million on early extinguishment of debt. Concurrently, we executed the Revolving Credit Agreement, from which we received proceeds of $60.0 million that were used to pay off the outstanding balance of the Riverstone First Lien Credit Agreement totaling $57.0 million, including accrued interest and prepayment penalties. As a result

43







of the prepayment of the Riverstone First Lien Credit Agreement, we recorded a loss of approximately $8.1 million on early extinguishment of debt.
  
Gain (Loss) from Commodity Derivatives, net

Loss on our commodity derivatives increased by $9.0 million during the year ended December 31, 2019, resulting primarily from changes in underlying commodity prices as compared to the hedged prices within derivative instruments and the monthly settlement of those instruments. Additionally, during the year ended December 31, 2019, our net loss from commodity derivatives consisted primarily of net losses of $3.4 million from settled positions and $5.6 million from mark-to-market adjustments on unsettled positions. During the year ended December 31, 2018, our net loss from commodity derivatives consisted primarily of net losses of $1.9 million from settled positions and $2.0 million from mark-to-market adjustments on unsettled positions.
 
Change in Fair Value of Financial Instruments

The change in fair value of financial instruments is attributable to embedded derivatives associated with the conversion feature of the Second Lien Term Loan (as defined in Note 11 - Long-Term Debt to our consolidated financial statements). Changes in our stock price directly affect the fair value of the embedded derivative. During the period from January 1, 2019 to March 5, 2019, we recognized a loss of $0.3 million on the embedded derivative. On March 5, 2019, the embedded derivative was extinguished as part of the 2019 Transaction Agreement (as defined in Note 11 - Long-Term Debt to our consolidated financial statements).

As of December 31, 2019, we recognized an embedded derivative associated the ARM sales agreement as the agreement no longer meets the criteria for the “normal purchase normal sales” exception under ASC 815, “Derivatives and Hedging”, due to the Company not meeting the minimum quantities deliverable under the contract and the net settlement criteria being met (see Note 21 - Commitments and Contingencies to our consolidated financial statements). Upon recognition, we recorded a loss of $3.2 million on the embedded derivative.

Interest Expense

Interest expense for the year ended December 31, 2019 was $11.4 million compared to $32.8 million for the year ended December 31, 2018. For the year ended December 31, 2019, interest expense included $6.5 million from the Revolving Credit Agreement, $1.6 million of PIK interest, $0.9 million from financing arrangements, $1.7 million related to amortization of the debt discount on our Second Lien Term Loan and $0.8 million for amortization debt issuance costs. For the year ended December 31, 2018, we incurred interest expense of $32.8 million, which included $3.0 million for quarterly interest payments on notes payable and term loans, $12.2 million of PIK interest, $14.4 million related to amortization of debt discount on our Second Lien Term Loan and $3.2 million for amortization debt issuance costs. The Second Lien Term Loan was converted to common and preferred stock in March 2019, and, as a result, there was less paid-in-kind interest and amortization of debt discount during the 2019 period.

Going Concern and Liquidity

Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions and investors, the sale of equity and equity derivative securities and targeted asset dispositions. Our primary uses of capital have been for the acquisition, development, exploration and exploitation of oil and natural gas properties, in addition to refinancing of debt instruments. Our ability to fund planned capital expenditures and to make acquisitions depends upon commodity prices, our future operating performance, availability of borrowings under our Revolving Credit Agreement, and more broadly, on the availability of equity and debt financing, which is affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control. The Company has negative working capital, a history of net operating losses and cash flows used in operations. We cannot predict whether additional liquidity from equity or debt financings or borrowings under our Revolving Credit Agreement will be available on acceptable terms, or at all, in the foreseeable future.
    
From time to time, we raise capital through the sale of oil and natural gas properties that are not in our current drilling plans. In August 2019, we sold approximately 513 noncontiguous net acres in New Mexico for net cash proceeds of $16.6 million. The Company repurchased certain overriding royalty interests in the acreage previously sold under the ORRI Agreement for $2.6 million, resulting in net proceeds of approximately $14 million that were used for general corporate purposes and to restart drilling and completion activity during the third quarter. We may continue to enter into such sales in the future.

During the year ended December 31, 2019, we exchanged and converted our outstanding Second Lien Term Loan with a face value of approximately $133.6 million for a combination of preferred stock and common stock, of which $60.0 million was converted into Series E Preferred Stock, $55.0 million was converted into Series F Preferred Stock, and $18.6 million was converted

44







into common stock based on a $1.88 per share issuance price. Additionally, the conversion features and voting rights on the existing Series C Preferred Stock and Series D Preferred Stock were eliminated in exchange for the issuance of 7.8 million shares of our common stock. The net dilution to our common stockholders was decreased by approximately 12 million shares as the result of the conversion of the Second Lien Term Loan and the elimination of the conversion features on the Series C Preferred Stock and the Series D Preferred Stock.

In 2019, we relied significantly on borrowings under our Revolving Credit Agreement to provide drilling and completion capital and for other general corporate purposes. Our ability to maintain or increase our borrowing base under our Revolving Credit Agreement is dependent on numerous factors, including our ability to add proved reserves and production, commodity prices and the lending policies of our lenders. We currently have four wells drilled and awaiting completion (referred to as “DUC” wells) that, when and if completed, would add to our current production cash flows in 2020.

As of December 31, 2019, we were fully drawn against the borrowing base under our Revolving Credit Agreement (as defined in Note 11 - Long-Term Debt to our Consolidated Financial Statements), with $115 million of indebtedness outstanding under our Revolving Credit Agreement. As provided for in the Seventh Amendment to our Revolving Credit Agreement and as a result of a decrease in commodity prices, on January 17, 2020, the borrowing base was decreased to $90.0 million.

As a result of the January 17, 2020 redetermination of the borrowing base, a borrowing base deficiency in the amount of $25 million (the “Borrowing Base Deficiency”) was created under the Revolving Credit Agreement. The Borrowing Base Deficiency constitutes the difference between the principal amount of borrowings currently outstanding under the Revolving Credit Agreement, $115 million, and the borrowing base as so redetermined, $90 million. On February 28, 2020, we paid $17.25 million towards the Borrowing Base Deficiency. Pursuant to the Fourteenth Amendment to the Revolving Credit Agreement, the remaining payment of $7.8 million is due June 5, 2020.

The Company is seeking additional funding and considering certain strategic transactions to enable it to pay the remaining Borrowing Base Deficiency amount of $7.8 million. There is no assurance, however, that funding or additional transactions will be completed or that the bank group will agree to further deficiency payment extensions. If the Company is unable to repay the remaining borrowing base deficiency as and when required under the Revolving Credit Agreement, an event of default would occur under the Revolving Credit Agreement.

Our next borrowing base redetermination is scheduled to occur on or about June 5, 2020. If the borrowing base is further reduced by the lenders in connection with this redetermination, we will be required to repay borrowings in excess of the borrowing base as we do not have sufficient additional oil and natural gas properties to eliminate the borrowing base deficiency by pledging additional oil and natural gas properties to secure our obligations under the Revolving Credit Agreement. Under the Revolving Credit Agreement, we have the option to affect such repayment either in full within 30 days after the redetermination or in monthly installments over a six-month period after the redetermination.

Our liquidity and ability to comply with debt covenants under our Revolving Credit Agreement have been negatively impacted by the recent decrease in commodity prices, which have fallen significantly since the beginning of 2020, due in part to failed OPEC negotiations as well as concerns about the COVID-19 pandemic, which has significantly decreased worldwide demand for oil and natural gas. Our Revolving Credit Agreement contains financial covenants that require the Company to maintain a ratio of Total Debt to EBITDAX (each as defined in the Revolving Credit Agreement) (the “Leverage Ratio”) of not more than 4.00 to 1.00 and a ratio of Current Assets to Current Liabilities (each as defined in the Revolving Credit Agreement) (the “Current Ratio”) of not less than 1.00 to 1.00 as of the last day of each fiscal quarter thereafter. See Note 11-Long-term Debt to our consolidated financial statements for additional information regarding the financial covenants under our Revolving Credit Agreement. As of December 31, 2019, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants under the Revolving Credit Agreement. Pursuant to the Twelfth Amendment (as defined in Note 11 - Long-Term Debt to our consolidated financial statements), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants as of December 31, 2019.

As of March 31, 2020, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants. Pursuant to the Fourteenth Amendment (as defined in Note 11 - Long-Term Debt), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants as of March 31, 2020. If we are not able to pay or defer the $7.8 million Borrowing Base Deficiency due on June 5, 2020 or do not maintain compliance with the covenants, the obligations of the Company under the Revolving Credit Agreement may be accelerated, which would have a material adverse effect on our business.

Fluctuations in oil and natural gas prices have a material impact on our financial position, results of operations, cash flows and quantities of oil, natural gas and NGL reserves that may be economically produced. Historically, oil and natural gas

45







prices have been volatile, and may be subject to wide fluctuations in the future. Furthermore, the Company has negative working capital, a history of net operating losses and cash flows use in operations. If continued depressed prices persist, the Company will continue to experience operating losses, negative cash flows from operating activities, and negative working capital.

In order to improve our leverage position and current ratio to meet the financial covenants under the Revolving Credit Agreement, we are currently pursuing or considering a number of actions, which in certain cases may require the consent of current lenders and stockholders. In November 2019, our board of directors formed a Special Committee tasked with reviewing and evaluating strategic alternatives that may enhance the value of the Company, including alternatives that may be available to identify and access further sources of liquidity. The Special Committee hired financial and legal advisors to advise the Special Committee on these matters.

The Special Committee continues to explore financing alternatives and deleveraging transactions. We are also addressing operational matters such as adjusting our capital budget and improving cash flows from operations by continuing to reduce costs and intend to continue to pursue and consider other strategic alternatives.

There can be no assurance that we will be able to implement any of these plans successfully, or that such plans, if executed, will result in the ability to pay borrowing base deficiencies, generate sufficient liquidity to continue as a going concern or comply with our Revolving Credit Agreement covenants. These factors raise substantial doubt about our ability to continue as a going concern within twelve-month period following the date of issuance of these consolidated financial statements.

    Our ability to fund our future operations, including drilling and completion capital expenditures, will largely be dependent upon our active management of our drilling and completion budget, and, if necessary, the continued suspension of our drilling plans until we are able to identify and access further sources of liquidity. We are currently considering alternative secured financing to replace the current revolving credit facility under our Revolving Credit Agreement. We are the operator of 100% of our 2020 operational capital program and we expect to operate a substantial majority of wells we may drill in the near future, and, as a result, we have had, and expect to continue to have, the discretion to control the amount and timing of a substantial portion of our capital expenditures. The Company has recently elected to temporarily suspend current drilling operations, until necessary funding is obtained, to focus on production and facilities optimization while the results and performance of the new wells are evaluated. In response to our efforts to strengthen our capital through reducing operating costs, during April 2020 the Company elected to shut-in 12 wells which were identified as uneconomic as a result of the continued decline in commodity prices in 2020 and 19 additional wells have been identified for short term shut-in through May and June. The 19 wells identified for short term shut-in are naturally flowing wells and could be turned back to sales quickly as market conditions dictate. We may in the future, however, determine it prudent to extend the current suspension or temporarily suspend further drilling and completion operations due to capital constraints, shortage of liquidity, or reduced returns on investment as a result of commodity price weakness.

Information about our cash flows for the years ended December 31, 2019 and 2018, are presented in the following table (in thousands)
 
Years Ended December 31,
 
2019
 
2018
Cash provided by (used in):
 

 
 

Operating activities
$
(25,824
)
 
$
92,132

Investing activities
(65,527
)
 
(242,935
)
Financing activities
73,967

 
154,478

Net change in cash and cash equivalents
$
(17,384
)
 
$
3,675

 
Operating Activities

For the year ended December 31, 2019, net cash used in operating activities was $25.8 million, compared to net cash provided by operating activities of $92.1 million for the year ended December 31, 2018. The $25.8 million used in operating activities was primarily made up of net loss of $272.1 million, non cash adjustments to net income of $282.5 million, and cash used by change in working capital of $36.2 million, primarily the result of payments of accounts payable outstanding at December 31, 2018.

46








Investing Activities

For the year ended December 31, 2019, net cash used in investing activities was $65.5 million, compared to $242.9 million for the same period in 2018. The $65.5 million in cash used for investing activities during the year ended December 31, 2019, was primarily attributable to the following:
 
cash payments of approximately $82.4 million for capital expenditures on oil and gas properties; partially offset by

approximately $16.9 million in proceeds from the sale of assets.

Capital Expenditure Breakdown

During the year ended December 31, 2019, drilling and completion capital cost incurred was $93.1 million, comprised of $36.7 million on 2018 DUC wells and $40.3 million related to the 2019 drilling program, plus an additional $3.7 million related to the 2018 drilling program and $10.8 million for facility and water supply and disposal projects. Of the capital cost incurred on 2018 DUC wells, adjustments to Lilis’ working interests due to non-consent elections increased capital costs by $7.5 million while reducing accounts receivable from other working interest partners by that amount.

At December 31, 2019, we had four DUC wells compared to six DUC wells at December 31, 2018. Although additional costs were incurred on all six DUC wells during 2019, four wells were placed on production during 2019. Those four wells included the Oso #1H, Haley #1H, Haley #2H, and NE Axis #2H. In addition, three wells were drilled, completed and placed on production during the fourth quarter of 2019, those being the Kudu A#2H, Kudu B#2H and Grizzly A#2H.
 
During the second half of 2019, under the direction of the Company’s new operations team, significant reductions in drilling days and drilling costs have been achieved. Reduced drilling cycle times were realized by incorporating oil-based drilling mud, utilizing a higher quality rig and better down hole tools/configurations. This has reduced the number of bit trips by 44% and increased the rate of penetration by 110% over prior wells drilled in early 2019. The identification of optimal drilling zones within drilling targets has also reduced time spent slide drilling by 5%. The Company has also improved in-zone precision from approximately 89% in 2018 to approximately 100% in recent wells. In addition to these changes, continuous drilling optimization is being evaluated and implemented with different hole sizes and configurations to further reduce cycle times. If and when the Company obtains the capital required to do so, the Company expects to incorporate these improved techniques on all future wells with the goal of achieving similar cost savings.

 
Year Ended
December 31,
 
2019
 
2018
Leasehold Acquisitions
 
 
 
    Proved
$

 
$
20,040

    Unproved
1,643

 
98,193

2017 Drilling & Completion Program

 
12,440

2018 Drilling & Completion Program
3,658

 
119,350

2018 Drilling & Completion Program-DUCs
36,738

 
24,887

2018 Working Interest Acquisitions

 
1,293

2019 Drilling & Completion Program
40,263

 

Facilities & Other Projects
10,824

 
9,484

Total Capital Spending
$
93,126

 
$
285,687


Financing Activities

For the year ended December 31, 2019, net cash provided by financing activities was $74.0 million compared to cash provided by financing activities of $154.5 million during the same period in 2018. The $74.0 million in net cash provided by financing activities included $56.9 million in net proceeds from drawdowns on the Revolving Credit Agreement and $38.2 million in net proceeds from the ORRI Agreement and WI Agreement (as defined in Note 5 - Acquisitions and Divestitures to our consolidated financial statements), offset by repayment of $18.0 million on the Revolving Credit Agreement.

47








Capital Structure
    
Revolving Credit Agreement

On October 10, 2018, we entered into a five-year, $500 million senior secured revolving credit agreement (the “Revolving Credit Agreement”) by and among the Company, as borrower, certain subsidiaries of the Company, as guarantors (the “Guarantors”), BMO Harris Bank, N.A., as administrative agent, and the lenders party thereto. The Revolving Credit Agreement provides for a senior secured reserves based revolving credit facility with an initial borrowing base of $95 million and also provides for issuance of letters of credit in an aggregate amount up to $5 million. The borrowing base is subject to semiannual redetermination in May and November of each year.

Borrowings under the Revolving Credit Agreement bear interest at a floating rate of either LIBOR or a specified base rate plus a margin determined based upon the usage of the borrowing base. The Company is required to pay a commitment fee of 0.5% per annum on any unused portion of the borrowing base. The Company’s obligations under the Revolving Credit Agreement are secured by first priority liens on substantially all of the Company’s and the Guarantors’ assets and are unconditionally guaranteed by each of the Guarantors.

The Revolving Credit Agreement matures on the earlier of the fifth anniversary of the closing date and the date that is 180 days prior to the maturity date of the Second Lien Credit Agreement (as defined below). Borrowings under the Revolving Credit Agreement are subject to mandatory repayment with the net proceeds of certain asset sales and debt incurrences or if a borrowing base deficiency occurs. The Company also may voluntarily repay borrowings from time to time and, subject to the borrowing base limitation and other customary conditions, may re-borrow amounts that are voluntarily repaid.

The Revolving Credit Agreement contains certain customary representations and warranties and affirmative and negative covenants, including covenants relating to: maintenance of books and records, financial reporting and notification, compliance with laws, maintenance of properties and insurance; and limitations on incurrence of indebtedness, liens, fundamental changes, international operations, asset sales, certain debt payments and amendments, restrictive agreements, investments, dividends and other restricted payments and hedging. It also requires the Company to maintain a ratio of Total Debt to EBITDAX of not more than 4.00 to 1.00 and a ratio of current assets to current liabilities of not less than 1.00 to 1.00 (each as defined in the Revolving Credit Agreement).

As of December 31, 2019, the Company was not in compliance with the Current Ratio covenant or Leverage Ratio covenant under the Revolving Credit Agreement (as defined and described in Note 11 - Long-Term Debt to our consolidated financial statements). Pursuant to the Twelfth Amendment (as defined in Note 11 - Long-Term Debt to our consolidated financial statements), the Company obtained a waiver from the requisite lenders of its compliance with the Current Ratio and Leverage Ratio covenant, among other waivers, as of December 31, 2019.

Seventh Amendment to Revolving Credit Agreement

On January 17, 2020, the Company entered into a Seventh Amendment (the “Seventh Amendment”) to the Revolving Credit Agreement. The Seventh Amendment provided for the January 14, 2020 redetermination of the borrowing base under the Revolving Credit Agreement (the “Scheduled Redetermination”). As so redetermined, the borrowing base was set at $90 million. As a result of the Scheduled Redetermination, a borrowing base deficiency in the amount of $25 million existed under the Revolving Credit Agreement (the “Borrowing Base Deficiency”). The Seventh Amendment required repayment of the Borrowing Base Deficiency in four equal monthly installments, with the first payment of $6.25 million scheduled to occur on January 24, 2020.

Eighth Amendment to Revolving Credit Agreement

On January 23, 2020, the Company entered into an Eighth Amendment (the “Eighth Amendment”) to the Revolving Credit Agreement. The Eighth Amendment, among other things, amended the Revolving Credit Agreement to provide that the due date for the first Installment Payment was extended from January 24, 2020 to February 7, 2020 and that the due dates for the subsequent Installment Payments were February 14, 2020, March 16, 2020 and April 14, 2020.


48







Ninth Amendment to Revolving Credit Agreement

On February 6, 2020, the Company entered into an Ninth Amendment (the “Ninth Amendment”) to the Revolving Credit Agreement. The Ninth Amendment amended the Revolving Credit Agreement to provide that the due date for the first Installment Payment was extended from February 7, 2020 to February 18, 2020 and the due date for the second Installment Payment was extended from February 14, 2020 to February 18, 2020. The due dates for the two subsequent Installment Payments remained March 16, 2020 and April 14, 2020.

Tenth Amendment to Revolving Credit Agreement
    
On February 14, 2020, the Company entered into an Tenth Amendment (the “Tenth Amendment”) to the Revolving Credit Agreement. The Tenth Amendment amended the Revolving Credit Agreement to provide that the due date for the first two Installment Payments was extended from February 18, 2020 to February 28, 2020 and the due dates for the two subsequent Installment Payments remained March 16, 2020 and April 14, 2020.

Eleventh Amendment to Revolving Credit Agreement
    
On March 13, 2020, the Company entered into an Eleventh Amendment (the “Eleventh Amendment”) to the Revolving Credit Agreement. The Eleventh Amendment amended the Revolving Credit Agreement to extend the due date for the $1.50 million installment of the Borrowing Base Deficiency from March 16, 2020 to March 30, 2020. The due date for the final installment of the Borrowing Base Deficiency remained April 14, 2020.

Twelfth Amendment to Revolving Credit Agreement

On March 30, 2020, the Company entered into an Twelfth Amendment (the “Twelfth Amendment”) to the Revolving Credit Agreement. The Twelfth Amendment amended the Revolving Credit Agreement to, among other things extend the due date for the $1.50 million installment of the Borrowing Base Deficiency from March 30, 2020 to April 14, 2020. The due date for the final installment of the Borrowing Base Deficiency remains April 14, 2020. The lenders under the Revolving Credit Agreement also waived the requirement under the Revolving Credit Agreement that the Company comply with a leverage ratio and a current ratio, in each case, as of December 31, 2019, and granted certain other waivers, including the requirement to comply with certain hedging obligations set forth in the Revolving Credit Agreement until June 30, 2020. Additionally, the lenders consented to an extension of an additional 45 days for the Company to provide its audited annual financial statements for the fiscal year ended December 31, 2019, and waived the requirement that such financial statements be delivered without a “going concern” or like qualification or exception.

Thirteenth Amendment to Revolving Credit Agreement

On April 14, 2020, the Company entered into a Thirteenth Amendment (the “Thirteenth Amendment”) to the Revolving Credit Agreement. The Thirteenth Amendment amended the Revolving Credit Agreement to extend the due date for the final $7.75 million installment of the Borrowing Base Deficiency from April 14, 2020 to April 21, 2020.

Fourteenth Amendment to Revolving Credit Agreement

On April 21, 2020, the Company entered into a Fourteenth Amendment (the “Fourteenth Amendment”) to the Revolving Credit Agreement. The Fourteenth Amendment, among other things, amended the Revolving Credit Agreement to extend the due date for the final $7.75 million installment of the Borrowing Base Deficiency from April 21, 2020 to June 5, 2020. The lenders under the Revolving Credit Agreement also waived the requirement under the Revolving Credit Agreement that the Company comply with a leverage ratio and a current ratio, in each case, as of March 31, 2020. Additionally, the lenders consented to defer the timing of the scheduled spring redetermination of the borrowing base under the Revolving Credit Agreement from on or about May 1, 2020 to on or about June 5, 2020.

Second Lien Credit Agreement

On April 26, 2017, the Company entered into a 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 amended (the “Second Lien Credit Agreement”) comprised of convertible loans in an aggregate initial principal amount of up to $125 million in two tranches. The first tranche consisted of an $80 million term loan (the “Second Lien Term Loan”), which was fully drawn and funded on April 26, 2017. The second tranche consisted of up to $45 million in delayed-draw term loans (the “Delayed Draw Term Loan”

49







and, together with the Second Lien Term Loan, the “Second Lien Loans”). The Second Lien Term Loan was subsequently converted into common stock and preferred stock in two separate transactions on October 2018 and March 2019 as described below.

Exchange and Conversion of Second Lien Term Loan and Issuance of Preferred Stock

On October 10, 2018, as consideration for the reduction by approximately $56.3 million of the outstanding principal amount of the Second Lien Term Loan under the Second Lien Credit Agreement, together with accrued and unpaid interest and the make-whole amount thereon totaling approximately $11.9 million, the Company entered into a transaction by and among the Company and certain private funds affiliated with the Värde Parties, pursuant to which the Company agreed to issue to the Värde Parties an aggregate of 5,952,763 shares of the Company’s common stock, par value $0.0001 per share, which includes 5,802,763 shares of common stock at an exchange price of $5.00 per share of common stock plus an additional 150,000 shares of common stock, and 39,254 shares of a newly created series of preferred stock of the Company, designated as “Series D 8.25% Convertible Participating Preferred Stock” (the “Series D Preferred Stock”);

On March 5, 2019, in exchange for satisfaction of the outstanding principal amount of the Second Lien Term Loan, accrued and unpaid interest thereon and the make-whole premium totaling approximately $133.6 million, the Company issued to the Värde Parties an aggregate of 60,000 shares of a newly created series of preferred stock of the Company, designated as “Series E 8.25% Convertible Participating Preferred Stock”, corresponding to $60 million of the Second Lien Exchange Amount based on the aggregate initial Stated Value of the shares of Series E Preferred Stock; 55,000 shares of a newly created series of preferred stock of the Company, designated as “Series F 9.00% Participating Preferred Stock”, corresponding to $55 million of the Second Lien Exchange Amount based on the aggregate initial Stated Value of the shares of Series F Preferred Stock; and 9,891,638 shares of common stock, corresponding to approximately $18.6 million of the Second Lien Exchange Amount, based on the $1.88 closing price of the common stock on the NYSE American on March 4, 2019.

In connection with the transaction, the Company also issued to the Värde Parties an aggregate of 7,750,000 shares of common stock as consideration for the Värde Parties’ consent to the amendment of the terms of the Series C Preferred Stock and the Series D Preferred Stock to, among other things, eliminate the convertibility of the Series C Preferred Stock and Series D Preferred Stock into shares of common stock and the voting rights of the Series C Preferred Stock and the Series D Preferred Stock.
    
See Note 13 - Related Party Transactions and Note 15 - Preferred Stock to our consolidated financial statements for additional information about Related Party Transactions and the Company’s Preferred Stock.

Related Party Transactions

On March 5, 2019, pursuant to the 2019 Transaction Agreement and the related payoff letter, the Company agreed to issue to the Värde Parties shares of two new series of its preferred stock and shares of its common stock, as consideration for the termination of the Second Lien Credit Agreement with the Värde Parties and the satisfaction in full, in lieu of repayment in cash, of the Second Lien Term Loan under the Second Lien Credit Agreement. See Note 11 - Long-Term Debt and Note 15 - Preferred Stock to our consolidated financial statements for additional information.

On July 31, 2019, the Company entered into two agreements with affiliates of Värde for the sale of an overriding royalty interest and a non-operated working interest in undeveloped assets. WLR’s (as defined in Note 5 - Acquisitions and Divestitures to our consolidated financial statements) proportionate share of revenue of $0.4 million for the year ended December 31, 2019 is included in interest expense on the Company’s consolidated statements of operations. Three of the properties included in the WI Agreement were producing as of December 31, 2019 and net revenue (revenue less production costs) of $0.5 million is included in interest expense on the Company’s consolidated statements of operations. See Note 5 - Acquisitions and Divestitures to our consolidated financial statements for additional information.

On August 16, 2019, the Company entered into an agreement with an affiliate of Värde to repurchase the overriding royalty interest for the New Mexico acreage sold. See Note 5 - Acquisitions and Divestitures to our consolidated financial statements for additional information.

On April 21, 2020, Värde Investment Partners, L.P., an affiliate of Värde Partners, Inc., became a lender under our Revolving Credit Agreement by acquiring, from a prior lender, loans and commitments under the Revolving Credit Agreement in the principal amount of approximately $25.7 million. The loans and commitments acquired by Värde Investment Partners, L.P. are subject to certain subordination provisions set forth in the Revolving Credit Agreement, as amended by the Fourteenth Amendment thereto dated April 21, 2020. For additional information regarding our Revolving Credit Agreement, as amended, see Note 11 - Long-Term Debt to our consolidated financial statements included in this Annual Report and “Item 7 - Management’s

50







Discussion and Analysis of Financial Condition and Results of Operations - Revolving Credit Agreement” in Part II of this Annual Report.

Subsequent Events

Sale of Certain Undeveloped Acreage in New Mexico

On February 28, 2020, the Company closed the sale of approximately 1,185 undeveloped net acres in Lea County, New Mexico, for net cash proceeds of approximately $24.1 million, subject to customary purchase price adjustments. The proceeds were used to fund a substantial portion of the Borrowing Base Deficiency with the balance to be used for general corporate purposes.

COVID-19

On January 30, 2020, the World Health Organization (“WHO”) announced a global health emergency due to the COVID-19 outbreak, which originated in Wuhan, China, and the risks to the international community as the virus spreads globally beyond its point of origin. In March 2020, the WHO classified the COVID-19 outbreak as a pandemic, based on the rapid increase in exposure globally.

In addition, in March 2020, members of OPEC failed to agree on production levels which has caused an increased supply and has led to a substantial decrease in oil prices and an increasingly volatile market. The oil price war ended with a deal to cut global petroleum output but did not go far enough to offset the impact of COVID-19 on demand. There has been an increase in supply which has pushed prices down further since March. If the depressed pricing continues for an extended period it will lead to i) further reductions in the borrowing base under our credit facility which would require us to make additional borrowing base deficiency payments, ii) reductions in reserves, and iii) additional impairment of proved and unproved oil and gas properties. We also expect disclosures of supplemental oil and gas information to be impacted by price declines.

In response to recent commodity prices and our efforts to strengthen our capital through reducing operating costs,during April 2020 the Company elected to shut-in 12 wells which were identified as uneconomic as a result of the continued decline in commodity prices in 2020 and 19 additional wells have been identified for short term shut-in through May and June. The 19 wells identified for short term shut-in are naturally flowing wells and could be turned back to sales quickly as market conditions dictate. The Company has also implemented an employee furlough program to further reduce general and administrative costs.  The furloughed employees will not receive compensation from the Company during the furlough period; however, subject to local regulations, these employees will be eligible for unemployment benefits.  The furlough period is uncertain at this time and will be reassessed as business conditions dictate.

The full impact of the COVID-19 outbreak and the decline in oil prices continues to evolve as of the date of this Annual Report. As such, it is uncertain as to the full magnitude that these events will have on the Company’s financial condition, liquidity, and future results of operations.

Management is actively monitoring the global situation on its financial condition, liquidity, operations, suppliers, industry, and workforce. Given the daily evolution of the COVID-19 outbreak and the global responses to curb its spread, the Company is not able to estimate the effects of the COVID-19 outbreak on its results of operations, financial condition, or liquidity for fiscal year 2020.

These matters could have a continued material adverse impact on economic and market conditions and trigger a period of global economic slowdown, which may impair the Company’s asset values, including reserve estimates.  Further, consumer demand has decreased since the spread of the outbreak and new travel restrictions placed by governments in an effort to curtail the spread of the coronavirus. Although the Company cannot estimate the length or gravity of the impacts of these events at this time, if the pandemic and/or decreased oil prices continue, they will have a material adverse effect on the Company’s results of future operations, financial position, and liquidity in fiscal year 2020. 

Coronavirus Aid, Relief, and Economic Security Act

On March 27, 2020, President Trump signed into law the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”). The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer side social security payments, net operating loss carryback periods, alternative minimum tax credit refunds, modifications to the net interest deduction limitations, increased limitations on qualified charitable contributions, and technical corrections to tax depreciation methods for qualified improvement property.


51







It also appropriated funds for the SBA Paycheck Protection Program loans that are forgivable in certain situations to promote continued employment, as well as Economic Injury Disaster Loans to provide liquidity to small businesses harmed by COVID-19. There is no assurance we are eligible for these funds or will be able to obtain them.

We continue to examine the impact that the CARES Act may have on our business. Currently, we are unable to determine the impact that the CARES Act will have on our financial condition, results of operations, or liquidity.

Effects of Inflation and Pricing

The oil and gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry puts pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Material changes in prices impact the current revenue stream, estimates of future reserves, borrowing base calculations of bank loans and the value of properties in purchase and sale transactions. Material changes in prices, such as those experienced to date in 2020, can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel. We anticipate business costs will vary in accordance with commodity prices for oil and natural gas, and the associated increase or decrease in demand for services related to production and exploration.

Off-Balance Sheet Arrangements
 
We do not have any material off-balance sheet arrangements.

Commitments and Contractual Obligations
 
On August 2, 2018, the Company executed a five-year agreement with SCM Crude, LLC, an affiliate of SCM, to secure firm takeaway pipeline capacity and pricing on a long-haul pipeline to the Gulf Coast region commencing July 1, 2019. On March 11, 2019, the agreement was replaced with a five-year agreement between the Company and ARM, a related company to SCM. The new agreement accelerated the start date to March 2019 and guarantees firm takeaway capacity on a long-haul pipeline to Corpus Christi, Texas, once completed, at a specified price. Under the terms of the new contract, the Company received pricing differentials on the crude oil sales contract subject to minimum quantities of crude oil to be delivered as follows:
Date
Quantity (Barrels per Day)
March 2019 - June 2019
5,000
July 2019 - December 2019
4,000
January 2020 - June 2020
5,000
July 2020 - June 2021
6,000
July 2021 - December 2024 (1)
7,500
(1) Extending to the later of December 2024 or 5 years from the EPIC Crude Oil pipeline in-service date (February 2025).

Further, ARM has agreed to purchase crude from the Company based upon Magellan East Houston pricing with a fixed “differential basis”. As of December 31, 2019, the agreement no longer meets the criteria for the “normal purchase normal sales” exception under ASC 815, “Derivatives and Hedging”, due to the Company not meeting the minimum quantities deliverable under the contract and the net settlement criteria being met. See Note 9 - Derivatives to our consolidated financial statements for information regarding the recognition of the net settlement mechanism as an embedded derivative over the remainder of the contract.

Critical Accounting Policies and Estimates

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

Critical accounting policies are defined as those significant accounting policies that are most critical to an understanding of a company’s financial condition and results of operation. We consider an accounting estimate or judgment to be critical if (i) it

52







requires assumptions to be made that were uncertain at the time the estimate was made, and (ii) changes in the estimate or different estimates that could have been selected could have a material impact on our results of operations or financial condition.

Use of Estimates
 
The accompanying 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, and common stock; and the allocation of general and administrative expenses. Actual results could differ significantly from these estimates.

Oil and Natural Gas Reserves

We follow the full cost method of accounting. All of our oil and natural gas properties are located within the United States and, therefore, all costs related to the acquisition and development of oil and natural gas properties are capitalized into a single cost center referred to as a full cost pool. Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and natural gas reserves. Under the full cost method of accounting, capitalized oil and natural gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves less the future cash outflows associated with the asset retirement obligations that have been accrued on the balance sheet plus the cost, or estimated fair value if lower, of unproved properties. Should capitalized costs exceed this ceiling, impairment would be recognized. Under the applicable SEC rules, we prepared our oil and natural gas reserves estimates as of December 31, 2019, using the average, first-day-of-the-month price during the 12-month period ended December 31, 2019.

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

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

Oil and Natural Gas Properties-Full Cost Method of Accounting


53







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

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

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

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

Under the full cost method of accounting, capitalized oil and natural gas property costs, less accumulated depletion and net of deferred income taxes, may not exceed an amount equal to the present value using the preceding 12-months’ average price based on closing prices on the first day of each month, adjusted for price differentials, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves, plus the cost, or estimated fair value if lower, of unproved properties. Should capitalized costs exceed this ceiling, we would recognize impairment.

Subsequent to December 31, 2019, commodity prices declined significantly, which we expect to significantly reduce the undiscounted expected cash flows from our proved reserves. Declines in commodity prices used for our full cost ceiling test will result in additional impairments of our proved properties during 2020. If there are significant delays in the completion of our drilling program due to capital constraints resulting from current market conditions, we will lose a portion of our acreage through lease expirations that will result in impairments recorded throughout 2020 related to those expirations.

Derivative Instruments

All derivative instruments are recorded on the consolidated balance sheet at fair value as either an asset or a liability with changes in fair value recognized currently in earnings. Although commodity based derivative instruments are used by the Company to manage the price risk attributable to its expected oil and natural gas production, those derivative instruments have not been designated as accounting hedges under the accounting guidance. All of our derivatives are accounted for as mark-to-market activities. Under ASC Topic 815, “Derivatives and Hedging,” these instruments are recorded on the consolidated balance sheets at fair value as either short term or long-term assets or liabilities based on their anticipated settlement date. The Company nets derivative assets and liabilities by commodity for counterparties where a legal right to such offset exists. Changes in the derivatives’ fair values are recognized in current earnings since the Company has elected not to designate its current derivative contracts as cash flow hedges for accounting purposes.

The Company has recognized certain conversion features within its Second Lien Term Loan as embedded derivatives that have been bifurcated from the Second Lien Term Loan, as defined in Note 11 - Long-Term Debt to our consolidated financial statements in Item 16 of this Annual Report on Form 10-K and accounted for separately from the debt.

The Company has recognized our crude oil sales agreement with ARM no longer meets the criteria for the “normal purchase normal sales” exception under ASC 815, “Derivatives and Hedging”, due to the Company not meeting the minimum quantities deliverable under the contract and the net settlement criteria being met. As a result, an embedded derivative exists as it is no longer probable the contract will only result in physical deliveries of crude oil and may not settle. See Note 9 - Derivatives to our consolidated financial statements in Item 16 of this Annual Report on Form 10-K.

Revenue Recognition

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.
 

54







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.

Income Taxes

The Company uses the asset and liability method in accounting for income taxes. Deferred tax assets and liabilities are recognized for temporary differences between financial statement carrying amounts and the tax bases of assets and liabilities and are measured using the tax rates expected to be in effect when the differences reverse. Deferred tax assets are also recognized for operating loss and tax credit carry forwards. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the results of operations in the period that includes the enactment date. A valuation allowance is used to reduce deferred tax assets when uncertainty exists regarding their realization.

The Company recognizes its tax benefits only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely to be realized upon settlement. A liability for “unrecognized tax benefits” is recorded for any tax benefits claimed that do not meet these recognition and measurement standards. As of December 31, 2019 and 2018, the Company has determined that no liability is required to be recognized.

The Company’s policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense. No interest or penalties were required to be accrued at December 31, 2019 and 2018. Further, the Company does not expect that the total amount of unrecognized tax benefits will significantly increase or decrease during the next 12 months.

Recently Issued Accounting Pronouncements

For a discussion of recently adopted accounting standards and recent accounting standards not yet adopted, see “Note 3 - Basis of Presentation and Summary of Significant Accounting Policies” to our Consolidated Financial Statements in Item 16 of this Annual Report.

Item 7A.    Quantitative and Qualitative Disclosures About Market Risk
 
We are exposed to various market risks, including risks relating to changes in commodity prices, interest rate risk, customer credit risk and currency exchange rate risk, as discussed below.
 
Commodity Price Risk
 
Our major market risk exposure is in the pricing applicable to our oil and natural gas production. Market risk refers to the risk of loss from adverse changes in oil and natural gas prices. Realized pricing is primarily driven by the prevailing domestic price for crude oil and spot prices applicable to the region in which we produce natural gas. Historically, prices received for oil and natural gas production have been volatile and unpredictable. We expect pricing volatility to continue. The prices that we receive depend on external factors beyond our control.
 
During the year ended December 31, 2019, our realized prices for liquids (crude oil and NGLs) continued to show significant improvement over the lows realized in January 2019, due largely to the rise in market index prices since then. Our realized oil price also continued to benefit from sales under the Company’s Crude Oil Gathering Agreement with SCM, which commenced March 1, 2019. Conversely, our realized natural gas prices saw a sharp decline beginning in April 2019 due primarily to the oversupply in the market combined with industry-wide infrastructure constraints in our operating region.

During the year ended December 31, 2019, the oil prices we received ranged from a low of $37.33 per barrel to a high of $61.66 per barrel. The NGL prices we received in the period ranged from a low of $0.24 per gallon to a high of $0.56 per gallon. Natural gas prices during the period ranged from a low of $0.36 per MCF to a high of $1.97 per MCF.
 
A significant decline in the prices of oil or natural gas could have a material adverse effect on our financial condition and results of operations. In order to reduce commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil and natural gas, we may enter into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production.


55







The price of oil and natural gas has fallen significantly since the beginning of 2020, due in part to OPEC negotiations as well as concerns about the COVID-19 pandemic and its impact on the worldwide economy and global demand for oil and gas. The resulting precipitous decline in oil and gas pricing experienced during March 2020 and through the date of this Annual Report, if prolonged, or a further deterioration of the market price for oil and natural gas will further negatively impact our ability to continue to operate as a going concern.

We have an active hedging program to mitigate risk regarding our cash flow and to protect returns from our development activity in the event of decreases in the prices received for our production; however, hedging arrangements may expose us to risk of significant financial loss in some circumstances and may limit the benefit we would receive from increases in the prices for oil, natural gas and NGLs.

The derivative contracts may include fixed-for-floating price swaps (whereby, on the settlement date, the Company will receive or pay an amount based on the difference between a pre-determined fixed price and a variable market price for a notional quantity of production), put options (whereby the Company pays a cash premium in order to establish a fixed floor price for a notional quantity of production and, on the settlement date, receives the excess, if any, of the fixed price floor over a variable market price), and costless collars (whereby, on the settlement date, the Company receives the excess, if any, of a variable market price over a fixed floor price up to a fixed ceiling price for a notional quantity of production). We do not enter into derivatives for trading or other speculative purposes. We believe that our use of derivatives and related hedging activities reduces our exposure to commodity price rate risk and does not expose us to material credit risk or any other material market risk.

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. The amount we can borrow is subject to periodic redetermination based in part on changing expectations of future prices. Lower prices may also reduce the amount of oil and natural gas that we can economically produce. We currently sell all of our oil and natural gas production under price sensitive or market price contracts.
 
Interest Rate Risk
 
As of December 31, 2019, we had $115.0 million outstanding under our Revolving Credit Agreement with an applicable margin that varies from 2.75% to 3.25%. In addition, holders of our shares of Preferred Stock are entitled to receive cumulative preferential dividends, payable and compounded quarterly in arrears at an average annual rate of 9.07% of the Stated Value until maturity.

Currently, we do not have any interest rate derivative contracts in place. If we incur significant debt with a risk of fluctuating interest rates in the future, we may enter into interest rate derivative contracts on a portion of our then outstanding debt to mitigate the risk of fluctuating interest rates.

Customer Credit Risk
 
Our principal exposure to credit risk is through receivables from the sale of our oil and natural gas production of approximately $9.1 million at December 31, 2019, and through actual and accrued receivables from our joint interest partners of approximately $9.5 million at December 31, 2019. We are subject to credit risk due to the concentration of our oil and natural gas receivables with our most significant customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. For the year ended December 31, 2019, sales to three customers, ARM Energy Management, LLC, Texican Crude & Hydrocarbon, LLC, and Lucid Energy Delaware, LLC, accounted for approximately, 68%, 19% and 12% of our revenue, respectively.
 
Currency Exchange Rate Risk
 
We do not have any foreign sales and we accept payment for our commodity sales only in U.S. dollars. We are, therefore, not exposed to foreign currency exchange rate risk on these sales.
 
Item 8.        Financial Statements and Supplementary Data

Our financial statements appear immediately after the signature page of this Annual Report and are incorporated herein by reference. See “Index to Financial Statements” included in this Annual Report.


56







Item 9.        Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A.    Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the Exchange Act. Internal control over financial reporting is an integral component of the Company’s disclosure controls and procedures. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon their evaluation, our Chief Executive Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2019.

Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Exchange Act). Our internal control structure is designed to provide reasonable assurance to our management and board of directors regarding the reliability of our financial reporting and the preparation and fairness of our financial statement preparation in accordance with U.S. generally accepted accounting principles.

Our management, with the participation of our Chief Executive Officer assessed the effectiveness of our internal control over financial reporting, as of December 31, 2019, based on the criteria for effective internal control over financial reporting established in “Internal Control - Integrated Framework (2013)” which is issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment and those criteria, our management determined that our internal control over financial reporting was effective as of December 31, 2019.

Changes in Internal Control Over Financial Reporting
 
There was no change in our internal control over financial reporting during the year ended December 31, 2019, that materially affected or is reasonably likely to materially affect our internal control over financial reporting.

Item 9B.     Other Information

None.

57







PART III

Item 10.     Directors, Executive Officers and Corporate Governance

The following table sets forth the names, ages and positions of the persons who are our directors and executive officers as of April 30, 2020:
Name
 
Age
 
Position
Michael G. Long
 
67

 
Chairman of the Board of Directors
Nuno Brandolini
 
66

 
Director
John Johanning
 
34

 
Director
Markus Specks
 
35

 
Director
Nicholas Steinsberger
 
56

 
Director
Joseph C. Daches
 
53

 
Chief Executive Officer, President and Chief Financial Officer

Directors hold office for a period of one year from their election at the annual meeting of stockholders and until a particular director’s successor is duly elected and qualified. Officers are elected by, and serve at the discretion of, our Board of Directors (the “Board” or the “Board of Directors”). None of the above individuals has any family relationship with any other individual listed above.

Below are summaries of the background and business experience, attributes, qualifications and skills of the current directors and executive officers of the Company:

Michael G. Long: Chairman of the Board of Directors.  Mr. Long joined our Board on April 10, 2018 and has served as Chairman of the Board since March 2020. Mr. Long is an experienced financial executive with over 35 years of experience in oil and gas related management, corporate finance, capital markets, risk management and strategic planning activities for both private and public oil and gas companies.  Mr. Long previously served as the Executive Vice President and Chief Financial Officer for Sanchez Energy Corporation and privately held Sanchez Oil and Gas Corporation and its affiliates.  Mr. Long also held the positions of EVP and CFO of Edge Petroleum Corporation and Vice President of Finance for W&T Offshore.

Director Qualifications:

Leadership Experience - Served as Executive Vice President and Chief Financial Officer of Sanchez Energy Corporation, Executive Vice President and Chief Financial Officer of Edge Petroleum Corporation, and Vice President of Finance for W&T Offshore.

Industry Experience - Extensive experience in corporate finance, capital markets, risk management and strategic planning activities.

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

Director Qualifications:

Leadership Experience - Executive positions with several private equity firms, and Board position with Cheniere Energy, Inc.

Industry Experience - Serves on the Board of Cheniere Energy, Inc., as well as has personal investments in the oil and gas industry.

58








John Johanning: Director.  Mr. Johanning joined our Board in March 2018. Mr. Johanning was designated as a director by the Värde Parties pursuant to a Securities Purchase Agreement dated January 30, 2018, and he was appointed to our Board in March 2018. Mr. Johanning is the Technical Director of Värde Partners, Inc.’s (“Värde”) energy business. Mr. Johanning joined Värde in May 2017 and presides over the Petroleum Engineering and Geoscience aspects of Värde’s investments in energy. Mr. Johanning is involved in the performance of current Värde investments across active onshore US basins as well as new business decisions in both opportunity screening and asset and company valuations. Prior to joining Värde, from January 2014 until May 2017, Mr. Johanning was a Vice President at Evercore Partners (“Evercore”) in Houston, Texas, where he was influential in numerous transactions totaling over $10 billion in transaction value. While at Evercore, Mr. Johanning advised numerous energy companies and financial sponsors on value-maximizing transactions. Mr. Johanning’s advisory mandates ranged over a variety of different transaction types including acquisitions and divestitures of assets, corporate mergers, and capital raises. Mr. Johanning also worked across all oilfield sectors, gaining transactional experience in the upstream, midstream, downstream and oilfield service sectors of the business. Mr. Johanning began his career as a Reservoir Engineer at BP from 2008 to 2014. Based in Houston, he developed oil and gas assets across several US Basins, including the Permian of West Texas and Southeast New Mexico and the Texas Gulf Coast Basin, among others. While on the South Texas Reservoir Management team, Mr. Johanning was responsible for the resource appraisal of a 400,000+ gross acre Eagle Ford Shale position that was deeply rooted in geological and well completion data. While at BP, Mr. Johanning gained a detailed technical understanding of oil and gas assets through the various facets of the business, including Production Engineering, Reservoir Engineering, Drilling and Completions, Geology and Geophysics, as well as Land, Legal and Finance functions. Mr. Johanning graduated from The University of Texas in at Austin in 2008 with a B.S. in Petroleum Engineering.

Director Qualifications:

Leadership Experience - Served as Vice President at Evercore Partners and currently presides over the Petroleum Engineering and Geoscience aspects of Värde Partners, Inc. as the Technical Director.

Industry Experience - Possesses particular knowledge and experience in the operations of oil and gas companies and has transactional experience in the upstream, midstream, downstream and oil field service sectors of the business, including acquisitions and divestitures of assets, corporate mergers, and capital raises.

Markus Specks: Director.  Mr. Specks joined our Board in March 2018. Mr. Specks was designated as a director by the Värde Parties pursuant to a Securities Purchase Agreement dated January 30, 2018, and he was appointed to our Board in March 2018. Mr. Specks is a Managing Director of Värde Partners, Inc. and Head of the firm’s Houston office. Mr. Specks leads Värde’s energy business and has experience managing credit, equity, and structured asset-level investments across the energy sector. He serves on Värde’s Investment Committee as well as several boards of private energy companies. Prior to joining Värde in 2008, Mr. Specks worked in investment banking at Lazard, focusing on middle-market M&A advisory. Mr. Specks holds a B.A. in Government from Lawrence University in Wisconsin.

Director Qualifications:

Leadership Experience - Managing Director of Värde Partners, Inc. and Head of the firm’s Houston office.

Industry Experience - Possesses particular knowledge and experience in developing companies and capital markets, particularly with oil and gas companies.

Nicholas Steinsberger: Director.  Mr. Steinsberger joined our Board on May 3, 2018. He is currently COO and Managing Director of ValPoint Operating, a small private equity backed company working in western Oklahoma. Mr. Steinsberger is a highly experienced petroleum engineer and global expert in shale drilling and completions who pioneered the use of slick water fracing. He began his career with Mitchell Energy and served as the Completion Manager for Mitchell from 1995 to 2002, where he piloted the Company’s fracking technique and developed the slick water frac, pioneering the current oil and gas shale boom. Mr. Steinsberger then served as the Completion Manager for Devon Energy after Devon’s acquisition of Mitchell Energy. In 2005, he founded Steinsberger Tight Gas Consulting, where he has drilled and completed wells in the Barnett, Fayetteville, Woodford, Wolfcamp, Utica, Bakken and Marcellus Shales. Mr. Steinsberger is regarded as an expert in the field of unconventional well completion and is responsible for the drilling and completion of over 1,000 wells in his career. He holds a B.S. in Petroleum Engineering from the University of Texas.


59







Director Qualifications:

Leadership Experience - COO and Managing Director of ValPoint Operating; Founder, President and CEO of Steinsberger Tight Gas Consulting.

Industry Experience - Possesses significant knowledge regarding technical aspects of drilling and completions and is also very active in the oil and gas industry.

Joseph C. Daches: Chief Executive Officer.  Mr. Daches was appointed Chief Executive Officer of the Company on November 13, 2019. He was Chief Financial Officer and Treasurer of Lilis since January 23, 2017, and President of Lilis since August 16, 2018. Mr. Daches has more than 25 years’ experience in management and working with boards of directors, banks and attorneys, primarily within the energy industry. Mr. Daches has helped guide several oil and gas companies through financial strategy activities, capital raises, and both public and private offerings. Mr. Daches possesses significant business experience and knowledge related to the oil and gas industry, including A&D transactions, oil and gas reporting, SEC reporting, corporate governance and compliance, budgeting and business valuations. Prior to joining the Company, Mr. Daches held the position of CFO at MHR, where he concluded his tenure by successfully guiding MHR through a restructuring and upon emergence was appointed Co-CEO by the new board of directors. Prior to joining MHR, Mr. Daches served as Executive Vice President and Chief Accounting Officer of Energy & Exploration Partners, Inc. since September 2012 and as a director of that company since April 2013. He previously served as a partner and Managing Director of the Willis Consulting Group, LLC, from January 2012 to September 2012. From October 2003 to December 2011, Mr. Daches served as the Director of E&P Advisory Services at Sirius Solutions, LLC, where he was primarily responsible for financial reporting, technical and oil and gas accounting, and the overall management of the E&P advisory services practice. Mr. Daches earned a Bachelor of Science in Accounting from Wilkes University in Pennsylvania, and he is a certified public accountant in good standing with the Texas State Board of Public Accountancy.

Corporate Governance

The Board of Directors and Committees

Our Board conducts its business through meetings and through its committees. Our Board held eight meetings in 2019 and took action by unanimous written consent on six occasions. Each director attended at least 75% of (i) the meetings of the Board held after such director’s appointment and (ii) the meetings of the committees on which such director served, after being appointed to such committee. Our policy regarding directors’ attendance at the annual meetings of stockholders is that all directors are expected to attend, absent extenuating circumstances. In 2019, we had two directors attend our Annual Meeting.

Board Leadership Structure

The Board selected Mr. Long to hold the position of Chairman of the Board on March 12, 2020. Mr. Long’s experience in the industry and various executive leadership roles has afforded him intimate knowledge of the issues, challenges and opportunities facing the Company.

The Board’s Role in Risk Oversight

It is management’s responsibility to assess and manage risk and bring to the Board’s attention any material risks to our Company. While our management team is responsible for assessing and managing material risks, our Board and Board committees generally oversee risk management. The Board also has oversight responsibility for our risk policies and processes relating to the financial statements and financial reporting processes and the guidelines, policies and processes for mitigating those risks.

Corporate Governance Guidelines

Our Board has developed and adopted Corporate Governance Guidelines to establish a common set of expectations to assist our Board and its committees in performing their duties. The Corporate Governance Guidelines provide guidance to our directors on various subjects, including our directors’ responsibilities, director qualification standards, director compensation, and access to management and independent advisors. A copy of our Corporate Governance Guidelines is available on our website at www.lilisenergy.com under “Investor Relations - Corporate Governance.”

Committees of the Board of Directors

Pursuant to our bylaws, our Board is permitted to establish committees from time to time as it deems appropriate. To facilitate independent director review and to make the most effective use of our directors’ time and capabilities, our Board has

60







established an Audit Committee and a Special Committee. The membership and principal functions of these committees are described below.

In connection with the resignation of certain directors, effective as of April 15, 2020, our Board does not have a standing Nominating and Corporate Governance Committee or a standing Compensation Committee.

Audit Committee

Currently, our Audit Committee consists of Mr. Long, who is the chairman of the Audit Committee, and Mr. Brandolini. Our Board of Directors determined that each of Mr. Long and Mr. Brandolini are independent as required by NYSE American for audit committee members. In addition, our Board of Directors determined that Mr. Long meets the requisite SEC criteria to qualify as an audit committee financial expert. The Audit Committee met five times during the year ended December 31, 2019, and acted by written consent once.

The Audit Committee selects, compensates and evaluates an independent public accounting firm to act as the Company’s independent auditors, as well as any other necessary registered public accounting firms. In addition, the Audit Committee reviews all critical accounting policies and practices to be used in the Company’s audit and reviews all alternative treatments of financial information within generally accepted accounting principles. The Audit Committee also reviews with management and our independent auditors any major issues regarding accounting principles and financial statement presentation and any significant financial reporting issues and judgments. Under its charter, the Audit Committee monitors compliance with our Code of Business Conduct.

The Audit Committee is governed by a written charter that is reviewed, and amended if necessary, on an annual basis. A copy of the charter is available on our website at www.lilisenergy.com under “Investor Relations - Corporate Governance.”

Consideration and Determination of Executive and Director Compensation

Our Board does not currently have a standing Compensation Committee. Due to the reduced size of the Board following the resignations of three directors, effective as of April 15, 2020, the Board determined that it would be appropriate for the Compensation Committee to be dissolved and for the responsibilities of the Board’s former Compensation Committee to be assigned to its directors that meet the independence standards of the NYSE American LLC. As such, Mr. Long, Mr. Brandolini, Mr. Johanning and Mr. Specks, as the four independent members of the Board, participate in the consideration of officer and director compensation.

The independent members of the Board review, approve and modify our executive compensation program, plans and awards provided to our directors, executive officers and key employees. The independent members of the Board also review and approve short-term and long-term incentive plans and other stock or stock-based incentive plans. In addition, the independent members of the Board review our compensation and benefit philosophy, plans and programs on an as-needed basis. In reviewing our compensation and benefits policies, the independent members of the Board may consider the recruitment, development, promotion, retention and compensation of our executive and senior officers; trends in management compensation; and any other factors that it deems appropriate.

The independent members of the Board, at least annually, review and approve the corporate goals and objectives applicable to the compensation of the Company’s CEO, evaluates the CEO’s performance in light of those goals and objectives, and determine and approve the CEO’s compensation level based on the evaluation. The CEO is not permitted to be present during any Board deliberations or voting with respect to his compensation. The independent members of the Board also, at least annually, review and approve the annual base salaries and incentive opportunities of the executive officers (other than the CEO) and review and approve all other incentive awards and opportunities, including both cash-based and equity based awards and opportunities.
Consideration of Director Nominees

Our Board does not currently have a standing Nominating and Corporate Governance Committee. Due to the reduced size of the Board following the resignations of three directors, effective as of April 15, 2020, the Board determined that it would be appropriate for the Nominating and Corporate Governance Committee to be dissolved and for the responsibilities of the Board’s former Nominating and Corporate Governance Committee to be assigned to its directors that meet the independence standards of the NYSE American LLC. As such, Mr. Long, Mr. Brandolini, Mr. Johanning and Mr. Specks, as the four independent members of the Board, participate in the consideration of director nominations.

61








The primary responsibilities of the independent members of the Board with respect to director nominations include identifying, evaluating and recommending, for the approval of the entire Board, potential candidates to become members of the Board, recommending membership on standing committees of the Board, developing and recommending to the entire Board corporate governance principles and practices for our company and assisting in the implementation of such policies.

Special Committee

In November 2019, our board of directors formed a committee of independent directors (the “Special Committee”) tasked with reviewing and evaluating strategic alternatives that may enhance the value of the Company, including alternatives that may be available to identify and access further sources of liquidity.

Communications with the Board of Directors

Stockholders may communicate with our Board or any of the Company’s directors by sending written communications addressed to the Board or any of the directors, at Lilis Energy, Inc., 201 Main Street, Suite 700, Fort Worth, TX 76102, Attention: General Counsel. All communications are compiled by the General Counsel and forwarded to the Board or the individual director(s) accordingly.

Code of Ethics and Corporate Governance Guidelines

Our Board has adopted a Code of Business Conduct that applies to all of our officers and employees, including our chief executive officer, chief financial officer or controller, and persons performing similar functions. Our Code of Business Conduct codifies the business and ethical principles that govern all aspects of our business.

Our Board has developed and adopted Corporate Governance Guidelines to establish a common set of expectations to assist the Board, and its committees in performing their duties. The Corporate Governance Guidelines provide guidance to our directors on various subjects, including our director’s responsibilities, director qualification standards, director compensation, and access to management and independent advisors.

A copy of our Code of Business Conduct and Corporate Governance Guidelines are available on our website at www.lilisenergy.com under “Investor Relations - Corporate Governance.” We will undertake to provide a copy of our Code of Business Conduct and Corporate Governance Guidelines to any person, at no charge, upon a written request. All written requests should be directed to: Lilis Energy, Inc., 201 Main Street, Suite 700, Fort Worth, TX 76102, Attention: General Counsel. If any substantive amendments are made to our Code of Business Conduct, or if any waiver (including any implicit waiver) is granted from any provision of the Code of Business Conduct to our chief executive officer, chief financial officer or controller, we will disclose the nature of such amendment or waiver on our website at www.lilisenergy.com under “Investor Relations - Corporate Governance” or, if required, in a Current Report on Form 8-K.

Delinquent Section 16(a) Reports

Our executive officers and directors and persons who own more than 10% of our common stock are required to file reports with the SEC, disclosing the amount and nature of their beneficial ownership in our common stock, as well as changes in that ownership. Based solely on our review of reports and written representations that we have received, we believe that all required reports were timely filed during 2019, except for the following:

Mark Christensen filed one Form 4, reporting one transaction, subsequent to the time prescribed by Section 16(a) of the Exchange Act.

Joseph C. Daches filed one Form 4, reporting three transactions, subsequent to the time prescribed by Section 16(a) of the Exchange Act.


62







Item 11.     Executive Compensation

Executive Compensation for Fiscal Year 2019

We are currently considered a “smaller reporting company” for purposes of the SEC’s executive compensation and other disclosure rules. In accordance with such rules, we are required to provide a Summary Compensation Table and an Outstanding Equity Awards at Fiscal Year End Table, as well as limited narrative disclosures.

The compensation earned by our executive officers for the year ended December 31, 2019, consisted of base salary, short-term incentive compensation consisting of cash bonus payments and long-term incentive compensation consisting of awards of stock grants.

Summary Compensation Table

The table below sets forth compensation paid to our chief executive officer, chief financial officer and our other most highly compensated executive officer during the fiscal years ended December 31, 2019 and 2018, which we refer to as our named executive officers (“NEOs”) for the years ended December 31, 2019 and 2018.
Name and Principal Position
Year
Salary
($)
(1)
Bonus
($)
(2)
Stock
Awards
($)
(3)
Option
Awards
($)
All Other
Compensation
($)
(4)
Total
($)
Joseph C. Daches(5)
2019
450,000

800,000

1,194,000


38,387

2,482,387

(Chief Executive Officer, President and Chief Financial Officer)
2018
420,513

600,000



43,883

1,064,396

Ronald D. Ormand(6)
2019
239,743

800,000

1,592,000


1,034,730

3,666,473

(Former Chief Executive Officer)
2018
500,000

1,250,000



24,326

1,750,000

James W. Denny, III(7)
2019
199,993

200,000

298,500

 
227,515

926,008

(Executive Vice President, Operations)
2018
255,458

100,000

876,000


23,271

1,254,729

(1) 
The base salary amounts in this column represent actual base compensation paid or earned through the end of the applicable year.
(2) 
The amounts in this column include annual bonuses paid for the applicable year.
(3) 
The amounts in this column represent the aggregate grant date fair value of stock awards granted during the applicable year. The grant date fair values for restricted stock awards were computed in accordance with FASB ASC Topic 718. The amounts reported in this column reflect the accounting cost for the stock awards and do not necessarily correspond to the actual economic value that may be received for the stock awards.
(4) 
For 2019, this amount includes $8,682 and $25,738 paid for reimbursement of health insurance premiums to Mr. Ormand and Mr. Daches, respectively. The amount also includes $1,026,048 for severance and COBRA for Mr. Ormand. This also includes 401K matching for Mr. Daches in the amount of $10,153 for 2018 and $10,375 in 2019, and Mr. Denny in the amount of $5,305 in 2018 and $5,221 in 2019.
(5) 
On November 13, 2019, Mr. Daches was appointed Chief Executive Officer. He has been Chief Financial Officer since January 23, 2017, and President since August 16, 2018.
(6) 
On June 6, 2019, Mr. Ormand resigned as Chief Executive Officer and as Executive Chairman of the Board.
(7) 
On June 28, 2019, Mr. Denny ceased serving as the Executive Vice President, Operations.


63







Outstanding Equity Awards at Fiscal Year-End
 
 
Option Awards
 
Stock Awards
Name
 
Number of
Securities
Underlying
Unexercised
Options (#)
Exercisable
 
Number of
Securities
Underlying
Unexercised
Options (#)
Unexercisable
 
Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)
 
Option
Exercise
Price
($)
 
Option
Expiration
Date
 
Number of
Shares or
Units of
Stock That
Have Not
Vested
(#)
 
Market Value
of Shares or
Units of Stock
That Have Not
Vested
($)
(1)
 
Market or Payout Value of Unearned Shares, Units or Other Rights That have Not Vested
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Joseph C. Daches
 
750,000

 

 

 
2.98

 
12/15/2026

 
396,000

 
150,480

 

Ronald D. Ormand(2)
 
250,000

 

 

 
2.98

 
12/15/2026

 

 

 

James W. Denny, III(3)
 

 

 

 

 

 

 

 


Vesting of options and stock awards reflected in this table is subject to continuous service with our Company, except that unvested awards may vest upon termination by us without cause, termination by the officer for good reason, or termination due to the officer’s disability or death (in each case as set forth in the applicable award agreement or employment agreement).

(1) 
The market value of the stock awards is based on the closing price per share of our common stock on the NYSE American on December 31, 2019, which was $0.38.

(2) 
Mr. Ormand held 693,000 shares of unvested restricted stock as of his retirement, which vesting was accelerated upon his retirement on June 5, 2019.

(3) 
Mr. Denny forfeited 165,000 unvested shares of restricted common stock upon his separation from the Company on June 28, 2019.

Employment Agreements and Other Compensation Arrangements

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

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

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

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

2016 Omnibus Incentive Plan

Background

Our 2016 Plan was approved by our Board effective April 20, 2016 and approved by our stockholders at the Company’s 2016 annual meeting on May 23, 2016. Our 2016 Plan replaced our 2012 EIP.


64







The purposes of our 2016 Plan are to create incentives that are designed to motivate eligible directors, officers, employees and consultants to put forth maximum effort toward our success and growth, and to enable us to attract and retain experienced individuals who by their position, ability and diligence are able to make important contributions to our success.

On a go forward basis, the Company intends to base compensation on certain performance matrices relating to employees positions or roles and standards utilized by its peers in the industry. By using measurable goals, the Company can more easily validate award increases based on employee and Company performance combined and assure that the Company remains competitive.

Eligibility

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

Administration

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

Number of Authorized Shares

When initially approved by our stockholders, 50,000,000 shares of our common stock were made available for issuance under our 2016 Plan. As a result of our 1-for-10 reverse stock split, which took effect on June 23, 2016, the number of shares available for issuance under our 2016 Plan was automatically reduced to 5,000,000. On August 25, 2016, our Board approved an amendment to our 2016 Plan to increase the maximum number of shares that may be issued from 5,000,000 to 10,000,000, and our stockholders approved that amendment at a special meeting on November 3, 2016. On May 15, 2017, our Board approved a second amendment to the 2016 Plan to increase the maximum number of shares of our common stock that may be issued under the 2016 Plan from 10,000,000 to 13,000,000, and our stockholders approved that amendment at the 2017 Annual Meeting. In 2018, our Board and our stockholders approved a third amendment to the 2016 Plan to increase the maximum number of shares of our common stock that may be issued under the 2016 Plan from 13,000,000 to 18,000,000.

Up to 18,000,000 shares may be granted as tax-qualified incentive stock options under our 2016 Plan. The shares issuable under our 2016 Plan consist of authorized and unissued shares, treasury shares or shares purchased on the open market or otherwise.

If any award is canceled, terminates, expires or lapses for any reason prior to the issuance of shares or if shares are issued under our 2016 Plan and thereafter are forfeited to us, the shares subject to those awards and the forfeited shares will not count against the aggregate number of shares available for grant under the plan. In addition, the following items will not count against the aggregate number of shares available for grant under our 2016 Plan: (1) the payment in cash of dividends or dividend equivalents under any outstanding award, (2) any award that is settled in cash rather than by issuance of shares, (3) shares surrendered or tendered in payment of the option price or purchase price of an award or any taxes required to be withheld in respect of an award or (4) awards granted in assumption of or in substitution for awards previously granted by an acquired company.

Limits on Awards to Nonemployee Directors

The maximum number of shares subject to awards under our 2016 Plan granted during any calendar year to any nonemployee member of our Board, taken together with any cash fees paid to the director during the fiscal year, may not exceed $500,000 in total value (calculating the value of any such awards based on the grant date fair value of such awards for financial reporting purposes).

Types of Awards

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

65







No Repricing

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

Clawback

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

Transferability

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

Effect of Change in Control

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

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

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

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

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

Term, Termination and Amendment of 2016 Plan

Unless earlier terminated by our Board, our 2016 Plan will terminate, and no further awards may be granted, 10 years after the date on which it was initially approved by stockholders. Our Board may amend, suspend or terminate our 2016 Plan at any time, except that, if required by applicable law, regulation or stock exchange rule, stockholder approval will be required for any amendment. The amendment, suspension or termination of our 2016 Plan or the amendment of an outstanding award generally may not, without a participant’s consent, materially impair the participant’s rights under an outstanding award.


66







Equity Grants for Fiscal Year 2019

During the year ended December 31, 2019, we granted 3,684,372 shares of restricted common stock and 135,000 options to purchase shares of common stock to our employees and directors. Also, during 2019, 1,650 stock options and 257,730 shares of restricted stock previously issued and unvested were forfeited or canceled in connection with the termination of certain employees, the departure of certain directors and/or shares canceled to cover tax withholding on vested restricted shares. Options issued to employees and directors generally vest in equal installments over specified time periods during the service period or upon achievement of certain performance-based operating thresholds.

On February 14, 2019, Mr. Daches received a grant of restricted stock under our 2016 Plan covering 600,000 shares of our common stock. The restricted stock vests over two years, with 34% vesting on the date of the grant, 33% vesting on the first anniversary of the date of the grant, and 33% vesting on the second anniversary of the date of the grant, subject to continued service.

On February 14, 2019, Mr. Ormand received a grant of restricted stock under our 2016 Plan covering 800,000 shares of our common stock. The restricted stock vests over two years, with 34% vesting on the date of the grant, 33% vesting on the first anniversary of the date of the grant, and 33% vesting on the second anniversary of the date of the grant, subject to continued service. Mr. Ormand held 693,000 shares of unvested restricted stock as of his retirement, which vesting was accelerated upon his retirement on June 5, 2019.

On February 14, 2019, Mr. Denny received a grant of restricted stock under our 2016 Plan covering 150,000 shares of our common stock. The restricted stock vests over two years, with 34% vesting on the date of the grant, 33% vesting on the first anniversary of the date of the grant, and 33% vesting on the second anniversary of the date of the grant, subject to continued service. Mr. Denny forfeited 99,000 unvested shares of restricted common stock upon his separation from the Company on June 28, 2019.

Equity Grants for Fiscal Year 2018

During the year ended December 31, 2018, we granted 1,194,944 shares of restricted common stock and 352,500 options to purchase shares of common stock to our employees and directors. Also, during 2018, 1,601,045 stock options and 1,280,480 shares of restricted stock previously issued and unvested were forfeited or canceled in connection with the termination of certain employees, the departure of certain directors and/or shares canceled to cover tax withholding on vested restricted shares. Options issued to employees and directors generally vest in equal installments over specified time periods during the service period or upon achievement of certain performance-based operating thresholds.

On May 3, 2018, Mr. Denny received a grant of restricted stock under our 2016 Plan covering 200,000 shares of our common stock. The restricted stock vests over two years, with 34% vesting on the date of the grant, 33% vesting on the first anniversary of the date of the grant, and 33% vesting on the second anniversary of the date of the grant, subject to continued service. Mr. Denny forfeited 66,000 unvested shares of restricted common stock upon his separation from the Company on June 28, 2019.

Employment Agreements

Mr. Daches

On December 17, 2019, we entered into an employment agreement with Mr. Daches, effective as of January 1, 2020, in connection with his appointment as our Chief Executive Officer. The initial term of the agreement is scheduled to end on January 1, 2022, and the agreement will renew automatically for additional one-year periods beginning on January 1, 2022, unless either party gives notice of non-renewal at least 180 days before the end of the then-current term. This agreement replaces in its entirety Mr. Daches’ prior employment agreement with the Company.

Mr. Daches’ annual base salary under this agreement (which will be reviewed periodically by the Board for adjustments) will not be less than $515,000. Mr. Daches will also be eligible to receive bonuses and awards of equity and non-equity compensation and to participate in the annual and long-term compensation plans of the Company, in each case as determined by our Board. The target annual bonus for Mr. Daches set forth in his agreement is no less than 100% of base salary and restricted shares equal to 200% of base salary. In 2019, Mr. Daches received a $200,000 cash bonus for his appointment as Interim Chief Executive Officer. Under Mr. Daches’ prior employment agreement, he received an annual salary of $480,000 during 2019.



67







Mr. Ormand

On July 5, 2016, we entered into an employment agreement with Ronald D. Ormand, effective as of July 11, 2016. The initial term of the agreement was scheduled to end on December 31, 2017, and the agreement renewed automatically for additional one-year periods beginning on December 31, 2017, unless either party gave notice of non-renewal at least 180 days before the end of the then-current term.

Mr. Ormand’s base salary under his agreement (which was reviewed by the Board for adjustments) was $300,000 for the first year of the agreement, $350,000 for the second year of the agreement, and $400,000 for the third year of the agreement. Mr. Ormand was eligible to receive a cash bonus equal to a percentage of his base salary (ranging from 0% to 400%) depending on the level of achievement of certain BOE per day, EBITDAX and cash on hand performance measures. Mr. Ormand was also eligible to receive awards of equity and non-equity compensation and to participate in our annual and long-term incentive plans, in each case as determined by our Board in its discretion.

On June 6, 2019, Mr. Ormand retired as Chief Executive Officer and Executive Chairman of the Board. In connection with his retirement, Mr. Ormand entered into a separation agreement with the Company, pursuant to which he received $1,026,048 as separation payment.

Potential Payments Upon Termination or Change-In-Control

Mr. Daches

Under his employment agreement, upon a termination by the Company without cause or a termination by him for good reason, Mr. Daches will be entitled to a lump sum severance payment equal to 12 months of base salary and 12 months of COBRA premiums. Upon a termination by the Company without cause or a termination by Mr. Daches for good reason within 18 months after a change in control, he will be entitled to a lump sum severance payment equal to 24 months of base salary and 24 months of COBRA premiums. All severance payments under Mr. Daches’ employment agreement are subject to his execution of a release of claims against the Company.

Stock Options

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

Retirement and Other Benefits

All employees, including our named executive officers, may participate in our 401(k) retirement savings plan (“401(k) Plan”). Each employee may make before tax contributions in accordance with Internal Revenue Service limits. We provide this 401(k) Plan to help our employees save a portion of their cash compensation for retirement in a tax efficient manner. In prior years, we have made a matching contribution in an amount equal to 100% of the employee’s elective deferral contribution up to 4% of the employee’s annual compensation.

Compensation of Nonemployee Directors

The compensation of our non-employee directors is reviewed and approved by the Board. We use a combination of cash and stock-based incentive compensation to attract and retain qualified candidates to serve on our Board. In determining director compensation, we consider the significant amount of time the directors spend fulfilling their duties, as well as the competitive market for skilled directors.

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


68







Our Director Compensation Program is comprised of the following components:

Initial Grant:  Each nonemployee director receives 10,000 restricted shares of common stock on the first anniversary of the date of the director’s appointment, which would vest in three equal installments over a three-year period, (subject to the continued service of the director and certain accelerated vesting provisions);

Initial Option Award:  Each nonemployee director receives a one-time initial grant of 25,000 stock options, which would vest immediately, and 20,000 options that would vest in equal installments over a three-year period beginning on the first anniversary of the grant date;

Annual Stock Award:  Each nonemployee director would receive an annual stock award equal to $150,000 divided by the most recent per share closing price of the common stock prior to the date of each annual grant, payable on each anniversary of the date an independent director was initially appointed to our Board, and subject to certain accelerated vesting provisions;

Annual Fees: On a quarterly basis, beginning at the end of the first full quarter following the appointment of the nonemployee director to the Board, each director receives $15,000 in cash compensation;

Chairman and Committee Chairman Fees:  On a quarterly basis, beginning at the end of the first full quarter following the appointment of the nonemployee director to Chairman of the Board, Chairman of the Audit Committee, Chairman of the Compensation Committee, Chairman of the Reserves Committee, and Chairman of the Nominating and Governance Committee, the director receives $12,500, $6,250, $6,250, $6,250, and $2,500 respectively, in cash compensation; and

Committee Fees: On a quarterly basis, beginning at the end of the first full quarter following the appointment of the nonemployee director to the Audit Committee, the Compensation Committee, the Reserves Committee, and the Nominating and Governance Committee, the director receives $3,125, $2,500, $2,500, and $1,875, respectively, in cash compensation.

Our Board evaluates the fees and compensation paid to the directors for their service on our Board on an annual basis.

Effective as of April 15, 2020, the Board dissolved its Reserves Committee, Compensation Committee and Nominating and Corporate Governance Committee. With respect to such committees, we do not expect to pay any additional committee chairman fees or committee fees during 2020.

As previously disclosed, the Company has formed a Special Committee. On a quarterly basis, beginning at the end of the first full quarter following the appointment of the nonemployee director to Chairman of the Special Committee or member of the Special Committee, the director receives $6,250 and $3,125, respectively, in cash compensation.



69







2019 Director Compensation

In 2019, each non-employee director received compensation consistent with our Director Compensation Program, consisting of an annual stock award, with additional fees being paid to the chairman of the Audit Committee, the chairman of the Compensation Committee, the chairman of the Reserves Committee, and the chairman of the Nominating and Governance Committee. Each member who served on a committee received an additional fee in connection for service on such committee. The fees received by our directors are pro-rated based on the time of their service with the Company. Each non-employee director is reimbursed for reasonable out-of-pocket costs incurred to attend Board meetings.
Name
 
Fees Earned
or Paid in
Cash
Compensation
($)
 
Stock
Awards
($)
(1)
 
Option
Awards
($)
 
All Other
Compensation
($)
 
Total
($)
Michael G. Long(2)
 
95,000

 
121,700

 
97,650

 

 
314,350

Nuno Brandolini(3)
 
80,000

 
150,000

 

 

 
230,000

Mark Christensen(4)
 
60,000

 
150,000

 

 

 
210,000

R. Glenn Dawson(5)
 
103,750

 
150,000

 

 
276,875

 
530,625

John Johanning(6)
 
182,500

 

 

 

 
182,500

Ronald D. Ormand(7)
 
30,000

 

 

 

 
30,000

Markus Specks(8)
 
181,875

 

 

 

 
181,875

Nicholas Steinsberger(9)
 
55,000

 
124,200

 
97,650

 
185,000

 
461,850

David M. Wood(10)
 
81,875

 
163,310

 
97,650

 

 
342,835


(1) 
Represents restricted stock awards. Awards in this column are reported at grant date fair value in accordance with FASB ASC Topic 718. The amounts reported reflect the accounting cost for the awards and do not correspond to the actual economic value that may be received for the awards. On January 31, 2019, Mr. Brandolini, Mr. Christensen and Mr. Dawson were each granted 69,124 shares of restricted stock, Mr. Steinsberger was awarded 47,235 shares of restricted stock, Mr. Long was awarded 46,083 shares of restricted stock and Mr. Wood was awarded 161,681 shares of restricted stock. These awards all vested in full immediately. Mr. Long and Mr. Steinsberger also each received 10,000 shares of restricted stock that have a 3-year vesting, with the first vesting date being the first anniversary of the award.

(2) 
Mr. Long was appointed to the Board on April 10, 2018. In 2019, Mr. Long received a fee of $15,000 per quarter for his service as a Director, $6,250 per quarter for his service as Chairman of the Audit Committee, and $2,500 per quarter for his service as a member of the Compensation Committee. Mr. Long also received an annual stock award grant of $100,000, which at the grant date stock price of $2.17 per share resulted in 46,083 shares of the Company’s common stock. Mr. Long also received a non-qualified incentive stock award for 45,000 of the Company’s common stock that vests over three years.

(3) 
Mr. Brandolini was appointed to the Board on February 13, 2014. In 2019, Mr. Brandolini received a fee of $15,000 per quarter for his service as a Director, $2,500 per quarter for his service as Chairman of the Nominating and Corporate Governance Committee, and $2,500 per quarter for his service as a member of the Compensation Committee. Mr. Brandolini also received an annual stock award grant of $150,000, which at the grant date stock price of $2.17 per share resulted in 69,124 shares of the Company’s common stock.

(4) 
Mr. Christensen was appointed to the Board on September 6, 2017. In 2019, Mr. Christensen received a fee of $15,000 per quarter for his service as a Director. Mr. Christensen also received an annual stock award grant of $150,000, which at the grant date stock price of $2.17 per share resulted in 69,124 shares of the Company’s common stock. Effective as of April 15, 2020, Mr. Christensen resigned from the Board.

(5) 
Mr. Dawson was appointed to the Board on January 13, 2016. In 2019, Mr. Dawson received a fee of $15,000 per quarter for his service as a Director, $6,250 for his service as Chairman of the Compensation Committee, and $3,125 per quarter for his service as member of the Audit Committee. In 2019, Mr. Dawson received a quarterly fee of $60,000 per quarter on an interim basis for his service as Chairman of the Reserves Committee due to additional oversight responsibility requested by the Board (as described in the Amended and Restated Reserves Committee Charter) to be performed until requisite Company personnel is available to handle such responsibilities, which such fee for service as the Chairman of the Reserves Committee was approved by all members of the Board. Mr. Dawson also received an annual stock award grant of $150,000, which at the

70







grant date stock price of $2.17 per share resulted in 69,124 shares of the Company’s common stock. Effective as of April 15, 2020, Mr. Dawson resigned from the Board.

(6) 
Mr. Johanning was appointed to the Board on March 1, 2018. In 2019, Mr. Johanning received a fee of $15,000 per quarter for service as a Director and $2,500 per quarter for his service as a member of the Reserves Committee. In lieu of the prorated annual stock award equal to $150,000, Mr. Johanning elected to receive a cash payment of $112,500, which is equal to $150,000 prorated for Mr. Johanning joining the Board in March 2018. The quarterly fees were paid directly to Värde.

(7) 
Mr. Ormand became a nonemployee Director on the Board on June 6, 2019. Beginning with the third quarter of 2019, Mr. Ormand received a fee of $15,000 per quarter for his service as a Director. Effective as of April 15, 2020, Mr. Ormand resigned from the Board.

(8) 
Mr. Specks was appointed to the Board on March 1, 2018. In 2019, Mr. Specks received a fee of $15,000 per quarter for his service as a Director and $1,875 per quarter for his service as a member of the Nominating and Corporate Governance Committee. In lieu of the prorated annual stock award equal to $150,000, Mr. Specks elected to receive a cash payment of $112,500, which is equal to $150,000 prorated for Mr. Specks joining the Board in March 2018. The quarterly fees were paid directly to Värde.

(9) 
Mr. Steinsberger was appointed to the Board on May 3, 2018. In 2019, Mr. Steinsberger received $15,000 per quarter for his service as a Director and $2,500 per quarter for his service as a member of the Reserves Committee. For the first quarter of 2019, in lieu of his $15,000 cash payment for service as a Director, Mr. Steinsberger elected to receive a grant award of 6,912 shares of the Company’s common stock, which at the grant date stock price of $2.17 per share was equal to $15,000. Mr. Steinsberger also received an annual stock award grant of $87,500, which at the grant date stock price of $2.17 per share resulted in 40,323 shares of the Company’s common stock. Mr. Steinsberger also received a non-qualified incentive stock award for 45,000 of the Company’s common stock that vests over three years. Mr. Steinsberger also received $60,000 per quarter for consulting with the Company; see “Item 13. Certain Relationships and Related Transactions, and Director Independence - Related Party Transactions” below for more information.

(10) 
Mr. Wood was appointed to the Board on June 1, 2018 and resigned from the Board on March 12, 2020. Mr. Wood received a fee of $15,000 per quarter for his service as a Director, $1,875 for his service as a member on the Nominating Committee and $3,125 per quarter for his service as a member of the Audit Committee. Mr. Wood also received an annual stock award grant of $75,000, which at the grant date stock price of $2.17 per share resulted in 34,562 shares of the Company’s common stock. Mr. Wood received a grant award of 127,119 shares of the Company’s stock for his compensation as Chairman, which at the grant date stock price of $0.52 per share was equal to $66,101, as approved by the Board. Mr. Wood also received a non-qualified incentive stock award for 45,000 of the Company’s common stock that vests over three years. Effective as of March 13, 2020, Mr. Wood resigned from the Board.

Indemnification of Directors and Officers

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

Item 12.     Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
 
The following table sets forth certain information with respect to beneficial ownership of our common stock as of April 30, 2020 by each of our executive officers and directors and each person known to be the beneficial owner of 5% or more of the outstanding common stock.

This table is based upon the total number of shares outstanding as of April 30, 2020. Unless otherwise indicated, the persons and entities named in the table have sole voting and sole investment power with respect to the shares set forth opposite the stockholder’s name. Beneficial ownership is determined in accordance with Rule 13d-3 under the Exchange Act. In computing the number of shares beneficially owned by a person or a group and the percentage ownership of that person or group, shares of our common stock subject to options or warrants currently exercisable or exercisable within 60 days after April 30, 2020, are deemed outstanding by such person or group, but are not deemed outstanding for the purpose of computing the percentage ownership of any other person. All share amounts that appear in this report have been adjusted to reflect a 1-for-10 reverse stock split of our outstanding common stock effected on June 23, 2016. Unless otherwise indicated, the address of each stockholder listed in the table is c/o Lilis Energy, Inc., 201 Main Street, Suite 700, Fort Worth, Texas 76102.


71







Name and Address of Beneficial Owner
 
Lilis common
stock
Held Directly
 
Lilis common
stock
Acquirable
Within 60
Days
(1)
 
Total
Beneficially
Owned
 
Percent of
Class
Beneficially
Owned
Directors and Named Executive Officers
 
 
 
 
 
 
 
 
Joseph Daches, Chief Executive Officer, President, and Chief Financial Officer
 
1,149,560

 
750,000

 
1,899,560

 
1.7

Michael Long, Chairman of the Board
 
67,083

 
25,000

 
92,083

 
*
Nuno Brandolini, Director
 
704,709

 
45,000

 
749,709

 
*
John Johanning, Director
 

 

 

 
*
Ronald D. Ormand, Former Director (2)
 
4,829,064

 
295,000

 
5,124,064

 
4.5

Markus Specks, Director
 

 

 

 
*
Nicholas Steinsberger, Director
 
67,235

 
25,000

 
92,235

 
*
Directors and Officers as a Group (7 persons) (3)
 
6,817,651

 
1,140,000

 
7,957,651

 
7.0

 
 
 
 
 
 
 
 
 
5% Stockholders
 
 
 
 
 
 
 
 
Värde Partners, Inc.(5)
901 Marquette Avenue South
Suite 330,
Minneapolis, MN 55402
 
23,594,401

 
24,000,000 (4)

 
47,594,401

 
41.4


*
Represents beneficial ownership of less than 1% of the outstanding shares of common stock.

(1) 
Represents shares of common stock subject to options and warrants exercisable within 60 days.

(2) 
Consists of: (i) 2,706,792 shares of common stock held by Perugia Investments, LP (“Perugia”) and (ii) 2,122,272 shares of common stock held directly by Mr. Ormand. Mr. Ormand is manager of Perugia and has shared voting and dispositive power over the securities held by Perugia.

(3) 
The directors and officers as a group beneficially own a total of 7,957,651 shares of common stock, which represents 7.0% of our currently issued and outstanding common stock.

(4) 
Based on the Schedule 13D/A filed on March 8, 2019. This represents shares of common stock which may be issued pursuant to the conversion of the shares Series E Preferred Stock within 60 days as if such Series E Preferred Stock had been converted on the date of borrowing or issuance, as applicable.

(5)
Värde Partners, Inc. is the ultimate owner of the general partners (the “General Partners”), of each of The Värde Fund XI (Master), L.P., The Värde Fund XII (Master), L.P., The Värde Skyway Fund, L.P., The Värde Skyway Mini-Master Fund, L.P., Värde Investment Partners (Offshore) Master, L.P., The Värde Fund VI-A, L.P., Värde Investment Partners, L.P., and Värde Investment Partners (Offshore) Master, L.P. (the “Värde Entities”), or of the General Partners’ general partners or managing members. Mr. George Hicks and Mr. Ilfryn Carstairs are the co-chief executive officers of Värde Partners, Inc. As such, each of Värde Partners, Inc., Mr. Hicks and Mr. Carstairs may be deemed to have beneficial ownership of the shares owned by each of the Värde Entities. Each of Värde Partners, Inc., Mr. Hicks, and Mr. Carstairs disclaims beneficial ownership of the securities held indirectly through the Värde Entities except to the extent of their pecuniary interest therein, and this disclosure shall not be deemed an admission that any such reporting person is the beneficial owner for purposes of this Proxy Statement or for any other purpose.

To our knowledge, except as noted above, no person or entity is the beneficial owner of 5% or more of our common stock.


72







Equity Compensation Plan Information

The following table summarizes information regarding the number of shares of our common stock that are available for issuance under all of our existing equity compensation plans as of December 31, 2019:
໿
Plan Category
 
Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights
(a)
 
Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights
(b)
 
Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (excluding securities reflected in column (a))
(c)
Equity compensation plans approved by security holders
 
3,588,350
 
4.05
 
5,372,127
Equity compensation plans not approved by security holders
 

 

 

Total
 
3,588,350
 
4.05
 
5,372,127

For additional information regarding the Company’s benefit plans and share-based compensation expense, see Note 17 - Share Based and Other Compensation to our consolidated financial statements included in this Annual Report.

Item 13.    Certain Relationships and Related Transactions, and Director Independence

Related Party Transactions

We describe below transactions and series of similar transactions, since January 1, 2018, to which we were a party, in which:

The amounts involved exceeded or will exceed the lesser of $120,000 or one percent (1%) of our average total assets at year-end for the last two completed fiscal years; and

Any of our directors, executive officers, or holders of more than 5% of our capital stock, or any member of the immediate family of, or person sharing the household with, any of the foregoing persons, who had or will have a direct or indirect material interest.

Transactions with the Värde Parties

On January 30, 2018, we entered into a Securities Purchase Agreement with certain private funds affiliated with Värde Partners, Inc. (the “Series C Purchasers”), pursuant to which, on January 31, 2018, the Series C Purchasers purchased 100,000 shares of our newly created series of preferred stock of the Company, designated as “Series C 9.75% Convertible Participating Preferred Stock” (the “Series C Preferred Stock”), for a purchase price of $1,000 per share, or an aggregate of $100,000,000. Värde Partners, Inc. is the lead lender, and certain private funds affiliated with Värde Partners, Inc. are lenders, under the Company’s Second Lien Credit Agreement.

On October 10, 2018, we entered into a transaction agreement (the “2018 Transaction Agreement”) by and among the Company and the Värde Parties, pursuant to which we agreed to issue to the Värde Parties (i) an aggregate of 5,952,763 shares of the Company’s common stock, par value $0.0001 per share, which includes 5,802,763 shares of common stock at an exchange price of $5.00 per share of common stock plus an additional 150,000 shares of common stock, and (ii) 39,254 shares of a newly created series of preferred stock of the Company, designated as “Series D 8.25% Convertible Participating Preferred Stock” (the “Series D Preferred Stock”), as consideration for the reduction by approximately $56.3 million of the outstanding principal amount of the Second Lien Term Loan under the Second Lien Credit Agreement, together with accrued and unpaid interest and the make-whole amount thereon totaling approximately $11.9 million, and issue and sell to the Värde Parties 25,000 shares of a newly created subseries of the Company’s Series Preferred Stock, designated as “Series C-2 9.75% Convertible Participating Preferred Stock”, for a purchase price of $1,000 per share, or an aggregate of $25 million. Värde Partners, Inc. is the lead lender, and certain private funds affiliated with Värde Partners, Inc. are lenders, under the Company’s Second Lien Credit Agreement. For more

73







information about the 2018 Transaction Agreement, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Preferred Stock Issuance” under Item 7 of this Annual Report.

On March 5, 2019, we entered into the transaction agreement (the “2019 Transaction Agreement”) by and among the Company and the Värde Parties, pursuant to which we agreed to issue to the Värde Parties an aggregate of (i) 9,891,638 shares of the Company’s common stock, par value $0.0001 per share (the “Term Loan Exchanged Common Stock”), (ii) 60,000 shares of a newly created series of preferred stock of the Company, designated as “Series E 8.25% Convertible Participating Preferred Stock” (the “Series E Preferred Stock” or the “Exchanged Series E Shares”), and (iii) 55,000 shares of a newly created series of preferred stock of the Company, designated as “Series F 9.00% Participating Preferred Stock” (the “Series F Preferred Stock” or the “Exchanged Series F Shares”, as consideration for the termination of the Second Lien Credit Agreement (as defined in the 2019 Transaction Agreement) and the satisfaction in full, in lieu of repayment in full in cash, of $133.6 million pursuant to the Payoff Letter (as defined in the 2019 Transaction Agreement) and issue to the Värde Parties, as consideration for the amendment and restatement of the Second Amended and Restated Series C Certificate of Designation and the Amended and Restated Series D Certificate of Designation, 7,750,000 shares of the Common Stock.

Värde Partners, Inc. was the lead lender, and certain private funds affiliated with Värde Partners, Inc. were lenders, under the Company’s Second Lien Credit Agreement. Värde Partners, Inc. and its applicable affiliated funds beneficially own over 5% of our common stock. For more information about the 2018 Transaction Agreement, see “Note 14 Preferred Stock - Preferred Stock Issuance” to our consolidated financial statements included in this Annual Report.

On April 21, 2020, Värde Investment Partners, L.P., an affiliate of Värde Partners, Inc., became a lender under our Revolving Credit Agreement by acquiring, from a prior lender, loans and commitments under the Revolving Credit Agreement in the principal amount of approximately $25.7 million. The loans and commitments acquired by Värde Investment Partners, L.P. are subject to certain subordination provisions set forth in the Revolving Credit Agreement, as amended by the Fourteenth Amendment thereto dated April 21, 2020. For additional information regarding our Revolving Credit Agreement, as amended, see Note 11 - Long-Term Debt to our consolidated financial statements included in this Annual Report and “Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations - Revolving Credit Agreement” in Part II of this Annual Report.

VPD Acquisition

On February 28, 2018, pursuant to an agreement we entered into with VPD Texas, L.P. (“VPD”) dated that date, we acquired from VPD a 50% undivided leasehold interest in certain oil and gas properties and assets in Loving and Winkler Counties, Texas for a purchase price of approximately $10.5 million. VPD is affiliated with Värde Partners, Inc., which is the lead lender under the Second Lien Credit Agreement, and Värde Partners, Inc. and certain affiliated funds hold all of the issued and outstanding shares of Series C Preferred Stock. As such, Värde Partners, Inc. and its applicable affiliated funds beneficially own over 5% of our common stock as a result of their respective conversion rights under the Second Lien Credit Agreement and the Series C Preferred Stock.

Compensation of Directors

On August 1, 2019, Steinsberger Tight Gas Consulting LLC and the Company entered into an engagement letter effective as of June 1, 2019, under which the Steinsberger Tight Gas Consulting LLC provides consulting services involving all areas of operations to the Company for $60,000 per quarter. Mr. Steinsberger, who is a Director on our Board, is Managing Partner of Steinsberger Tight Gas Consulting LLC.

For more information on this and other Director compensation, see “Item 12. Executive Compensation - Compensation of Nonemployee Directors” above.

Employee Relationship

The Company employs Austin Brooks, who is the son-in law of Ronald Ormand, who was a Director on our Board until his resignation on April 15, 2020. In 2019, his total compensation, including salary, bonus and other benefits, totaled approximately $379,204. Our employment relationship with Mr. Brooks was entered into in 2018 in the ordinary course of business and has been conducted on an arm’s-length basis, and the compensation paid to Mr. Brooks is commensurate with that of his peers.


74







Conflict of Interest Disclosure

We have a corporate code of business conduct that requires disclosure of any conflicts of interests at least annually and upon awareness of any potential conflict of interest, such conflict will either be prohibited or the Company will adopt a mitigation plan to protect the Company’s interest.

Director Independence

Our Board follows the standards of independence established under the rules of the NYSE American, as well as our Corporate Governance Guidelines on Director Independence, in determining if directors are independent. The Board has determined that four of our current directors, Mr. Brandolini, Mr. Johanning, Mr. Specks, and Mr. Long, are “independent directors” under the NYSE American rules referenced above.

No independent director receives, or has received, any fees or compensation directly as an individual from us other than compensation received in his capacity as a director or indirectly through their respective companies, except as described above. There were no transactions, relationships or arrangements not otherwise disclosed that were considered by the Board in determining whether any of the directors were independent.

Item 14.     Principal Accounting Fees and Services

The following table sets forth fees billed by our principal accounting firm BDO USA, LLP for the years ended December 31, 2019 and 2018:
(In thousands)
 
Year Ended
December 31,
 
 
2019
 
2018
Audit Fees
 
$
738

 
$
1,032

Audit Related Fees
 
$

 
$

Tax Fees
 
$

 
$

All Other Fees
 
$

 
$


Audit Fees consist of the aggregate fees for professional services rendered for the audit of our annual financial statements and the reviews of the financial statements included in our Quarterly Reports on Forms 10-Q and for any other services that were normally provided by our auditors in connection with our statutory and regulatory filings or engagements.

Audit-Related Fees consist of the aggregate fees billed or reasonably expected to be billed for professional services rendered for assurance and related services that were reasonably related to the performance of the audit or review of our financial statements and were not otherwise included in Audit Fees.

Tax Fees consist of the aggregate fees billed for professional services rendered for tax consulting. Included in such Tax Fees were fees for consultancy, review, and advice related to our income tax provision and the appropriate presentation on our financial statements of the income tax related accounts.

All Other Fees consist of the aggregate fees billed for products and services provided by our auditors and not otherwise included in Audit Fees, Audit-Related Fees or Tax Fees.

Audit Committee Pre-Approval Policy

Consistent with SEC rules regarding auditor independence, our Audit Committee has the responsibility for appointing, approving the compensation of, and overseeing the work of our independent public accounting firm. Our independent registered public accounting firm may not be engaged to provide non-audit services that are prohibited by law or regulation to be provided by it, nor may our independent registered public accounting firm be engaged to provide any other non-audit service unless it is determined that the engagement of the principal accountant provides a business benefit resulting from its inherent knowledge of our Company while not impairing its independence. Our Audit Committee must pre-approve permissible non-audit services. During the year ended December 31, 2019, we had no non-audit services provided by our independent registered public accounting firm.


75










76







PART IV

Item 15. Exhibits, Financial Statement Schedules

a.
The following documents are filed as part of this Annual Report on Form 10-K or incorporated by reference:

(i)
The consolidated financial statements of Lilis Energy, Inc. are listed on the Index to this Form 10-K, page 79.

b.
The following exhibits are filed or furnished with this Annual Report on Form 10-K or incorporated by reference:

b)    Exhibits
2.1
2.2
2.3
2.4
3.1
3.2
3.3
3.4
3.5
3.6
3.7
3.8
3.9


77







4.1
4.2
4.3
4.4
4.5
4.6
4.7

78








79








80







101.INS*
XBRL Instance Document
101.SCH*
XBRL Taxonomy Extension Schema Document
101.CAL*
XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*
XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*
XBRL Taxonomy Extension Label Linkbase Document
101.PRE*
XBRL Taxonomy Extension Presentation Linkbase Document
*
Filed herewith.
Indicates management contract or compensatory plan.
+
To be filed by amendment.


81







c)    Financial Statement Schedules

Not applicable.

Item 16. Form 10-K Summary

None.


82







SIGNATURES
 
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 
LILIS ENERGY, INC.
 
 
 
Date: April 30, 2020

By:
/s/ Joseph C. Daches
 
 
Joseph C. Daches
 
 
Chief Executive Officer, President, and Chief Financial Officer
 
Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated.
Signature
 
Title
 
Date
 
 
 
 
 
/s/ Joseph C. Daches
 
Chief Executive Officer, President, and Chief Financial Officer
 
April 30, 2020
Joseph C. Daches
 
(Principal Executive Officer and Principal Financial and Accounting Officer)
 
 
 
 
 
 
 
/s/ Nuno Brandolini
 
Director
 
April 30, 2020
Nuno Brandolini
 
 
 
 
 
 
 
 
 
/s/ John Johanning
 
Director
 
April 30, 2020
John Johanning
 
 
 
 
 
 
 
 
 
/s/ Markus Specks
 
Director
 
April 30, 2020
Markus Specks
 
 
 
 
 
 
 
 
 
/s/ Michael G. Long
 
Director
 
April 30, 2020
Michael G. Long
 
 
 
 
 
 
 
 
 
/s/ Nicholas Steinsberger
 
Director
 
April 30, 2020
Nicholas Steinsberger
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


83







Index to Financial Statements




84







Report of Independent Registered Public Accounting Firm
 



Shareholders and Board of Directors
Lilis Energy, Inc.
Fort Worth, Texas

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Lilis Energy, Inc. (the “Company”) as of December 31, 2019 and 2018, the related consolidated statements of operations, changes in stockholders’ equity (deficit), and cash flows for each of the two years in the period ended December 31, 2019, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

Going Concern Uncertainty

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the consolidated financial statements, the Company has incurred significant losses, negative cash flows from operations, and working capital deficiencies. Additionally, the Company has significant borrowing base deficiency payments due under its revolving credit agreement and does not anticipate maintaining compliance with the debt covenants contained in its revolving credit agreement during 2020, which may accelerate the Company’s debt obligations. These matters raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ BDO USA, LLP

We have served as the Company’s auditor since 2017.
Dallas, Texas
April 30, 2020



85







Lilis Energy, Inc. and Subsidiaries
Consolidated Balance Sheets
(In thousands, except share and per share data)
 
December 31,
 
2019
 
2018
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
3,753

 
$
21,137

Accounts receivable, net of allowance of $448 and $25, respectively
18,146

 
20,546

Derivative instruments
427

 
2,551

Prepaid expenses and other current assets
4,438

 
1,851

Total current assets
26,764

 
46,085

Property and equipment:
 
 
 
Oil and natural gas properties, full cost method of accounting, net
228,855

 
430,379

Other property and equipment, net
421

 
524

Total property and equipment, net
229,276

 
430,903

Right-of-use assets
1,722

 

Other assets
837

 
3,785

Total assets
$
258,599

 
$
480,773

LIABILITIES, MEZZANINE EQUITY AND STOCKHOLDERS’ EQUITY (DEFICIT)
 
 
 
Current liabilities:
 
 
 
Current portion of long-term debt
$
115,000

 
$

Accounts payable
24,834

 
47,112

Accrued liabilities and other
13,972

 
14,794

Revenue payable
11,442

 
14,546

Derivative instruments
5,044

 
515

Total current liabilities
170,292

 
76,967

Asset retirement obligations
3,423

 
2,433

Long-term debt

 
157,804

Long-term derivative instruments and other non-current liabilities
3,762

 
4,699

Long-term deferred revenue and other long-term liabilities
73,749

 
52,513

Total liabilities
251,226

 
294,416

Commitments and Contingencies - Note 21


 


Mezzanine equity:
 
 
 
10,000,000 shares of preferred stock authorized
 
 
 
Series C-1 9.75% Participating Preferred Stock, 100,000 shares issued and outstanding with a stated value of $1,203 and $1,093, per share, as of December 31, 2019 and 2018, respectively
80,446

 
106,774

Series C-2 9.75% Participating Preferred Stock, 25,000 shares issued and outstanding with a stated value of $1,128 and $1,024, per share, as of December 31, 2019 and 2018, respectively
18,857

 
25,522

Series D 8.25% Participating Preferred Stock, 39,254 shares issued and outstanding with a stated value of $1,107 and $1,021, per share, as of December 31, 2019 and 2018, respectively
29,082

 
40,729

Series E 8.25% Convertible Participating Preferred Stock, 60,000 shares issued and outstanding with a stated value of $1,069, per share, as of December 31, 2019
66,285

 

Series F 9.00% Participating Preferred Stock, 55,000 shares issued and outstanding with a stated value of $1,076, per share, as of December 31, 2019
50,861

 


86







Stockholders’ equity (deficit):
 
 
 
Common stock, $0.0001 par value per share, 150,000,000 shares authorized 91,584,460 and 71,182,016 issued and outstanding as of December 31, 2019 and December 31, 2018, respectively
9

 
7

Additional paid-in capital
342,382

 
321,753

Treasury stock, 253,598 shares at cost
(997
)
 
(997
)
Accumulated deficit
(579,552
)
 
(307,431
)
Total stockholders’ equity (deficit)
(238,158
)
 
13,332

Total liabilities, mezzanine equity and stockholders’ equity (deficit)
$
258,599

 
$
480,773


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

87







Lilis Energy, Inc. and Subsidiaries
Consolidated Statements of Operations
(In thousands, except share and per share data)
 
Year Ended December 31,
 
2019
 
2018
Revenues:
 
 
 
Oil sales
$
59,015

 
$
58,042

Natural gas sales
3,180

 
5,246

Natural gas liquid sales
3,868

 
6,928

Total revenues
66,063

 
70,216

Operating expenses:
 
 
 
Production costs
16,127

 
13,843

Gathering, processing and transportation
3,960

 
3,392

Production taxes
3,302

 
3,709

General and administrative
28,371

 
33,251

Depreciation, depletion, amortization and accretion
33,252

 
25,367

Impairment of oil and natural gas properties
228,324

 

Total operating expenses
313,336

 
79,562

Operating loss
(247,273
)
 
(9,346
)
Other income (expense):
 
 
 
Loss on early extinguishment of debt
(1,299
)
 
(20,370
)
Gain (loss) from commodity derivatives
(8,985
)
 
55

Change in fair value of financial instruments
(3,573
)
 
58,343

Interest expense
(11,426
)
 
(32,827
)
Other income
435

 
2

Total other income (expense)
(24,848
)
 
5,203

Net loss before income taxes
(272,121
)
 
(4,143
)
Income tax expense

 

Net loss
(272,121
)
 
(4,143
)
Paid-in-kind dividends on preferred stock
(25,397
)
 
(10,687
)
Net loss attributable to common stockholders
$
(297,518
)
 
$
(14,830
)
 
 
 
 
Net loss per common share-basic and diluted: (Note 18)
 
 
 
Basic
$
(3.38
)
 
$
(0.24
)
Diluted
$
(3.38
)
 
$
(0.47
)
 
 
 
 
Weighted average common shares outstanding:
 
 
 
Basic
87,912,362

 
62,854,214

Diluted
87,912,362

 
78,451,341


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


88







Lilis Energy, Inc. and Subsidiaries
Consolidated Statements of Changes in Stockholders’ Equity (Deficit)
(In thousands, except share data)
 
Common Shares
 
Additional
Paid-In Capital
 
Treasury Shares
 
Accumulated Deficit
 
Total
 
Shares
 
Amount
 
 
Shares
 
Amount
 
 
Balance, January 1, 2018
53,368,331

 
$
5

 
$
272,335

 

 
$

 
$
(303,288
)
 
$
(30,948
)
Stock-based compensation

 

 
9,000

 

 

 

 
9,000

Common stock for restricted stock
404,093

 

 

 

 

 

 

Common stock withheld for taxes on stock-based compensation
(484,727
)
 

 
(2,230
)
 

 

 

 
(2,230
)
Common stock for acquisition of oil and natural gas properties
6,940,722

 
1

 
24,777

 

 

 

 
24,778

Exercise of warrants and stock options
5,000,834

 

 
3,751

 

 

 

 
3,751

Common stock issued for extinguishment of debt
5,952,763

 
1

 
24,584

 

 

 

 
24,585

Reclassification of warrant derivative liabilities

 

 
223

 

 

 

 
223

Purchase of treasury stock

 

 

 
(253,598
)
 
(997
)
 

 
(997
)
Dividends on preferred stock

 

 
(10,687
)
 

 

 

 
(10,687
)
Net loss

 

 

 

 

 
(4,143
)
 
(4,143
)
Balance, December 31, 2018
71,182,016

 
$
7

 
$
321,753

 
(253,598
)
 
$
(997
)
 
$
(307,431
)
 
$
13,332

Stock-based compensation

 

 
6,506

 

 

 

 
6,506

Common stock for restricted stock
3,178,448

 

 

 

 

 

 

Common stock withheld for taxes on stock-based compensation
(417,642
)
 

 
(546
)
 

 

 

 
(546
)
Common stock issued for extinguishment of debt
17,641,638

 
2

 
32,988

 

 

 

 
32,990

Gain on extinguishment of debt

 

 
7,078

 

 

 

 
7,078

Dividends on preferred stock

 

 
(25,397
)
 

 

 

 
(25,397
)
Net loss

 

 

 

 

 
(272,121
)
 
(272,121
)
Balance, December 31, 2019
91,584,460

 
$
9

 
$
342,382

 
(253,598
)
 
$
(997
)
 
$
(579,552
)
 
$
(238,158
)














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

89







Lilis Energy, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
(In thousands) 
 
Year Ended December 31,
 
2019
 
2018
Cash flows from operating activities:
 
 
 
Net loss
$
(272,121
)
 
$
(4,143
)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
 
 
 
Stock-based compensation
6,506

 
9,000

Bad debt recovery
422

 
106

Amortization of debt issuance cost and accretion of debt discount
2,460

 
15,656

Payable in-kind interest
1,590

 
12,213

Loss on early extinguishment of debt
1,299

 
20,370

Loss (gain) from commodity derivatives, net
8,985

 
(55
)
Net settlements paid on commodity derivatives
(3,214
)
 
(2,742
)
Change in fair value of financial instruments
3,573

 
(58,343
)
Deferred revenue realized
(232
)
 

Impairment of oil and natural gas properties
228,324

 

Depreciation, depletion, amortization and accretion
33,252

 
25,367

Operating lease ROU amortization
(453
)
 

Changes in operating assets and liabilities:
 
 
 
Accounts receivable
(6,378
)
 
(13,226
)
Prepaid expenses and other assets
(944
)
 
(473
)
Accounts payable and accrued liabilities
(31,393
)
 
53,402

Proceeds from options associated with future midstream services
2,500

 
35,000

Net cash (used in) provided by operating activities
(25,824
)
 
92,132

Cash flows from investing activities:
 
 
 
Acquisition of oil and natural gas properties

 
(92,410
)
Proceeds from the sale of assets
16,851

 
17,500

Capital expenditures
(82,378
)
 
(168,025
)
Net cash used in investing activities
(65,527
)
 
(242,935
)
Cash flows from financing activities:
 
 
 
Proceeds from term loans, net of financing costs

 
47,806

Proceeds from revolving credit agreement, net of financing costs
56,883

 
72,566

Repayment of term loans and notes payable

 
(88,836
)
Repayment of revolving credit agreement
(18,000
)
 

Proceeds from the issuance of Series C Preferred Stock

 
122,418

Proceeds from the Värde financing arrangement, net of transaction costs
38,230

 

Partial repayment of the Värde financing arrangement
(2,600
)
 

Repurchase of common stock

 
(997
)
Proceeds from exercise of warrants and stock options

 
3,751

Payment for tax withholding on stock-based compensation
(546
)
 
(2,230
)
Net cash provided by financing activities
73,967

 
154,478

Net increase (decrease) in cash and cash equivalents
(17,384
)
 
3,675

Cash and cash equivalents at beginning of period
21,137

 
17,462

Cash and cash equivalents at end of period
$
3,753

 
$
21,137

Supplemental disclosure:
 
 
 
Cash paid for interest
$
6,488

 
$
4,958


  

90







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

91







Lilis Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
 
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 - LIQUIDITY AND GOING CONCERN

These consolidated financial statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business for the twelve-month period following the date of issuance of these consolidated financial statements. As such, the accompanying consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets and their carrying amount, or the amount and classification of liabilities that may result should the Company be unable to continue as a going concern.

As of December 31, 2019, we were fully drawn against the borrowing base under our Revolving Credit Agreement (as defined in Note 11 - Long-Term Debt), with $115.0 million of indebtedness outstanding under our Revolving Credit Agreement. As provided for in the Seventh Amendment to our Revolving Credit Agreement and as a result of a decrease in commodity prices, on January 17, 2020, the borrowing base was decreased to $90.0 million.

As a result of the January 17, 2020 redetermination of the borrowing base, a borrowing base deficiency in the amount of $25.0 million (the “Borrowing Base Deficiency”) was created under the Revolving Credit Agreement. The Borrowing Base Deficiency constitutes the difference between the principal amount of borrowings currently outstanding under the Revolving Credit Agreement ($115.0 million) and the borrowing base as so redetermined ($90.0 million). On February 28, 2020, we paid $17.3 million towards the Borrowing Base Deficiency. Pursuant to the Fourteenth Amendment to the Revolving Credit Agreement, the remaining payment of $7.8 million is due June 5, 2020.

The Company is seeking additional funding and considering certain strategic transactions to enable it to pay the remaining Borrowing Base Deficiency amount of $7.8 million. Unless funding or additional transactions are completed, the Company will not be able to pay the remaining Borrowing Base Deficiency. There is no assurance that such transactions will occur or that the bank group will agree to further deficiency payment extensions. If the Company is unable to repay the remaining borrowing base deficiency as and when required under the Revolving Credit Agreement, an event of default would occur under the Revolving Credit Agreement.

Our next borrowing base redetermination is scheduled to occur on or about June 5, 2020. If the borrowing base is further reduced by the lenders in connection with this redetermination, we will be required to repay borrowings in excess of the borrowing base or eliminate the borrowing base deficiency by pledging additional oil and natural gas properties to secure our obligations under the Revolving Credit Agreement. Under the Revolving Credit Agreement, we have the option to affect such repayment either in full within 30 days after the redetermination or in monthly installments over a six-month period after the redetermination.

We have experienced losses and negative cash flows from operations and working capital deficiencies. Additionally, our liquidity and operating forecasts have been negatively impacted by the recent decrease in commodity prices, which impacts our ability to comply with debt covenants under our Revolving Credit Agreement. The commodity prices have fallen significantly since the beginning of 2020, due in part to failed OPEC negotiations as well as concerns about the COVID-19 pandemic, which has significantly decreased worldwide demand for oil and natural gas. Our Revolving Credit Agreement contains financial covenants that require the Company to maintain a ratio of Total Debt to EBITDAX (each as defined in the Revolving Credit Agreement) (the “Leverage Ratio”) of not more than 4.00 to 1.00 and a ratio of Current Assets to Current Liabilities (each as defined in the Revolving Credit Agreement) (the “Current Ratio”) of not less than 1.00 to 1.00 as of the last day of each fiscal quarter thereafter. See Note 11-Long-term Debt for additional information regarding the financial covenants under our Revolving Credit Agreement. As of December 31, 2019, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants under the Revolving Credit Agreement. Pursuant to the Twelfth Amendment (as defined in Note 11 - Long-Term Debt), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants, among other waivers of default, as of December 31, 2019. 

As of March 31, 2020, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants. Pursuant to the Fourteenth Amendment (as defined in Note 11 - Long-Term Debt), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants as of March 31, 2020. If we are not able to pay or defer the $7.8 million Borrowing Base Deficiency due on June 5, 2020 or do not maintain compliance with our debt covenants, the

92







obligations of the Company under the Revolving Credit Agreement may be accelerated, which would have a material adverse effect on our business. The Company does not expect to be in compliance with debt covenants in future periods without additional sources of liquidity or future amendments to the Revolving Credit Agreement.

Fluctuations in oil and natural gas prices have a material impact on our financial position, results of operations, cash flows and quantities of oil, natural gas and NGL reserves that may be economically produced. Historically, oil and natural gas prices have been volatile, and may be subject to wide fluctuations in the future. If continued depressed prices persist, the Company will continue to experience operating losses, negative cash flows from operating activities, and negative working capital.

In order to improve our leverage position and current ratio to meet the financial covenants under the Revolving Credit Agreement, we are currently pursuing or considering a number of actions, which in certain cases may require the consent of current lenders and stockholders. In November 2019, our board of directors formed a committee of independent directors (the “Special Committee”) tasked with reviewing and evaluating strategic alternatives that may enhance the value of the Company, including alternatives that may be available to identify and access further sources of liquidity through financing alternatives or deleveraging transactions. The Special Committee hired financial and legal advisors to advise the Special Committee on these matters.    

The Special Committee continues to explore financing alternatives and deleveraging transactions. We are also addressing operational matters such as adjusting our capital budget and improving cash flows from operations by continuing to reduce costs and intend to continue to pursue and consider other strategic alternatives.
    
There can be no assurance that we will be able to implement any of these plans successfully, or that such plans, if executed, will result in the ability to pay borrowing base deficiencies, generate sufficient liquidity to continue as a going concern or comply with our Revolving Credit Agreement covenants. The factors discussed above raise substantial doubt about our ability to continue as a going concern within twelve-month period following the date of issuance of these consolidated financial statements.

NOTE 3 - BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
Principles of Consolidation and Presentation
 
The accompanying consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, Brushy Resources, Inc., 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.
   
Use of Estimates
 
The accompanying 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, and common stock; and the allocation of general and administrative expenses. Actual results could differ significantly from these estimates.

Reclassifications

Certain reclassifications have been made to the prior year comparative financial statements to conform to the 2019 presentation. These reclassifications have no effect on the Company’s previously reported results of operations, stockholders’ equity or cash flows.

Cash and Cash Equivalents

Cash and cash equivalents include highly liquid instruments with an original maturity of three months or less are stated at cost, which approximates fair value.
 

93







Accounts Receivable

The Company has accounts receivable from joint interest owners of properties operated by the Company. The Company typically has the right to withhold future revenue disbursements to recover any non-payment of related joint interest billings. Management routinely assesses accounts receivable amounts to determine their collectability and accrues an allowance for uncollectible receivables when, based on the judgment of management, it is probable that a receivable will not be collected. The Company records actual and estimated oil and natural gas revenue receivable from third parties at its net revenue interest. In addition, the Company has receivables derived from sales of certain oil and natural gas production which are collateral under the Company’s credit agreements. The Company had an allowance for doubtful accounts of $0.4 million as of December 31, 2019. There was no allowance for doubtful accounts as of December 31, 2018.

Fair Value of Financial Instruments

As of December 31, 2019, and 2018, the carrying value of cash and cash equivalents, accounts receivable, accounts payable, accrued liabilities, revenue payable and advances from joint interest partners approximates fair value due to the short-term nature of such items. The carrying value of the Company’s secured debt is carried at cost which approximates the fair value of the debt as the related interest rates approximates interest rates currently available to the Company.

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. For the year ended December 31, 2019, the ceiling value of the Company’s reserves was calculated based upon SEC pricing of $55.69 per barrel for oil and $2.58 per MMBtu for natural gas. For the year ended December 31, 2018, the ceiling value of the Company’s reserves was calculated based upon SEC pricing of $65.56 per barrel for oil and $3.10 per MMBtu for natural gas. Full-cost ceiling impairments totaling $228.3 million were recorded for the year ended December 31, 2019 and resulted primarily from decreased commodity prices and reduction in expected PUDs used in preparation of estimated future net revenues from proved oil and natural gas reserves as compared to the commodity prices used for the year ended December 31, 2018, when no such impairments were recognized.

The costs of unproved oil and natural gas properties are excluded from amortization until the properties are evaluated. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved oil and natural gas reserves are established or if impairment is determined. Unproved oil and natural gas properties are assessed periodically, at least annually, to determine whether impairment had occurred. The assessment considers the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, the economic viability of development if proved reserves were assigned and other current market conditions. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and were then subject to amortization.


94







Wells in Progress
 
Wells in progress connotes wells that are currently in the process of being drilled or completed or otherwise under evaluation as to their potential to produce oil and natural gas reserves in commercial quantities. Such wells continue to be classified as wells in progress and withheld from the depletion calculation and the ceiling test until such time as either proved reserves can be assigned, or the wells are otherwise abandoned. Upon either the assignment of proved reserves or abandonment, the costs for these wells are then transferred to the full cost pool and become subject to both depletion and the ceiling test calculations in accordance with full cost accounting under Rule 4-10 of Regulation S-X of the Securities Exchange Act of 1934, as amended.

Capitalized Interest

For significant oil and natural gas investments in unproved properties, and significant exploration and development projects that have not commenced production, interest is capitalized as part of the historical cost of developing and constructing assets. Capitalized interest is determined by multiplying the Company’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depreciation or impairment. As of December 31, 2019, there were no significant exploratory projects on unproved properties and none of the development projects exceeded the interest capitalization qualifying asset limit. As a result, no interest was capitalized as of December 31, 2019 and 2018.
 
Other Property and Equipment

Property and equipment include vehicles, office equipment and furniture which are stated at cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets. The estimated useful lives of property and equipment range from 4 to 20 years. The Company recorded approximately $0.2 million and $0.1 million of depreciation for the years ended December 31, 2019 and 2018, respectively.

Asset Retirement Obligations

The Company incurs retirement obligations for certain assets at the time they are placed in service. The fair values of these obligations are recorded as liabilities on a discounted basis. The costs associated with these liabilities are capitalized as part of the related assets and depreciated. Over time, the liabilities are accreted for the change in their present value. For purposes of depletion, the Company includes estimated dismantlement and abandonment cost, net of salvage values, associated with future development activities that have not yet been capitalized as asset retirement obligations. Asset retirement obligations incurred are classified as Level 3 (unobservable inputs) fair value measurements.

Revenue Recognition

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.

Stock based Compensation 

The Company applies a fair value method of accounting for stock based compensation, which requires recognition in the financial statements of the cost of services received in exchange for equity awards. For equity awards, compensation expense is based on the fair value on the grant date or modification date and is recognized in the Company’s financial statements over the vesting period. The Company utilizes the Black-Scholes Merton option-pricing model to measure the fair value of stock options based on several criteria, including but not limited to, the valuation model used and associated input factors, such as expected term of the award, stock price volatility, risk free interest rate, dividend rate. These inputs are subjective and are determined using management’s judgment. If differences arise between the assumptions used in determining stock based compensation expense and the actual factors, which become known over time, the Company may change the input factors used in determining future

95







stock based compensation expense. The fair value of restricted stock awards is identified as the closing stock price on the day the award was granted. The Company recognizes forfeitures as and when the stock awards are forfeited.

The Company accounts for warrant grants to nonemployees whereby the fair values of such warrants are determined using the option pricing model at the earlier of the date at which the nonemployee’s performance is complete or a performance commitment is reached.

Income Taxes

The Company uses the asset and liability method in accounting for income taxes. Deferred tax assets and liabilities are recognized for temporary differences between financial statement carrying amounts and the tax bases of assets and liabilities and are measured using the tax rates expected to be in effect when the differences reverse. Deferred tax assets are also recognized for operating loss and tax credit carry forwards. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the results of operations in the period that includes the enactment date. A valuation allowance is used to reduce deferred tax assets when uncertainty exists regarding their realization.

The Company recognizes its tax benefits only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely to be realized upon settlement. A liability for “unrecognized tax benefits” is recorded for any tax benefits claimed that do not meet these recognition and measurement standards. As of December 31, 2019 and 2018, the Company has determined that no liability is required to be recognized.

The Company’s policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense. No interest or penalties were required to be accrued at December 31, 2019 and 2018. Further, the Company does not expect that the total amount of unrecognized tax benefits will significantly increase or decrease during the next 12 months.

Concentration of Credit Risk

The Company operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payment for costs associated with the property and seeks reimbursement from the other joint interest owners in the property for their portion of those costs. When warranted, prepayments are required from joint interest owners for drilling and completion projects. Joint interest owners consist primarily of independent oil and natural gas producers whose ability to reimburse the Company could be negatively impacted by adverse market conditions.

The purchasers of the Company’s oil, natural gas and NGL production consist primarily of independent marketers, major oil and natural gas companies, refiners and natural gas pipeline companies. Credit evaluations are performed on the Company’s purchasers of its production and their financial condition is monitored on an ongoing basis. Based on those evaluations and monitoring, the Company may obtain letters of credit or parental guarantees from some purchasers.

All of the Company’s oil and natural gas derivative transactions are carried out in the over-the-counter market and are not typically subject to margin-deposit requirements. The use of derivative transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. The Company monitors the credit ratings of its derivative counterparties on an ongoing basis. If a counterparty were to default on its obligations to the Company under the derivative contracts or seek bankruptcy protection, it could have a material adverse effect on its ability to fund planned activities and could result in a larger percentage of our future production being subject to commodity price volatility. In addition, in poor economic environments and tight financial markets, the risk of a counterparty default is heightened and fewer counterparties may participate in derivative transactions, which could result in greater concentration of exposure to any one counterparty or a larger percentage of the Company’s future production being subject to commodity price changes.

Derivative Instruments

All derivative instruments are recorded on the consolidated balance sheet at fair value as either an asset or a liability with changes in fair value recognized currently in earnings. Although derivative instruments are used by the Company to manage the price risk attributable to its expected oil and natural gas production, those derivative instruments have not been designated as accounting hedges under the accounting guidance. All of our derivatives are accounted for as mark-to-market activities. Under ASC Topic 815, “Derivatives and Hedging,” these instruments are recorded on the consolidated balance sheets at fair value as either short term or long-term assets or liabilities based on their anticipated settlement date. The Company nets derivative assets and liabilities by commodity for counterparties where a legal right to such offset exists. Changes in the derivatives’ fair values are

96







recognized in current earnings since the Company has elected not to designate its current derivative contracts as cash flow hedges for accounting purposes.

The Company has recognized certain conversion features within its Second Lien Term Loan as embedded derivatives that have been bifurcated from the Second Lien Term Loan, as defined in Note 9 - Derivatives, and accounted for separately from the debt.

The Company has recognized that our crude oil sales agreement with ARM no longer meets the criteria for the “normal purchase normal sales” exception under ASC 815, “Derivatives and Hedging,” due to the Company not meeting the minimum quantities deliverable under the contract and the net settlement criteria being met. As a result, an embedded derivative exists as it is no longer probable the contract will only result in physical deliveries of crude oil and may net settle. See Note 9 - Derivatives for additional information.

Recently Adopted Accounting Standards
 
In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (ASU) No. 2016-02, Leases (Topic 842), a standard on lease accounting requiring a lessee to recognize assets and liabilities on the balance sheet for leases with lease terms greater than 12 months. This standard was effective for annual and interim periods beginning after December 15, 2018. We adopted this standard effective January 1, 2019, utilizing a modified retrospective transition approach. We chose to use the effective date as our date of initial application. Consequently, financial information was not updated and the disclosures required under the new standard were not provided for dates and periods before January 1, 2019.

The standard includes optional transition practical expedients intended to simplify its adoption. We elected to adopt the package of practical expedients, which allowed us to retain the historical lease classification, including treatment for land easements, determined under legacy GAAP as well as a relief from reviewing expired or existing contracts to determine if they contain leases. This standard does not apply to the Company’s leases that provide the right to explore for minerals, oil, or natural gas resources.

Upon adoption, we recognized operating lease liabilities totaling approximately $7.5 million, with corresponding right of use assets totaling $7.4 million. The liabilities were calculated as the present value of the remaining minimum rental payments for existing operating leases. This standard did not materially impact our consolidated net earnings and had no impact on our cash flows (see Note 10 - Leases).

Accounting Standards Not Yet Adopted

In June 2016, the FASB issued ASU 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which replaces the currently required incurred loss methodology with an expected loss methodology. This new methodology requires that a financial asset measured at amortized cost be presented at the net amount expected to be collected. The update is intended to provide financial statement users with more useful information about expected credit losses on financial instruments. The amended standard is effective for the Company on January 1, 2023, with early adoption permitted, and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Company is evaluating the impact the adoption of ASU 2016-13 will have on its consolidated financial statements.

In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement, which modifies the fair value disclosure requirements based on application of the disclosure framework. The provisions removed or amended certain disclosures and in some cases, the ASU requires additional disclosures. The standard is effective for the Company for fiscal years, and interim periods within those years, beginning after December 15, 2019. The Company is evaluating the impact the adoption of ASU 2018-13 will have on its consolidated financial statements.


97







Accrued Liabilities and Other
 
At December 31, 2019 and 2018, the Company’s accrued liabilities consisted of the following:
 
2019
 
2018
 
(In thousands)
Accrued personnel costs
$

 
$
2,300

Accrued drilling and completion costs
5,021

 
2,849

Drilling advances
1,328

 
5,001

Accrued production expenses
3,326

 
2,926

Other accrued liabilities
3,885

 
1,718

Short-term operating lease liabilities
412

 

 
$
13,972

 
$
14,794

 
NOTE 4 - OIL AND NATURAL GAS PROPERTIES

The following table sets forth a summary of oil and natural gas property costs (net of divestitures) at December 31, 2019 and 2018:
 
December 31,
 
2019
 
2018
 
(In thousands)
Oil and natural gas properties:
 
 
 
  Proved
$
478,569

 
$
358,858

  Unproved
109,590

 
169,863

Total oil and natural gas properties
588,159

 
528,721

Accumulated depletion, depreciation, amortization and impairment
(359,304
)
 
(98,342
)
Oil and natural gas properties, net
$
228,855

 
$
430,379


The following table sets forth a summary of costs withheld from amortization as of December 31, 2019:
 
Year of Acquisition
 
Total
 
2019
 
2018
 
2017
 
(In thousands)
Unamortized costs:
 
 
 
 
 
 
 
   Unproved leasehold costs
$
109,590

 
$
1,643

 
$
85,598

 
$
22,349

       Total
$
109,590

 
$
1,643

 
$
85,598

 
$
22,349


For the years ended December 31, 2019 and 2018, $56.2 million and $11.1 million, respectively, of unproved property costs were recorded as impairments of unproved property costs and transferred to proved properties. Impairments for 2019 were the result of title defects, lease expirations, changes to management’s development plans and uncertainty that the Company will have access to necessary funding to either extend the leases expiring in 2020 or begin drilling before their expiration dates. The 2018 impairment of $11.1 million was the result of defective titles for certain leases.

Depreciation, depletion and amortization expense related to proved properties was approximately $32.6 million and $25.2 million, respectively for the years ended December 31, 2019 and 2018. Full-cost ceiling impairments totaling $228.3 million were recorded for the year ended December 31, 2019. For the year ended December 31, 2018, no such impairments were recognized.

The 2019 impairment charges were the result of a decrease in crude oil and natural gas prices used in preparation of the proved reserves estimates. Additionally, proved undeveloped reserves previously included in the Company’s proved reserves report were reclassified as unproved because of the uncertainty regarding the availability of capital for development those reserves as of December 31, 2019. The reclassification of proved undeveloped reserves to unproved are recognized in the Company’s proved reserves report as of December 31, 2019. These changes have contributed, in part, to higher depletion rates for 2019 as compared to 2018.


98







NOTE 5 - ACQUISITIONS AND DIVESTITURES

Divestitures During 2019

On July 31, 2019, the Company entered into two agreements with Winkler Lea Royalty, L.P. (“WLR”) and Winkler Lea WI, L.P. (“WLWI”) for the sale of an overriding royalty interest and a non-operated working interest in undeveloped assets, respectively, for combined cash proceeds of $39.0 million, including WLWI’s drilling advance (the “Asset Sales”). WLR and WLWI are affiliates of Värde Partners, Inc., a related party (see Note 13 - Related Party Transactions).

The Company entered into a Purchase and Sale Agreement with WLR (the “ORRI Agreement”), pursuant to which the Company sold to WLR an overriding royalty interest (the “ORRI”) in approximately 1,446 net royalty acres in Winkler and Loving Counties, Texas, and Lea County, New Mexico. The ORRI is equal to the positive difference, if any, between 25% and existing royalties and other burdens, subject to proportionate reduction and the other terms and conditions set forth in the instrument of conveyance. The ORRI Agreement provides the Company with a right to repurchase all, but not less than all, of the ORRI for a period of three years and an obligation, at WLR’s election only upon a change of control, to repurchase all, but not less than all, of the ORRI, and also includes certain limitations on WLR’s right to transfer the ORRI during such three year period without the consent of the Company. The repurchase price for the first two years of the repurchase period is 1.5 times the purchase price paid by WLR, less the proportionate share of production paid by the Company. For the third year, the repurchase price is the same with the multiplier increased to 1.75. After the third year, the repurchase period expires.

The Company entered into a Purchase and Sale Agreement with WLWI (the “WI Agreement”), pursuant to which the Company sold an undivided 49% of its right, title and interest in certain undeveloped assets located in Winkler and Loving Counties, Texas, consisting of approximately 749 net acres. The WI Agreement provides that the Company must drill, complete and equip five commitment wells after closing (the “Development Plan”). Contemporaneously with the purchase, WLWI paid a drilling advance which funded its proportionate share of the development costs to drill, complete and equip such commitment wells. Any drilling cost overruns or costs incurred below estimated costs are the responsibility of the Company. As of December 31, 2019, three of the five commitment wells are producing, the fourth well is drilled and awaiting completion and the fifth well has not yet been drilled. Under the WI Agreement, the fourth and fifth wells are required to begin production mid-year 2020, subject to reasonable delays on account of Force Majeure or modifications or revisions to the Development Plan as approved by both parties. Should the Company otherwise breach the scheduled Development Plan, WLWI shall be entitled to liquidated damages of an amount equal to $150,000 plus $1,500 for each day beyond a 60-day period after Development Plan commitment date until the actual date of first production.

The WI Agreement provides the Company with a right to repurchase all, but not less than all, of the interest for a period of three years and an obligation, at WLWI’s election only upon a change of control, to repurchase all, but not less than all, of the interest, and also includes certain limitations on WLWI’s right to transfer the interest during such three year period without the consent of the Company. The repurchase price is 1.5 times the consideration paid by WLWI plus additional capital expenditures of WLWI. The repurchase period expires after three years.

As a result of the repurchase rights, the agreements with WLR and WLWI do not meet the criteria for a conveyance or sale of assets under ASC 932, “Extractive Activities - Oil & Gas”, and are accounted for as a financing arrangement. The net proceeds of the transaction of $39.0 million are included in long-term deferred revenue and other long-term liabilities on the Company’s consolidated balance sheet as of December 31, 2019. WLR’s proportionate share of revenue of $0.4 million and WLWI’s proportionate share of net revenues, (revenues less production costs), of $0.5 million for the year ended December 31, 2019 is included in interest expense on the Company’s consolidated statements of operations.

On August 16, 2019, we sold approximately 513 noncontiguous net acres in New Mexico for net cash proceeds of $16.7 million, which was recorded as a reduction to the full cost pool. The Company repurchased certain overriding royalty interests in the acreage previously sold to WLR under the ORRI Agreement for $2.6 million, resulting in a $1.3 million loss on extinguishment of a portion of the financing arrangement and is included in loss on early extinguishment of debt on the Company’s consolidated statements of operations.

On February 28, 2020, the Company closed on the sale of approximately 1,185 undeveloped net acres in Lea County, New Mexico, for net cash proceeds of approximately $24.1 million, subject to customary purchase price adjustments (the “Marlin Disposition”). The proceeds were used to fund a substantial portion of the Borrowing Base Deficiency with the balance to be used for general corporate purposes.


99







Acquisitions During 2018

During the year ended December 31, 2018, the Company acquired the following oil and natural gas properties:

Certain leasehold acreage in the Delaware Basin in Lea County, New Mexico from OneEnergy Partners Operating, LLC for $40.0 million in cash and 6,940,722 shares of the Company’s common stock valued at approximately $24.9 million, for total consideration of approximately $64.9 million. Transaction costs associated with this acquisition were approximately $1.1 million. The transaction was recorded as an asset acquisition.

Certain leasehold interests and other oil and natural gas assets in Loving and Winkler Counties, Texas from VPD Texas, L.P. for total cash consideration of approximately $11.1 million, including approximately $0.5 million of related acquisition costs. The transaction was recorded as an asset acquisition.
 
Certain leasehold interests and other oil and natural gas assets in Loving and Winkler Counties, Texas from Anadarko for total cash consideration of $7.1 million. The transaction was recorded as an asset acquisition.

Certain leasehold interests and other oil and natural gas assets in Lea County, New Mexico from Ameradev II, LLC for total cash consideration of $7.2 million and was recorded as an adjustment to the full cost pool.
 
Certain leasehold interests and other oil and natural gas assets in Loving and Winkler Counties, Texas from Felix Energy Holdings II, LLC for total cash consideration of $0.4 million and was recorded as an adjustment to the full cost pool.

Proved property and certain leasehold interests located in Winkler County, Texas from Southwest Royalties, LLC for total consideration of approximately $17.0 million. The acquisition was accounted for as a business combination. Therefore the purchase price was allocated to the assets acquired and liabilities assumed based on their estimated acquisition date fair values available at closing. Transaction costs associated for this acquisition were immaterial and were expensed in the Consolidated Statements for Operations during the year ended December 31, 2018. Revenues and operating expenses associated with the proved properties were insignificant to the December 31, 2018 Consolidated Statements of Operations. The following table presents the final allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date:
 
 
As of October 16, 2018
 
 
(In thousands)
Fair value of net assets:
 
 
Proved oil and natural gas properties
 
$
12,562

Unproved oil and natural gas properties
 
4,542

Total assets acquired
 
17,104

Asset retirement obligations assumed
 
(65
)
Fair value of net assets acquired
 
$
17,039


NOTE 6 - ASSET RETIREMENT OBLIGATIONS
 
The Company’s asset retirement obligations (“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.
 

100







The following table summarizes the changes in the Company’s ARO for the years ended December 31, 2019 and 2018
 
For the Year Ended December 31,
 
2019
 
2018
 
(In thousands)
ARO, beginning of period
$
2,444

 
$
952

Additional liabilities incurred
186

 
374

Accretion expense
433

 
85

Liabilities settled
(78
)
 
(87
)
Revision in estimates
438

 
1,120

ARO, end of period
3,423

 
2,444

Less: current portion of ARO (1)

 
(11
)
ARO, non-current
$
3,423

 
$
2,433

(1) The current portion of ARO is included in accrued liabilities in the consolidated balance sheets.

NOTE 7 - 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 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. Effective January 1, 2019 through February 28, 2019, the Company’s crude oil was sold under a single short-term contract. The purchaser’s commitment included all quantities of crude oil from the leases that were covered by the contract, with no quantity-based restrictions or variable terms. Pricing was based on posted indexes for crude oil of similar quality, less a negotiable fees deduction of $5.15 per barrel.

Effective March 1, 2019, the Company’s crude oil is sold under a single long-term contract with a term that extends to at least December 31, 2024. The purchaser’s commitment has a quantity-based minimum set forth in the contract, measured in barrels per day, with the minimum quantity commitment increasing at periodic intervals over the life of the contract to coincide with the Company’s expected growth in production.

Pursuant to the long-term contract, pricing is based on posted indexes for crude oil of similar quality, with a differential based on pipeline delivery to Houston, as opposed to the previous contract differential based on truck delivery to Midland-Cushing, along with a differential basis reduction of $9.25 per barrel that was effective from March 1, 2019 through June 30, 2019, which decreased to $6.50 per barrel for the period of July 1, 2019 through June 30, 2020, and then to $4.95 per barrel for the period from July 1, 2020 through December 31, 2024. The posted index prices and differentials change monthly based on the average of daily index price points for each sales month. The purchaser’s affiliate shipper also charges a tariff fee of $0.75 as a deduction from the received price (see Note 12 - Long-Term Deferred Revenue Liabilities and Other Long-Term Liabilities).


101







Natural Gas and NGL Revenues
 
Natural gas from our properties 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 our operated natural gas production is sold under one of two natural gas contracts, both of 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. Pricing under the gas contracts is 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 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 under production is recorded as a receivable. The Company did not have any significant natural gas imbalance positions as of December 31, 2019 and 2018.

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. To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and also recorded as accounts receivable in the accompanying consolidated balance sheets. In this scenario, payment is 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.

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


102







Practical expedients

A significant number of the Company’s product sales are short-term in nature with contract term of one year or less. For those contracts, the Company utilizes the practical expedient 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 less than one year, the Company utilizes 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) for the year ended December 31, 2019:
Year Ended December 31, 2019
Short-term contracts
 
Long-term contracts
 
Total
Crude oil
$
9,711

 
$
49,304

 
$
59,015

Natural gas
220

 
2,960

 
3,180

NGLs
188

 
3,680

 
3,868


Customer Credit Risk
 
Our principal exposure to credit risk is through receivables from the sale of our oil and natural gas production of approximately $9.1 million and $8.2 million at December 31, 2019 and 2018, respectively, and through actual and accrued receivables from our joint interest partners of approximately $9.5 million and $11.4 million at December 31, 2019 and 2018, 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 year ended December 31, 2019, the Company’s major customers as a percentage of total revenue consisted of the following:
 
Year ended December 31,
 
2019
 
2018
ARM Energy Management, LLC
68
%
 
%
Texican Crude & Hydrocarbon, LLC
19
%
 
87
%
Lucid Energy Delaware, LLC
12
%
 
10
%
Other below 10%
1
%
 
3
%
 
100
%
 
100
%
    
NOTE 8 - 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.


103







Determination of the fair values of our derivative contracts incorporates various factors, including not only the impact of our non-performance risk on our liabilities, but also the credit standing of the counterparties involved. The Company utilizes counterparty rate of default values to assess the impact of non-performance risk when evaluating both our liabilities to, and receivables from, counterparties.
 
Recurring Fair Value Measurements
 
Fair Value Measurement Classification
 
 
 
Quoted Prices in
Active Markets for
Identical Assets or
Liabilities
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Total
 
(In thousands)
As of December 31, 2019
 

 
 

 
 

 
 

Oil and natural gas derivative instruments:
 
 
 
 
 
 
 
Oil and natural gas derivative swap contracts
$

 
$
(3,932
)
 
$

 
$
(3,932
)
Oil and natural gas derivative collar contracts

 
301

 

 
301

Embedded derivative instruments:
 
 
 
 
 
 
 
Net settlement provisions under ARM sales agreement

 

 
(3,238
)
 
(3,238
)
Total
$

 
$
(3,631
)
 
$
(3,238
)
 
$
(6,869
)
As of December 31, 2018
 
 
 
 
 
 
 
Oil and natural gas derivative instruments:
 
 
 
 
 
 
 
Oil and natural gas derivative swap contracts
$

 
$
(2,923
)
 
$

 
$
(2,923
)
Oil and natural gas derivative collar contracts

 
4,047

 

 
4,047

Embedded derivative instruments:
 
 
 
 
 
 
 
Second Lien Term Loan conversion features

 

 
(1,965
)
 
(1,965
)
Total
$

 
$
1,124

 
$
(1,965
)
 
$
(841
)

Derivative assets and liabilities include unsettled amounts related to commodity derivative positions, including swaps and collars, as of December 31, 2019 and 2018. The fair value of the Company’s derivatives is based on third-party pricing models which utilize inputs that are either readily in the public market or which can be corroborated from active markets of broker quotes. Swaps and collars generally have observable inputs and these instruments are measured using Level 2 inputs.

In addition, derivative liabilities as of December 31, 2019 include an embedded derivative associated with the ARM sales agreement (see Note 21 - Commitments and Contingencies). The Company recognized a derivative liability and an unrealized loss of $3.2 million as of December 31, 2019. This embedded derivative has fewer observable inputs from objective sources and are therefore measured using Level 3 inputs. The fair value of the net settlement provisions under the agreement was determined based on certain assumptions including (1) forward pricing for crude oil basis differentials, (ii) future LIBOR rates and (iii) the Company’s implied credit rating.

The Company’s derivative liabilities as of December 31, 2018 also include embedded derivatives associated with the Second Lien Term Loan (as defined in Note 11 - Long-Term Debt). These instruments have fewer observable inputs from objective sources and are therefore measured using Level 3 inputs. The Company recorded an unrealized loss of $0.3 million and $58.3 million on the change in fair value of derivative liabilities associated with the Second Lien Term Loan conversion features for the years ended December 31, 2019 and 2018, respectively.

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


104







The following table sets forth a reconciliation of changes in the fair value of the Company’s financial assets and liabilities classified as Level 3 in the fair value hierarchy, except for the commodity derivatives classified as Level 2, as disclosed in Note 9, as of December 31, 2019 and 2018:

 
Firm Takeaway and Pricing Agreement Net Settlement Provisions
 
Second Lien Term
Loan Conversion
Features
 
Total
 
(in thousands)
Balance at January 1, 2019
$

 
$
(1,965
)
 
$
(1,965
)
Fair value of the converted portion of the embedded derivatives associated with the Second Lien Term Loan

 
2,300

 
2,300

Fair value of the embedded derivatives in ARM Sales Agreement
(3,238
)
 
(335
)
 
(3,573
)
Balance at December 31, 2019
$
(3,238
)
 
$

 
$
(3,238
)

 
Second Lien Term
Loan Conversion
Features
 
Warrant
Liabilities
 
Total
 
(in thousands)
Balance at January 1, 2018
$
(72,714
)
 
$
(223
)
 
$
(72,937
)
Transferred to equity

 
223

 
223

Fair value of the converted portion of the embedded derivatives associated with the Second Lien Term Loan
12,406

 

 
12,406

Change in fair value of derivative liabilities
58,343

 

 
58,343

Balance at December 31, 2018
$
(1,965
)
 
$

 
$
(1,965
)
 
NOTE 9 - DERIVATIVES

The Company’s derivative instruments as of December 31, 2019 and 2018, include the following:
 
December 31,
 
2019
 
2018
 
(In thousands)
Derivative assets (liabilities):
 
 
 
Derivative assets - current
$
427

 
$
2,551

Derivative assets - non-current (1)
187

 
1,822

Derivative liabilities - current (3)
(5,044
)
 
(515
)
Derivative liabilities - non-current (2) (3) (4)
(2,439
)
 
(4,699
)
Total derivative liabilities, net
$
(6,869
)
 
$
(841
)

(1) The non-current derivative assets are included in other assets in the consolidated balance sheets.
(2) The non-current derivative liabilities are included in long-term derivative instruments and other non-current liabilities in the consolidation balance sheets.
(3) The ARM sales agreement includes an embedded derivative. As of December 31, 2019, the embedded derivative is included as current liabilities and non-current liabilities of $0.8 million and $2.4 million, respectively.
(4) Includes $2.0 million embedded derivative associated with Second Lien Term Loan and $2.7 million in commodity derivatives as of December 31, 2018.



105







Embedded Derivatives

As discussed in Note 21 - Commitments and Contingencies, the ARM sales agreement contains minimum quantity commitments. Should the Company be unable to meet those minimum commitments, the agreement contains a two way make whole provision that allows for net settlement. As of December 31, 2019, the Company concluded it is no longer probable they will be able to make delivery of the minimum quantities specified in the agreement. The Company has, therefore recorded the fair value of the embedded derivative as of December 31, 2019. The net settlement feature for remaining future minimum commitment volumes are considered embedded derivatives that are recorded, with changes in fair value included in the Company’s consolidated statement of operations.

As of December 31, 2019, the derivative liability associated with the ARM sales agreement was approximately $3.2 million with $0.8 million recorded in current derivative instruments and $2.4 million recorded in long-term derivative instruments on the Company’s consolidated balance sheets.

As discussed in Note 11 - Long-Term Debt, the Second Lien Term Loan contained conversion features that were exercisable at the option of the lead lender thereunder or, in certain circumstances, the Company. The conversion features have been identified as embedded derivatives which (i) contain economic characteristics that are not clearly and closely related to the host contract, the Second Lien Term Loan, and (ii) are separate, stand-alone instruments with similar terms that would qualify as derivative instruments. As such, the conversion features were bifurcated and accounted for separately from the Second Lien Term Loan. The conversion features are recorded at fair value for each reporting period with changes in fair value included in the Company’s consolidated statement of operations for each reporting period.

As of December 31, 2018, the derivative liabilities associated with the Second Lien Term Loan were approximately $2.0 million. On March 5, 2019, the embedded derivative associated with the Second Lien Term Loan was written off against the gain on extinguishment of debt following the extinguishment of the Second Lien Term Loan on March 5, 2019, pursuant to the provisions of the 2019 Transaction Agreement (as defined in Note 11 - Long-Term Debt).

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 floor price over a variable market price), and costless collars (whereby, on the settlement date, the Company receives the excess, if any, of a variable market price over a fixed floor price up to a fixed ceiling price for a notional quantity of production).
  
Our hedging activities are intended to support oil and natural gas prices at targeted levels and manage exposure to oil and natural gas price fluctuations, as well as to meet our obligations under our Revolving Credit Agreement (as defined in Note 11 - Long-Term Debt). It is our policy to enter into derivative contracts only with counterparties that are creditworthy and competitive market makers. All of our derivatives are designated as unsecured. Certain of our derivative counterparties may require the posting of cash collateral under certain conditions. The Company does not enter into derivative contracts for speculative trading purposes.
 
All of our derivatives are accounted for as mark-to-market activities. Under Accounting Standard Codification (“ASC”) Topic 815, “Derivatives and Hedging,” these instruments are recorded on the Company’s 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. Because the Company has elected not to designate its current derivative contracts as cash flow hedges for accounting purposes, changes in the fair values of the derivatives are recognized in current earnings. 


106







The following table presents the Company’s derivative position for the production periods indicated as of December 31, 2019:
Description
 
 
 Notional Volume (Bbls/d)
 
Production Period
 
 Weighted Average Price ($/Bbl)
Oil Positions
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil Swaps
 
 
1,028

 
 January 2020 - December 2020
 
$
56.28

Oil Swaps
 
 
370

 
 January 2021 - December 2021
 
$
53.07

 
 
 
 
 
 
 
 
Basis Swaps (1)
 
 
1,500

 
 January 2020 - December 2020
 
$
(5.62
)
 
 
 
 
 
 
 
 
3 Way Collar
Floor sold price (put)
 
228

 
 January 2020 - December 2020
 
$
40.00

3 Way Collar
Floor purchase price (put)
 
228

 
 January 2020 - December 2020
 
$
50.00

3 Way Collar
Ceiling sold price (call)
 
228

 
 January 2020 - December 2020
 
$
59.60

3 Way Collar
Floor sold price (put)
 
80

 
 January 2021 - December 2021
 
$
37.50

3 Way Collar
Floor purchase price (put)
 
80

 
 January 2021 - December 2021
 
$
47.50

3 Way Collar
Ceiling sold price (call)
 
80

 
 January 2021 - December 2021
 
$
59.30

 
 
 
 
 
 
 
 
Oil Collar
Floor purchase price (put)
 
512

 
 January 2020 - December 2020
 
$
49.50

Oil Collar
Ceiling sold price (call)
 
512

 
 January 2020 - December 2020
 
$
63.87

Oil Collar
Floor purchase price (put)
 
742

 
 January 2021 - December 2021
 
$
50.00

Oil Collar
Ceiling sold price (call)
 
742

 
 January 2021 - December 2021
 
$
59.70

 
 
 
 
 
 
 
 
Description
 
 
Notional Volume (MMBtus/d)
 
Production Period
 
Weighted Average Price ($/MMBtu)
Natural Gas Positions
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gas Swaps
 
 
4,557

 
 January 2020 - December 2020
 
$
2.57

Gas Swaps
 
 
4,184

 
 January 2021 - March 2021
 
$
2.77

 
 
 
 
 
 
 
 
3 Way Collar
Floor sold price (put)
 
563

 
 January 2020 - December 2020
 
$
1.60

3 Way Collar
Floor purchase price (put)
 
563

 
 January 2020 - December 2020
 
$
2.10

3 Way Collar
Ceiling sold price (call)
 
563

 
 January 2020 - December 2020
 
$
3.00

3 Way Collar
Floor sold price (put)
 
133

 
 January 2021 - December 2021
 
$
1.65

3 Way Collar
Floor purchase price (put)
 
133

 
 January 2021 - December 2021
 
$
2.15

3 Way Collar
Ceiling sold price (call)
 
133

 
 January 2021 - December 2021
 
$
3.05

Gas Collar
Floor purchase price (put)
 
2,748

 
 January 2020 - December 2020
 
$
2.55

Gas Collar
Ceiling sold price (call)
 
2,748

 
 January 2020 - December 2020
 
$
3.07

Gas Collar
Floor purchase price (put)
 
4,464

 
 January 2021 - December 2021
 
$
2.20

Gas Collar
Ceiling sold price (call)
 
4,464

 
 January 2021 - December 2021
 
$
2.97


(1) 
The weighted average price under these basis swaps is the fixed price differential between the index prices of the Midland WTI and the Cushing WTI.


107







The table below summarizes the Company’s net gain (loss) on commodity derivatives for the year ended December 31, 2019 and 2018:
 
Year Ended December 31,
 
2019
 
2018
 
(in thousands)
Unrealized gain (loss) on unsettled derivatives
$
(5,575
)
 
$
1,977

Net settlements paid on derivative contracts
(3,214
)
 
(2,742
)
Net settlements receivable (payable) on derivative contracts
(196
)
 
820

Net gain (loss) on commodity derivatives
$
(8,985
)
 
$
55

  
The following information summarizes the gross fair values of derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Company’s consolidated balance sheets as of December 31, 2019 and as of December 31, 2018:
 
As of December 31, 2019
 
Gross Amount of Recognized Assets and Liabilities
 
Gross Amounts Offset in the Consolidated Balance Sheets
 
Net Amounts Presented in the Consolidated Balance Sheets
 
(In thousands)
Offsetting Derivative Assets:
 
 
 
 
 
Current assets
$
1,009

 
$
(582
)
 
$
427

Long-term assets
359

 
(172
)
 
187

Total assets
$
1,368

 
$
(754
)
 
$
614

Offsetting Derivative Liabilities:
 
 
 
 
 
Current liabilities
$
(4,827
)
 
$
582

 
$
(4,245
)
Current embedded derivative liabilities
(799
)
 

 
(799
)
Long-term commodity derivative liabilities
(172
)
 
172

 

Long-term embedded derivative liabilities
(2,439
)
 

 
(2,439
)
Total liabilities
$
(8,237
)
 
$
754

 
$
(7,483
)
 
 
 
 
 
 

 
As of December 31, 2018
 
Gross Amount of Recognized Assets and Liabilities
 
Gross Amounts Offset in the Consolidated Balance Sheets
 
Net Amounts Presented in the Consolidated Balance Sheets
 
(In thousands)
Offsetting Derivative Assets:
 
 
 
 
 
Current assets
$
4,122

 
$
(1,571
)
 
$
2,551

Long-term assets
1,854

 
(32
)
 
1,822

Total assets
$
5,976

 
$
(1,603
)
 
$
4,373

Offsetting Derivative Liabilities:
 
 
 
 
 
Current liabilities
$
(2,086
)
 
$
1,571

 
$
(515
)
Long-term commodity derivative liabilities
(2,766
)
 
32

 
(2,734
)
Long-term embedded derivative liabilities
(1,965
)
 

 
(1,965
)
Total liabilities
$
(6,817
)
 
$
1,603

 
$
(5,214
)
 

108







NOTE 10 - LEASES

Lease Recognition

The Company has entered into contractual lease arrangements to rent office space, compressors, drilling rigs and other equipment from third-party lessors. Right-of-use (“ROU”) assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make future lease payments arising from the lease. Operating lease ROU assets and liabilities are recorded at commencement date based on the present value of lease payments over the lease term. Lease payments included in the measurement of the lease liability include fixed payments and termination penalties or extensions that are reasonably certain to be exercised. Variable lease costs associated with leases are recognized when incurred and generally represent maintenance services provided by the lessor, allocable real estate taxes and local sales and business taxes. Leases with an initial term of 12 months or less are not recorded on the balance sheet. The Company recognizes lease expense on a straight-line basis over the lease term. The Company does not account for lease components separately from the non-lease components. The Company uses the implicit interest rate when readily determinable; however, most of the Company’s lease agreements do not provide an implicit interest rate. As such, at implementation and for new or modified leases subsequent to January 1, 2019, the Company uses its incremental borrowing rate based on the information available at commencement date of the contract in determining the present value of future lease payments. The incremental borrowing rate is calculated using a risk-free interest rate adjusted for the Company’s risk. Operating lease ROU assets also include any lease incentives received in the recognition of the present value of future lease payments. Certain of the Company’s leases may also include escalation clauses or options to extend or terminate the lease. These options are included in the present value recorded for the leases when it is reasonably certain that the Company will exercise that option. Lease expense for lease payments is recognized on a straight-line basis over the lease term.

The Company determines if an arrangement is or contains a lease at inception of the contract and records the resulting operating lease asset on the consolidated balance sheets as an asset, with offsetting liabilities recorded as a liability. The Company recognizes a lease in the consolidated financial statements when the arrangement either explicitly or implicitly involves property or equipment, the contract terms are dependent on the use of the property or equipment, and the Company has the ability or right to operate the property or equipment or to direct others to operate the property or equipment and receives greater than 10% of the economic benefits of the assets. As of December 31, 2019, the Company does not have any financing leases.

The Company has adopted the modified retrospective method for the new lease recognition rule. Therefore, prior periods are not presented as prior period amounts have not been adjusted under the modified retrospective. Refer to Note 3 - Basis of Presentation and Summary of Significant Accounting Policies for additional information.

The Company’s ROU assets and operating lease liabilities were included in the consolidated balance sheets as follows (in thousands):
 
 
December 31, 2019
Right of use assets:
 
 
Right of use assets - long-term (1)
 
$
1,722


 
 
Lease liabilities:
 
 
Lease liabilities - current (2)
 
$
412

Lease liabilities - long-term (3)
 
1,323

     Total lease liabilities
 
$
1,735

(1) Right of use assets - long-term are included in other assets on the consolidated balance sheets.
(2) Lease liabilities - current are included in accrued liabilities and other on the consolidated balance sheets.
(3) Lease liabilities - long-term are included in long-term derivatives instruments and other non-current liabilities on the consolidated balance sheets.

During the second quarter of 2019, the Company canceled a long-term drilling rig lease, within the terms of the agreement, which resulted in the write-off of the related lease liability and ROU asset of $5.4 million.

During the third quarter of 2019, the Company entered into a new long-term drilling rig lease which resulting in a lease liability and ROU asset of $10.8 million. During the 4th quarter of 2019, the Company canceled the long-term drilling rig lease, within the terms of the agreement, which resulted in the write-off of the related lease liability and ROU asset of $10.4 million.

109







Lease costs represent the straight line lease expense of ROU assets, short-term leases, and variable lease costs. The components of lease cost were classified as follows (in thousands):
 
Year Ended December 31, 2019
Fixed lease costs
$
5,084

Short-term lease costs
1,096

Variable lease costs
575

Total lease costs
$
6,755


Lease Cost included in the Consolidated Financial Statements
 
Year Ended December 31, 2019
Oil and natural gas properties, full cost method of accounting, net (1)
 

Total lease costs capitalized
 
$
5,688

 
 
 
Production costs
 
593

General and administrative
 
474

Total lease costs expensed
 
1,067

Total lease costs
 
$
6,755

(1) Represents short-term lease capital expenditures related to drilling rigs for the year ended December 31, 2019.

During the year ended December 31, 2019, the following cash activities were associated with the Company’s leases as follows (in thousands):
Cash paid for amounts included in the measurement of operating lease liabilities:
 
 
Operating cash flows from operating leases
 
$
222

Investing cash flows from operating leases
 
$
4,768


As of December 31, 2019, the weighted average lease term and discount rate related to the Company’s remaining leases were as follows:
Lease term and discount rate
Weighted-average remaining lease term (years)
 
4.45

Weighted-average discount rate
 
5.3
%

As of December 31, 2019, minimum future payments, including imputed interest, for long-term operating leases under the scope of ASC Topic 842, “Leases”, were as follows (in thousands):
Year
 
Amount
2020
 
$
477

2021
 
425

2022
 
353

2023
 
379

2024
 
315

After 2024
 

Less: the effects of discounting
 
(214
)
Present value of lease liabilities
 
$
1,735



110







As of December 31, 2018, minimum future payments, including imputed interest, for long-term operating leases under the scope of ASC Topic 840, “Leases”, were as follows (in thousands):
Year
 
Amount
2019
 
$
7,586

2020
 
66

2021
 

2022
 

2023
 

After 2023
 

Total lease commitment
 
$
7,652


NOTE 11 - LONG-TERM DEBT
 
 
December 31,
 
 
2019
 
2018
 
 
(In thousands)
8.25% Second Lien Term Loan, due 2021, net of debt issuance costs and debt discount
 
$

 
$
82,804

Revolving Credit Agreement, due October 2023
 
115,000

 
75,000

Total long-term debt
 
$
115,000

 
$
157,804

Less: current portion
 
(115,000
)
 

Total long-term debt, net of current portion
 
$

 
$
157,804

 
Revolving Credit Agreement

On October 10, 2018, the Company entered into a five-year, $500.0 million senior secured revolving credit agreement by and among the Company, as borrower, certain subsidiaries of the Company, as guarantors (the “Guarantors”), BMO Harris Bank, N.A., as administrative agent, and the lenders party thereto (the “Revolving Credit Agreement”). The Revolving Credit Agreement provides for a senior secured reserves based revolving credit facility with an initial borrowing base of $95.0 million. The borrowing base is subject to semiannual re-determinations in May and November of each year. In December 2018, the borrowing base was increased to $108.0 million in connection with our scheduled borrowing base re-determination. On March 5, 2019, the Company’s borrowing base under the Revolving Credit Agreement was increased from $108.0 million to $125.0 million, as the result of an acceleration of the scheduled May 2019 borrowing base redetermination pursuant to the First Amendment (as defined below). As provided in the Third Amendment (as defined below) and as a result of the Asset Sales (as defined in Note 5 - Acquisitions and Divestitures), in July 2019, the borrowing base was decreased to $115.0 million. As provided for in the Seventh Amendment and as a result of a decrease in commodity prices, on January 17, 2020, the borrowing base was decreased to $90.0 million. The reduction in the borrowing base resulted in a borrowing base deficiency as of January 17, 2020, of $25.0 million. We have made scheduled repayments of $17.3 million and the remaining $7.8 million is due on June 5, 2020.

Borrowings under the Revolving Credit Agreement bear interest at a floating rate of either LIBOR or a specified base rate plus a margin determined based upon the usage of the borrowing base. The Company is required to pay a commitment fee of 0.5% per annum on any unused portion of the borrowing base. The Company’s obligations under the Revolving Credit Agreement are secured by first priority liens on substantially all of the Company’s and the Guarantors’ assets and are unconditionally guaranteed by each of the Guarantors.

As of December 31, 2019, outstanding borrowings under the Revolving Credit Agreement were $115.0 million. The Revolving Credit Agreement also provides for issuance of letters of credit in an aggregate amount of up to $5.0 million. As of December 31, 2019, we were fully drawn against the borrowing base under our Revolving Credit Agreement, with $115.0 million of indebtedness outstanding under our Revolving Credit Agreement, classified as current liability due to uncertainty of the Company’s ability to meet debt covenants over the next twelve months.

The Company capitalizes certain direct costs associated with the debt issuance under the Revolving Credit Agreement and amortizes such costs over the term of the debt instrument. The deferred financing costs related to the Revolving Credit Agreement are classified in assets. For the year ended December 31, 2019 and 2018, the Company amortized debt issuance costs associated with the Revolving Credit Agreement of $0.8 million and $2.2 million, respectively. As of December 31, 2019, the

111







Company had $2.6 million of unamortized deferred financing costs in other current assets. As of December 31, 2018, the Company had $0.5 million and $1.7 million of unamortized deferred financing costs in other current assets and non-current assets, respectively.

The Revolving Credit Agreement matures on October 10, 2023. Borrowings under the Revolving Credit Agreement are subject to mandatory repayment in certain circumstances, including upon certain asset sales and debt incurrences or if a borrowing base deficiency occurs. The Company also may voluntarily repay borrowings from time to time and, subject to the borrowing base limitation and other customary conditions, may re-borrow amounts that are voluntarily repaid. Mandatory and voluntary repayments generally will be made without premium or penalty.

Pursuant to the Fourteenth Amendment to the Revolving Credit Agreement, our next borrowing base redetermination is scheduled to occur on or about June 5, 2020. If the borrowing base is further reduced by the lenders in connection with this redetermination, we will be required to repay borrowings in excess of the borrowing base or eliminate the borrowing base deficiency by pledging additional oil and natural gas properties to secure our obligations under the Revolving Credit Agreement. Under the Revolving Credit Agreement, we have the option to affect such repayment either in full within 30 days after the redetermination or in monthly installments over a six-month period after the redetermination.

The Revolving Credit Agreement contains certain customary representations and warranties and affirmative and negative covenants, including covenants relating to: maintenance of books and records; financial reporting and notification; compliance with laws; maintenance of properties and insurance; and limitations on incurrence of indebtedness, liens, fundamental changes, international operations, asset sales, certain debt payments and amendments, restrictive agreements, investments, dividends and other restricted payments and hedging. It also requires the Company to maintain a ratio of Total Debt to EBITDAX (each as defined in the Revolving Credit Agreement) (the “Leverage Ratio”) of not more than 4.00 to 1.00 and a ratio of Current Assets to Current Liabilities (each as defined in the Revolving Credit Agreement) (the “Current Ratio”) of not less than 1.00 to 1.00 as of the last day of each fiscal quarter.

Compliance with the Current Ratio and Leverage Ratio covenants in future periods depends on our ability to keep wells online and consistently flowing to sales, commodity prices, our ability to control costs, and if necessary, our ability to complete sales of non-core assets or access other sources of capital to reduce indebtedness. However, our future cash flows, and consequently our EBITDAX, are subject to a number of variables, including uncertainty in forecasted production volumes and commodity prices, and we may not be able to complete sales of non-core assets or access other sources of capital on acceptable terms or at all. As of December 31, 2019, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants. Pursuant to the Twelfth Amendment, the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants as of December 31, 2019. 

As of March 31, 2020, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants. Pursuant to the Fourteenth Amendment (as defined in Note 11 - Long-Term Debt), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants as of March 31, 2020. As the Company is not expecting to be able to meet future covenants without obtaining additional sources of liquidity, the outstanding amount on our Revolving Credit Agreement as of December 31, 2019 has been classified as current. See Note 2 - Liquidity and Going Concern, for additional information.

The Revolving Credit Agreement also provides for events of default, including failure to pay any principal, interest or other amounts when due, failure to perform or observe covenants, cross-default on certain outstanding debt obligations, inaccuracy of representations and warranties, certain Employee Retirement Income Security Act or “ERISA” events, change of control, the security documents or guaranty ceasing to be effective, and bankruptcy or insolvency events, subject to customary cure periods. Amounts owed by the Company under the Revolving Credit Agreement could be accelerated and become immediately due and payable following the occurrence of an event of default.

The Revolving Credit Agreement also provides for the Company to have and maintain Swap Agreements (as defined in the Revolving Credit Agreement) in respect of crude oil and natural gas, on not less than 75% of the projected production from proved reserves classified as “Developed Producing Reserves” attributable to the oil and natural gas properties of the Company, as reflected in the most recently delivered reserves report, for a period through at least 24 months after the end of each applicable quarter. For further information on our hedges, see Note 9 - Derivatives. Pursuant to the Twelfth Amendment, the Company obtained a waiver from the requisite lenders of the requirement to comply with certain hedging obligations set forth in the Credit Agreement until the quarter ending June 30, 2020.


112







First Amendment and Waiver to Revolving Credit Agreement

On March 1, 2019, the Company entered into a First Amendment and Waiver (the “First Amendment”) to the Revolving Credit Agreement. Among other matters, the First Amendment provided for the acceleration of the scheduled May 2019 redetermination of the borrowing base described above, which became effective on March 5, 2019 upon closing of the transactions contemplated by the 2019 Transaction Agreement (as defined below), including the satisfaction in full, as described below, of the Second Lien Term Loan under the Second Lien Credit Agreement (as defined below). The First Amendment also provides for the July 2019 scheduled redetermination of the borrowing base described above.

In addition, the First Amendment provided for a limited waiver of compliance by the Company with the Leverage Ratio covenant in the Revolving Credit Agreement as of December 31, 2018. Further, in connection with the satisfaction in full of the Second Lien Term Loan and the termination of the Second Lien Credit Agreement, the First Amendment amended the maturity date provisions of the Revolving Credit Agreement to eliminate any springing maturity under the Revolving Credit Agreement tied to the maturity of the Second Lien Credit Agreement, resulting in a fixed maturity date under the Revolving Credit Agreement of October 10, 2023. The First Amendment also effected certain other ministerial and conforming amendments to the Revolving Credit Agreement related to the transactions contemplated by the 2019 Transaction Agreement and required payment by the Company to the lenders of customary fees.

Second Amendment and Waiver to Revolving Credit Agreement

On May 6, 2019, the Company entered into a Second Amendment and Waiver (the “Second Amendment”) to the Revolving Credit Agreement, pursuant to which the requisite lenders under the Revolving Credit Agreement waived compliance by the Company with the Current Ratio covenant as of March 31, 2019 in exchange for a customary consent fee. Additionally, the Second Amendment provided for a 25-basis point increase in the interest rate margin applicable to loans under the Revolving Credit Agreement if the Company’s Leverage Ratio is equal to or greater than 3.00 to 1.00. The Second Amendment also provides that if the Company has available cash and cash equivalents (subject to certain carveouts) in excess of $10 million for a period of at least five consecutive business days, then it must prepay the loans under the Revolving Credit Agreement in the amount of such excess.

Third Amendment and Waiver to Revolving Credit Agreement

On July 26, 2019, the Company entered into a Third Amendment (the “Third Amendment”) to the Revolving Credit Agreement, pursuant to which the requisite required lenders under the Revolving Credit Agreement agreed to reduce the borrowing base to $115 million from $125 million as a part of the scheduled July 1, 2019 redetermination and as a result of the Asset Sales; to give pro forma effect to the Asset Sales for the calculation of EBITDAX, Total Debt, and Current Liabilities at June 30, 2019; and, subject to the consummation of the Asset Sales completed on July 31, 2019 and the required use of the proceeds, to amend the Current Ratio to be not less than 0.85 to 1.00 on September 30, 2019, rather than the minimum Current Ratio of 1.00 to 1.00 required otherwise. Additionally, the Third Amendment provides for, among other things, an increase in the required amount hedged to 75% of projected production from proved reserves classified as “Developed Producing Reserves”. The Third Amendment also effected certain other ministerial changes to the Revolving Credit Agreement and required payment by the Company to the lenders of customary fees.

Fourth Amendment and Waiver to Revolving Credit Agreement

On November 5, 2019, the Company entered into a Fourth Amendment and Waiver (the “Fourth Amendment”) to the Revolving Credit Agreement, pursuant to which, among other matters, the requisite lenders under the Revolving Credit Agreement waived compliance by the Company with the Leverage Ratio covenant as of September 30, 2019 in exchange for a customary consent fee. Additionally, the Fourth Amendment modified the Leverage Ratio for future periods by modifying the manner in which EBITDAX is calculated for the periods ending December 31, 2019, March 31, 2020 and June 30, 2020 such that EBITDAX is calculated on an annualized basis for those periods, excluding quarterly periods ended prior to December 31, 2019. The Fourth Amendment also (1) requires the Company to use 100% of net cash proceeds from dispositions to repay borrowings until completion of the scheduled November 1, 2019 redetermination or during a borrowing base deficiency, (2) added completion of the scheduled November 1, 2019 redetermination as a condition precedent to future borrowings and (3) limits certain exceptions to certain of the negative covenants under the Revolving Credit Agreement during the period from the date of the Fourth Amendment to the date on which annual financial statements for the fiscal year ending December 31, 2019 are delivered.

113








Fifth Amendment and Waiver to Revolving Credit Agreement
 
On November 27, 2019, the Company entered into a Fifth Amendment (the “Fifth Amendment”) to the Revolving Credit Agreement dated as of October 10, 2018 which provides that the semi-annual redetermination of the borrowing base under the Revolving Credit Agreement previously scheduled to occur on or about November 1, 2019 (the “Fall 2019 Scheduled Redetermination”) will instead occur on December 16, 2019. Additionally, among other matters, the Fifth Amendment shortened the period over which the Company may repay in installments any borrowing base deficiency that may exist as a result of the Fall 2019 Scheduled Redetermination, as described below.

Under the Revolving Credit Agreement, a borrowing base deficiency will occur if the amounts outstanding under the Revolving Credit Agreement exceed the borrowing base then in effect. If a borrowing base deficiency occurs, the Company is required to repay borrowings in excess of the borrowing base or eliminate the borrowing base deficiency by pledging additional oil and natural gas properties to secure its obligations under the Revolving Credit Agreement. The Company has the option to effect such repayment either (1) in full within 30 days after the redetermination or (2) in monthly installments over a period of, except as amended by the Fifth Amendment, six months, commencing 30 days after the redetermination. The Fifth Amendment provides that, for a borrowing base deficiency that exists as a result of the Fall 2019 Scheduled Redetermination only, the period over which the Company may repay the amount of the deficiency in installments will be four months, rather than six months, commencing 30 days after the redetermination.

Sixth Amendment and Waiver to Revolving Credit Agreement

On December 16, 2019, the Company entered into a Sixth Amendment (the “Sixth Amendment”) to the Revolving Credit Agreement which provides that the semi-annual redetermination of the borrowing base under the Revolving Credit Agreement previously scheduled to occur on or about December 16, 2019 (the “Fall 2019 Scheduled Redetermination”) will instead occur on or about January 14, 2020. Additionally, among other matters, the Sixth Amendment provides that, if any borrowing base deficiency exists as a result of the Fall 2019 Scheduled Redetermination, the date on which the initial payment is due to cure such deficiency is the first business day after such deficiency, rather than 30 days after such deficiency.

Seventh Amendment to Revolving Credit Agreement

On January 17, 2020, the Company entered into a Seventh Amendment (the “Seventh Amendment”) to the Revolving Credit Agreement. The Seventh Amendment provided for the January 14, 2020 redetermination of the borrowing base under the Revolving Credit Agreement (the “Scheduled Redetermination”). As so redetermined, the borrowing base has been set at $90 million. As a result of the Scheduled Redetermination, a borrowing base deficiency in the amount of $25 million existed under the Revolving Credit Agreement (the “Borrowing Base Deficiency”). The Seventh Amendment required repayment of the Borrowing Base Deficiency in four equal monthly installments, with the first payment of $6.25 million scheduled to occur on January 24, 2020.

Eighth Amendment to Revolving Credit Agreement

On January 23, 2020, the Company entered into an Eighth Amendment (the “Eighth Amendment”) to the Revolving Credit Agreement. The Eighth Amendment, among other things, amended the Revolving Credit Agreement to provide that the due date for the first Installment Payment was extended from January 24, 2020 to February 7, 2020 and that the due dates for the subsequent Installment Payments are February 14, 2020, March 16, 2020 and April 14, 2020.

Ninth Amendment to Revolving Credit Agreement

On February 6, 2020, the Company entered into an Ninth Amendment (the “Ninth Amendment”) to the Revolving Credit Agreement. The Ninth Amendment amended the Revolving Credit Agreement to provide that the due date for the first Installment Payment is extended from February 7, 2020 to February 18, 2020 and the due date for the second Installment Payment is extended from February 14, 2020 to February 18, 2020. The due dates for the two subsequent Installment Payments remain March 16, 2020 and April 14, 2020.


114







Tenth Amendment to Revolving Credit Agreement
    
On February 14, 2020, the Company entered into an Tenth Amendment (the “Tenth Amendment”) to the Revolving Credit Agreement. The Tenth Amendment amended the Revolving Credit Agreement to provide that the due date for the first two Installment Payments is extended from February 18, 2020 to February 28, 2020 and the due dates for the two subsequent Installment Payments remain March 16, 2020 and April 14, 2020.

Eleventh Amendment to Revolving Credit Agreement

On March 13, 2020, the Company entered into an Eleventh Amendment (the “Eleventh Amendment”) to the Revolving Credit Agreement. The Eleventh Amendment amended the Revolving Credit Agreement to extend the due date for the $1.50 million installment of the Borrowing Base Deficiency from March 16, 2020 to March 30, 2020. The due date for the final installment of the Borrowing Base Deficiency remains April 14, 2020.

Twelfth Amendment to Revolving Credit Agreement

On March 30, 2020, the Company entered into a Twelfth Amendment (the “Twelfth Amendment”) to the Revolving Credit Agreement. The Twelfth Amendment amended the Revolving Credit Agreement to, among other things extend the due date for the $1.50 million installment of the Borrowing Base Deficiency from March 30, 2020 to April 14, 2020. The due date for the final installment of the Borrowing Base Deficiency remains April 14, 2020. The lenders under the Revolving Credit Agreement also waived the requirement under the Revolving Credit Agreement that the Company comply with a leverage ratio and a current ratio, in each case, as of December 31, 2019, and granted certain other waivers, including the requirement to comply with certain hedging obligations set forth in the Revolving Credit Agreement until June 30, 2020. Additionally, the lenders consented to an extension of an additional 45 days for the Company to provide its audited annual financial statements for the fiscal year ended December 31, 2019, and waived the requirement that such financial statements be delivered without a “going concern” or like qualification or exception.

Thirteenth Amendment to Revolving Credit Agreement
    
On April 14, 2020, the Company entered into a Thirteenth Amendment (the “Thirteenth Amendment”) to the Revolving Credit Agreement. The Thirteenth Amendment amended the Revolving Credit Agreement to extend the due date for the final $7.75 million installment of the Borrowing Base Deficiency from April 14, 2020 to April 21, 2020.

Fourteenth Amendment to Revolving Credit Agreement

On April 21, 2020, the Company entered into a Fourteenth Amendment (the “Fourteenth Amendment”) to the Revolving Credit Agreement. The Fourteenth Amendment, among other things, amended the Revolving Credit Agreement to extend the due date for the final $7.75 million installment of the Borrowing Base Deficiency from April 21, 2020 to June 5, 2020. The lenders under the Revolving Credit Agreement also waived the requirement under the Revolving Credit Agreement that the Company comply with a leverage ratio and a current ratio, in each case, as of March 31, 2020. Additionally, the lenders consented to defer the timing of the scheduled spring redetermination of the borrowing base under the Revolving Credit Agreement from on or about May 1, 2020 to on or about June 5, 2020.

Second Lien Credit Agreement

On April 26, 2017, the Company entered into a second lien credit agreement (the “Second Lien Credit Agreement”), by and among the Company, certain subsidiaries of the Company, as guarantors, Wilmington Trust, National Association, as administrative agent, and the lenders party thereto, consisting of certain private funds affiliated with Värde Partners, Inc. (“Värde”). The Second Lien Credit Agreement provided for convertible loans in an aggregate initial principal amount of up to $125 million in two tranches (together, the “Second Lien Term Loan”). The first tranche consisted of an $80 million term loan, which was fully drawn and funded on April 26, 2017. The second tranche consisted of up to $45 million in delayed-draw term loans, which was fully drawn and funded in October 2017. In November 2017, the Second Lien Credit Agreement was amended to increase the amount available for borrowing under the second tranche of the Second Lien Term Loan by $25 million, and the additional $25 million was fully drawn and funded in November 2017.

Prior to the satisfaction in full of the Second Lien Term Loan and the termination of the Second Lien Credit Agreement on March 5, 2019, as described below, the Second Lien Term Loan bore interest at a rate per annum of 8.25%, compounded quarterly in arrears and payable only in-kind by increasing the principal amount of the loan by the amount of the interest due on each interest payment date, and had a maturity date of April 26, 2021.

115








Each tranche of the Second Lien Term Loan was separately convertible at any time, in full and not in part, at the option of Värde, as lead lender, as follows: (i) 70% of the principal amount, together with accrued and unpaid interest and the make-whole premium on such principal amount, would convert into a number of shares of the Company’s 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 (ii) 30% of the principal amount, together with accrued and unpaid interest and the make-whole premium on such principal amount, would convert on a dollar for dollar basis into a new term loan. Additionally, if the closing price of the Company’s common stock on the principal exchange on which it was traded had been at least 150% of the Conversion Price then in effect for at least 20 of the 30 immediately preceding trading days, the Company had the option to convert the Second Lien Term Loan, in whole or in part, into a number of shares of its common stock determined by dividing the principal amount to be converted, together with accrued and unpaid interest on such principal amount, by the Conversion Price.

On October 10, 2018, the Company entered into a transaction agreement (the “2018 Transaction Agreement”) by and among the Company and certain private funds affiliated with Värde that were lenders under the Second Lien Credit Agreement (collectively, the “Värde Parties”), pursuant to which, among other matters, the Company issued to the Värde Parties (i) an aggregate of 5,952,763 shares of its common stock and (ii) 39,254 shares of a newly created series of preferred stock of the Company, designated as “Series D 8.25% Convertible Participating Preferred Stock”, as consideration for the reduction by approximately $56.3 million of the outstanding principal amount of the Second Lien Term Loan under the Second Lien Credit Agreement, together with accrued and unpaid interest and the make-whole amount thereon totaling approximately $11.9 million.

On March 5, 2019, the Company entered into a transaction agreement (the “2019 Transaction Agreement”) by and among the Company and the Värde Parties pursuant to which, among other matters, the Company issued to the Värde Parties shares of two new series of its preferred stock and shares of its common stock, as consideration for the termination of the Second Lien Credit Agreement and the satisfaction in full, in lieu of repayment in cash, of the Second Lien Term Loan. Specifically, in exchange for satisfaction of the outstanding principal amount of the Second Lien Term Loan, accrued and unpaid interest thereon and the make-whole amount totaling approximately $133.6 million (the “Second Lien Exchange Amount”), the Company issued to the Värde Parties:

an aggregate of 55,000 shares of a newly created series of preferred stock of the Company, designated as “Series F 9.00% Participating Preferred Stock” (the “Series F Preferred Stock”), corresponding to $55 million of the Second Lien Exchange Amount based on the aggregate initial Stated Value (as defined in Note 15 - Preferred Stock) of the shares of Series F Preferred Stock;

an aggregate of 60,000 shares of a newly created series of preferred stock of the Company, designated as “Series E 8.25% Convertible Participating Preferred Stock” (the “Series E Preferred Stock”), corresponding to $60 million of the Second Lien Exchange Amount based on the aggregate initial Stated Value (as defined in Note 15 - Preferred Stock) of the shares of Series E Preferred Stock; and

9,891,638 shares of common stock, corresponding to approximately $18.6 million of the Second Lien Exchange Amount, based on the closing price of the Company’s common stock on the NYSE American on March 4, 2019 of $1.88.

Subsequent to this transaction, the Company’s long-term debt consists solely of borrowings under the Revolving Credit Agreement.

As a result of the satisfaction in full of the Second Lien Term Loan pursuant to the 2019 Transaction Agreement, the Company recorded a gain on extinguishment of debt of $7.1 million, which was recorded as an increase in additional paid in capital due to the Värde Parties, being existing shareholders of the Company.


116







Interest Expense
 
The components of interest expense are as follows (in thousands) for the year ended December 31, 2019 and 2018:
 
Year Ended December 31,
 
2019
 
2018
Interest on debt
$
6,488

 
$
2,975

Net revenue payments on financing arrangement
888

 

Paid-in-kind interest on term loans
1,590

 
12,213

Amortization of debt financing costs
803

 
3,241

Amortization of discount on term loans
1,657

 
14,398

Total
$
11,426

 
$
32,827

   
NOTE 12 - LONG-TERM DEFERRED REVENUE LIABILITIES AND OTHER LONG-TERM LIABILITIES

 
December 31,
 
2019
 
2018
 
(in thousands)
Long-term deferred revenue liabilities
$
36,920

 
$
52,500

Long-term deferred proceeds, WLR agreement
13,061

 

Long-term deferred proceeds, WLWI agreement
23,768

 

Other

 
13

Total long-term deferred revenue liabilities and other long-term liabilities
$
73,749

 
$
52,513


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 and a contract operating and right of first refusal agreement with SCM Water, LLC (“SCM Water”), a subsidiary of Salt Creek Midstream, LLC (“SCM”). The water gathering agreement complements 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 to construct, maintain and operate the water gathering system will be fully funded by SCM Water and will be designed to accommodate all water produced by the Company’s operations. Pursuant to the contract operating agreement, the Company will act as contract operator of SCM Water’s salt water disposal wells.

Additionally, the Company 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.

On March 7, 2019, SCM Water exercised its option to purchase the Company’s existing water infrastructure. The Company determined that approximately $11.7 million of the upfront payments were attributable to the sale of the water infrastructure and right-of-way/easement, and recorded the exercise of the option as a reduction of deferred liabilities and a reduction of oil and natural gas properties.

The Company is actively working on permitting additional SWD well locations. The Company anticipates that the majority of its water will eventually be disposed of 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 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 an area right-of-way/easement, and the water gathering agreement provided that the Company would receive an additional $2.5 million bonus upon hitting the target of 40,000 barrels per day of produced water. The Company completed its drilling obligation and recognized the prefunded drilling bonus of $5.0 million as a reduction of deferred liabilities and a reduction of oil and natural gas properties as the deferred payment was attributable to the sale of the water infrastructure.


117







On March 11, 2019, the Company, SCM Water, and ARM Energy Management, LLC (“ARM”), a related company to SCM Water, agreed to amend the terms of the previously negotiated water gathering and disposal agreement and entered into a new crude oil sales contract (See Note 7 - Revenue and Note 21 - Commitments and Contingencies). Under the terms of such agreements, the Company agreed to an increase in salt water disposal rates in exchange for more favorable pricing differentials on the crude oil sales contract, modification on the minimum quantities of crude oil required under the crude oil sales contract, an upfront payment of $2.5 million and the elimination of the potential bonus for hitting a target of 40,000 barrels of produced water per day. The Company determined that the upfront $2.5 million payment was primarily attributable to the crude oil sales contract, and the Company recorded the $2.5 million payment as deferred revenues and will recognize it in income ratably as the crude oil is sold.

Crude Oil Gathering Agreement and Option Agreement

On May 21, 2018, the Company entered into a crude oil gathering agreement and option agreement with 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 under a tariff arrangement 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. 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 payment of $35.0 million, which was recorded in long-term deferred revenue.
Asset Disposition Accounted for as a Financing Arrangement

As a result of certain repurchase rights, as discussed more fully in Note 5 - Acquisitions and Divestitures, the agreements with WLR and WLWI do not meet the criteria for a sale and are accounted for as a financing arrangement under ASC 470. The net proceeds of the transaction of $39.0 million are included in long-term deferred revenue and other long-term liabilities on the Company’s consolidated balance sheet as of December 31, 2019. As a result of the transaction, the net revenue payments of $0.9 million for the year ended December 31, 2019 are included in interest expense on the Company’s consolidated statements of operations (see Note 5 - Acquisitions and Divestitures).


118








NOTE 13 - RELATED PARTY TRANSACTIONS
 
During the year ended December 31, 2019 and 2018, the Company was engaged in the following transactions with certain related parties:  
 
 
 
 
As of December 31,
Related Party
 
Transactions
 
2019
 
2018
 
 
 
 
(In thousands)
Directors and Officers:
 
 
 
 

 
 

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

 
$
10,705

 
 
Receivable balance outstanding for operating costs associated with VPD's producing wells
 

 
1,843

 
 
ImPetro Operating, LLC, a wholly-owned subsidiary of the Company is the operator for two of VPD's producing wells and VPD reimbursed the Company for operating charges
 

 
44

 
 
Revenue payable balance due as of December 31, 2019 for revenue associated with VPD's producing wells
 
(157
)
 

 
 
Payable to WLR for net proportionate share of production
 
(161
)
 

 
 
Payable to WLWI for net proportionate share of production
 
(526
)
 
 
 
 
Asset disposition accounted for as a financing arrangement
 
(36,833
)
 

 
 
Total:
 
$
(37,677
)
 
$
12,592

(1) Värde was the lead lender in the Company’s Second Lien Term Loan (see Note 11 - Long-Term Debt), is a major stockholder of the Company, and also participated in various transactions in 2018 and 2019 (which such transactions included the issuance of preferred stock to Värde Parties) (see Note 15 - Preferred Stock).

Additionally, on March 5, 2019, pursuant to the 2019 Transaction Agreement and the related payoff letter, the Company agreed to issue to the Värde Parties shares of two new series of its preferred stock and shares of its common stock, as consideration for the termination of the Second Lien Credit Agreement with the Värde Parties and the satisfaction in full, in lieu of repayment in cash, of the Second Lien Term Loan under the Second Lien Credit Agreement. See Note 11 - Long-Term Debt and Note 15 - Preferred Stock for additional information.

On July 31, 2019, the Company entered into two agreements with affiliates of Värde for the sale of an overriding royalty interest and a non-operated working interest in undeveloped assets. WLR’s proportionate share of production of $0.4 million and WLWI’s proportionate share of production, net of production costs, of $0.5 million for the year ended December 31, 2019 is included in interest expense on the Company’s consolidated statements of operations. None of the properties included in the WI Agreement were producing as of December 31, 2019. See Note 5 - Acquisitions and Divestitures for additional information.

On August 16, 2019, the company entered into an agreement with an affiliate of Värde to repurchase the overriding royalty interest for the New Mexico acreage sold. See Note 5 - Acquisitions and Divestitures for additional information.

On April 21, 2020, Värde Investment Partners, L.P., an affiliate of Värde Partners, Inc., became a lender under our Revolving Credit Agreement by acquiring, from a prior lender, loans and commitments under the Revolving Credit Agreement in the principal amount of approximately $25.7 million. The loans and commitments acquired by Värde Investment Partners, L.P. are subject to certain subordination provisions set forth in the Revolving Credit Agreement, as amended by the Fourteenth Amendment thereto dated April 21, 2020. For additional information regarding our Revolving Credit Agreement, as amended, see Note 11 - Long-Term Debt.


119







NOTE 14 - INCOME TAXES

The income tax provision (benefit) for the years ended December 31, 2019 and 2018 consisted of the following:
 
December 31,
 
2019
 
2018
 
(in thousands)
U.S. Federal:
 
 
 
Current
$

 
$

Deferred
(55,366
)
 
(7,496
)
State and local:
 
 
 
Current

 

Deferred
(4,220
)
 
509

 
(59,586
)
 
(6,987
)
Change in valuation allowance
59,586

 
6,987

Income tax provision
$

 
$


The tax effects of temporary differences that give rise to the Company’s deferred tax asset as of December 31, 2019 and 2018 consisted of the following:
 
December 31,
 
2019
 
2018
 
(In thousands)
Deferred tax assets:
 
 
 
Net operating loss carry-forward
$
31,992

 
$
27,568

Share based compensation
531

 
808

Abandonment obligation
761

 
541

Derivative instruments
1,526

 

Deferred revenue
15,863

 
11,630

Interest expense
4,540

 
3,804

Lease Liability
386



Property Basis
27,837



Accrued liabilities and other
144

 
85

Total deferred tax asset
83,580

 
44,436

Valuation allowance
(83,197
)
 
(23,611
)
Deferred tax asset, net of valuation allowance
383

 
20,825

 
 
 
 
Deferred tax liabilities:
 
 
 
Derivative instruments

 
249

Oil and natural gas properties and equipment

 
20,576

Right of use asset
383



Total deferred tax liability
383

 
20,825

Net deferred tax asset (liability)
$

 
$



120







Reconciliation of the Company’s effective tax rate to the expected U.S. federal tax rate is:
 
Year Ended December 31,
 
2019
 
2018
Effective federal tax rate
21
 %
 
21
 %
State tax rate, net of federal benefit
1
 %
 
2
 %
Change in fair value derivative liability
 %
 
296
 %
Debt discount amortization
 %
 
(73
)%
Change in rate
 %
 
(6
)%
Other permanent differences
 %
 
(6
)%
NOL true-up - §382 limitation
 %
 
(6
)%
Loss from early debt extinguishment
 %
 
(59
)%
Other
 %
 
(1
)%
Valuation allowance
(22
)%
 
(169
)%
Net
 %
 
 %

As of December 31, 2019 and 2018, the Company had net operating loss carry-forwards for federal income tax purposes of approximately $142.2 million and $127.5 million respectively, available to offset future taxable income. To the extent not utilized, federal net operating loss carry-forwards incurred prior to January, 1 2018 of $69.9 million will expire beginning in 2028 through 2037. Federal net operating loss carryforwards incurred after December 31, 2017 of $77.1 million have no expiration and can only be used to offset 80% of taxable income when utilized. A portion of the net operating loss of $142.2 million is subject to Section 382 limitations of utilization due to ownership changes of more than 50% which occurred in the prior tax years.  

In assessing the need for a valuation allowance on the Company’s deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon whether future book income is sufficient to reverse existing temporary differences that give rise to deferred tax assets, as well as whether future taxable income is sufficient to utilize net operating loss and credit carryforwards. Assessing the need for, or the sufficiency of, a valuation allowance requires the evaluation of all available evidence, both positive and negative. Negative evidence considered by management includes cumulative book and tax losses in recent years, no taxable income in available carryback years, and no tax planning strategies contemplated to realize the valued deferred tax assets.

As of December 31, 2019, and 2018, management assessed the available positive and negative evidence to estimate if sufficient future taxable income would be generated to use the Company’s deferred tax assets and determined that it is not more-likely-than-not that the deferred tax assets would be realized in the near future. Therefore, the Company recorded a full valuation allowance of approximately $83.2 million and $23.6 million on its deferred tax assets as of December 31, 2019 and 2018, respectively.

NOTE 15 - PREFERRED STOCK
 
Preferred Stock Issuances
 
On January 30, 2018, the Company entered into a Securities Purchase Agreement by and among the Company and the Värde Parties, pursuant to which, on January 31, 2018, the Company issued and sold to the Värde Parties 100,000 shares of a newly created series of preferred stock of the Company, designated as “Series C 9.75% Convertible Participating Preferred Stock” for a purchase price of $1,000 per share, or an aggregate of $100.0 million. The Series C 9.75% Convertible Participating Preferred Stock was subsequently re-designated as “Series C-1 9.75% Convertible Participating Preferred Stock” in connection with the transactions contemplated by the 2018 Transaction Agreement (as defined in Note 11 - Long-Term Debt) and as “Series C-1 9.75% Participating Preferred Stock” in connection with the transactions contemplated by the 2019 Transaction Agreement (as defined in Note 11 - Long-Term Debt) (as re-designated, the “Series C-1 Preferred Stock”).

Pursuant to the 2018 Transaction Agreement, on October 10, 2018, the Company issued and sold to the Värde Parties 25,000 shares of a newly created series of the Company’s preferred stock designated as “Series C-2 9.75% Convertible Participating Preferred Stock” for a purchase price of $1,000 per share, or an aggregate of $25.0 million. The Series C-2 9.75% Convertible Participating Preferred Stock was subsequently re-designated as “Series C-2 9.75% Participating Preferred Stock” in connection with the transactions contemplated by the 2019 Transaction Agreement (as re-designated, the “Series C-2 Preferred Stock” and, together with the Series C-1 Preferred Stock, the “Series C Preferred Stock”). Also pursuant to the 2018 Transaction Agreement, on October 10, 2018, the Company issued to the Värde Parties 39,254 shares of its Series D 8.25% Convertible Participating Preferred Stock. The Series D 8.25% Convertible Participating Preferred Stock was subsequently re-designated as “Series D

121







8.25% Participating Preferred Stock” in connection with the transactions contemplated by the 2019 Transaction Agreement (as re-designated, the “Series D Preferred Stock”).

Pursuant to the 2019 Transaction Agreement, on March 5, 2019, the Company issued to the Värde Parties (i) 60,000 shares of its Series E Preferred Stock and (ii) 55,000 shares of its Series F Preferred Stock.

Additionally, pursuant to the 2019 Transaction Agreement, on March 5, 2019, the Company issued to the Värde Parties an aggregate of 7,750,000 shares of its common stock, as consideration for the Värde Parties’ consent to the amendment of the terms of the Series C Preferred Stock and the Series D Preferred Stock to, among other things, eliminate the convertibility and voting rights of the Series C Preferred Stock and the Series D Preferred Stock. As a result of the transactions effected under the 2019 Transaction Agreement, the potential dilution of the Company’s common stockholders resulting from the conversion of convertible debt and convertible preferred stock was reduced from approximately 53.5 million shares of common stock (related to the Second Lien Term Loan, the Series C Preferred Stock and the Series D Preferred Stock) to approximately 24.0 million shares of common stock (related to the Series E Preferred Stock). Other than the Series E Preferred Stock, the Company has no convertible debt or convertible preferred stock outstanding following the closing of the transactions contemplated by the 2019 Transaction Agreement. The amendments to the terms of the Series C Preferred Stock also fixed the redemption price payable by the Company in connection with a redemption of the Series C Preferred Stock at price per share equal to (i) the Stated Value (as defined in the certificate of designation for the Series C Preferred Stock) multiplied by 125.0% plus (ii) accrued and unpaid dividends thereon and any other amounts payable by the Company in respect thereof. Prior to the amendments, the percentage specified in clause (i) above would have increased to 130.0% for a redemption of the Series C Preferred Stock effected after December 31, 2019.

As of December 31, 2019, the Company accounted for the Series C, D, E and F Preferred Stock at its initial fair value at closing of the 2019 Transaction Agreement, plus cumulative paid-in-kind dividends accrued subsequent to the closing of the transactions contemplated by the 2019 Transaction Agreement, under mezzanine equity in the consolidated balance sheet. The components of each series of preferred stock are summarized in the table below:
 
 
Series C Preferred Stock
 
Series D Preferred Stock
 
Series E Preferred Stock
 
Series F Preferred Stock
 
 
Number of Shares
 
Amount
 
Number of Shares
 
Amount
 
Number of Shares
 
Amount
 
Number of Shares
 
Amount
 
 
(In thousands, except shares)
Balance, January 1, 2019
 
125,000

 
$
132,296

 
39,254

 
$
40,729

 

 
$

 

 
$

Change in carrying value due to modification
 

 
(46,632
)
 

 
(15,056
)
 

 

 

 

Issuance of Preferred Stock in extinguishment of debt
 

 

 

 

 
60,000

 
62,115

 
55,000

 
46,682

Paid-in-kind dividends
 

 
13,639

 

 
3,409

 

 
4,170

 

 
4,179

Balance, December 31, 2019
 
125,000

 
$
99,303

 
39,254

 
$
29,082

 
60,000

 
$
66,285

 
55,000

 
$
50,861


Material Terms of the Series C Preferred Stock and Series D Preferred Stock
 Ranking. The Series D Preferred Stock ranks senior to the Series C Preferred Stock, and 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.
Stated Value. Each series of the Preferred Stock has a per share stated value of $1,000, subject to increase in connection with the payment of dividends in kind (the “Stated Value”).
Dividends. Holders of shares of 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 for the Series C Preferred Stock and 8.25% of the Stated Value for the Series D Preferred stock 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 the Preferred Stock will be entitled to participate in any dividends paid on the Common Stock on an as-converted basis.

122







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 “Series C Optional Redemption Amount”). The Company has the right to redeem the Series D 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 117.5%, plus (ii) accrued and unpaid dividends thereon and any other amounts payable by the Company in respect thereof (the “Series D optional Redemption Amount”). Each Series of the 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 Certificates of Designation) as described below.
     Change of Control. Upon the occurrence of a Change of Control (as defined in the Certificates of Designation), each holder of shares of Preferred Stock will have the option to:
cause the Company to redeem all of such holder’s shares of Preferred Stock for cash in an amount per share equal to (i) the applicable 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 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 Preferred Stock, subject to any adjustments to the applicable 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 D Preferred Stock will be entitled to receive, prior to any distributions on the Series C Preferred Stock, the Common Stock or other capital stock of the Company ranking junior to the Series D Preferred Stock, an amount per share of Series D Preferred Stock equal to the greater of (i) the Series D Optional Redemption Amount then in effect and (ii) the amount such holder would receive in respect of the number of shares of Common Stock into which such shares of Series D Preferred Stock is then convertible; and
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 applicable Series C 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. In addition to the Board designation rights described in the Certificate of Designation, holders of shares of 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 Preferred Stock will entitle the holder to a number of votes equal to (i) the applicable Stated Value as of the applicable record date or other determination date divided by (ii) (a) in the case of Series C-1 Preferred Stock, $4.42 (the closing price of the Common Stock on the NYSE American on January 30, 2018), and (b) in the case of Series C-2 Preferred Stock and Series D Preferred Stock, $4.41 (the closing price of the Common Stock on the NYSE American on October 9, 2018).

Description of the Series E Preferred Stock and Series F Preferred Stock

Ranking. The Series F Preferred Stock ranks senior to all of the other series of preferred stock of the Company, and the Series E Preferred Stock ranks senior to the Series D Preferred Stock and the Series C Preferred Stock, in each case with respect to dividends and rights on the liquidation, dissolution or winding up of the Company.

Stated Value. The Series E Preferred Stock and the Series F Preferred Stock have an initial per share stated value of $1,000, subject to increase in connection with the payment of dividends in kind as described below (the “Stated Value”).
Dividends. Holders of the Series E Preferred Stock and Series F 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, 2019, at an annual rate of 8.25% of the Stated Value for the Series E Preferred Stock and at an annual rate of 9.00% of the Stated Value for the Series F Preferred Stock. However, if, on any dividend payment date occurring after April 26, 2021, dividends due on such dividend payment date on the Series E Preferred Stock or the Series F Preferred Stock are not paid in full in cash, the annual dividend rate for the dividends due on such dividend payment date (but not for any future dividend payment date on which dividends are paid in full in cash) will be 9.25% on the Series E Preferred Stock and 10.00% on the Series

123







F Preferred Stock. 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 cumulative preferential dividends, holders of the Series E Preferred Stock and Series F Preferred Stock are entitled to participate in dividends paid on the Company’s common stock. For holders of the Series E Preferred Stock, such participation will be based on the number of shares of common stock such holders would have owned if all shares of Series E Preferred Stock had been converted to common stock at the Conversion Rate (as defined below) then in effect. For holders of the Series F Preferred Stock, such participation will be based on the dividends such holders would have received if, immediately prior to the applicable record date, each outstanding share of Series F Preferred Stock had been converted into a number of shares of common stock equal to the Series F Optional Redemption Price (as defined below) divided by $7.00, subject to proportionate adjustment in connection with stock splits and combinations, dividends paid in stock and similar events affecting the outstanding common stock (regardless of the fact that shares of the Series F Preferred Stock are not convertible into common stock).
 
Optional Redemption. Subject to the limitations described below and certain additional limitations on partial redemptions, the Company has the right to redeem the Series E Preferred Stock, in whole or in part, at a price per share equal to (i) the Stated Value then in effect multiplied by (A) 110% if the optional redemption date occurs on or prior to March 5, 2020, (B) 105% if the optional redemption date occurs after March 5, 2020 and on or prior to March 5, 2021 and (C) 100% if the optional redemption date occurs after March 5, 2021, plus (ii) accrued and unpaid dividends thereon and any other amounts payable by the Company in respect thereof (the “Series E Optional Redemption Price”). However, for any optional redemption effected in connection with or following a Change of Control (as defined in the Series E Certificate of Designation) or any mandatory redemption in connection with a Change of Control as described below, the Series E Optional Redemption Price will be calculated under clause (C) above, regardless of when the redemption or Change of Control occurs.
Except in the case of a Change of Control Redemption (as defined in the Series E Certificate of Designation), the Company may not effect an optional redemption of the Series E Preferred Stock unless:
either (i) as of the optional redemption date, there are no shares of the Series F Preferred Stock outstanding or (ii) all outstanding shares of the Series F Preferred Stock are redeemed on such optional redemption date concurrently with such optional redemption of the Series E Preferred Stock in accordance with the terms of the Series F Certificate of Designation;
the aggregate Series E Optional Redemption Price for all shares of the Series E Preferred Stock to be redeemed pursuant to such optional redemption shall not exceed the aggregate amount of net cash proceeds received by the Company from a contemporaneous issuance of common stock issued for the purpose of redeeming such shares of Series E Preferred Stock; and
if the optional redemption date occurs prior to March 5, 2022, then (i) the VWAP for at least 20 trading days during the 30 trading day period immediately preceding the notice of the optional redemption has been at least 150% of the Conversion Price (as defined below) then in effect, and (ii) such optional redemption shall be for all (but not less than all) then-outstanding shares of Series E Preferred Stock.

The Series E Preferred Stock is not redeemable at the option of the holders except in connection with a Change of Control as described below and is perpetual unless converted or redeemed in accordance with the Series E Certificate of Designation.
The Company has the right to redeem the Series F Preferred Stock, in whole or in part (subject to certain limitations on partial redemptions), at a price per share equal to (i) the Stated Value then in effect, multiplied by 115.0%, plus (ii) accrued and unpaid dividends thereon and any other amounts payable by the Company in respect thereof (the “Series F Optional Redemption Price”).
The Series F Preferred Stock is not redeemable at the option of the holders except in connection with a Change of Control as described below and is perpetual unless converted or redeemed in accordance with the Series F Certificate of Designation.
Conversion. Each share of the Series E Preferred Stock is convertible at any time at the option of the holder into the number of shares of common stock equal to (i) the applicable Series E Optional Redemption Price that would have been received by the holder upon the redemption of the applicable shares of Series E Preferred Stock as of the Conversion Date (as defined in the Series E Certificate of Designation) divided by (ii) the Conversion Price (as defined below) (the “Conversion Rate”). However, for purposes of determining the Conversion Rate, the Series E Optional Redemption Price will be calculated on the basis applicable to an optional redemption occurring after March 5, 2021 (i.e., multiplying the Stated Value by 100.0%), regardless of the timing or circumstances of the conversion. The “Conversion Price” for the Series E Preferred Stock is $2.50, subject to adjustment as described below. The Conversion Price will be subject to proportionate adjustment in connection with stock splits and combinations, dividends paid in stock and similar events affecting the outstanding common stock. Additionally, the Conversion Price will be adjusted, based on a broad-based weighted average formula, if the Company issues, or is deemed to issue, additional shares of

124







common stock for consideration per share that is less than the Conversion Price then in effect, subject to certain exceptions and to the Share Cap (as defined below).
To comply with the rules of the NYSE American, the Series E Certificate of Designation provides that the number of shares of common stock issuable on conversion of a share of Series E Preferred Stock may not exceed the Stated Value divided by $1.88 (which was the closing price of the common stock on the NYSE American on March 4, 2019) (the “Share Cap”), subject to proportionate adjustment in connection with stock splits and combinations, dividends paid in stock and similar events affecting the outstanding common stock (such price, as so adjusted, the “Initial Market Price”), prior to the receipt of stockholder approval of the issuance of shares of common stock in excess of the Share Cap upon conversion of shares of Series E Preferred Stock. The 2019 Transaction Agreement requires the Company to seek such shareholder approval at its next annual meeting of shareholders. Accordingly, the Company received shareholder approval at its 2019 annual meeting of shareholders held on May 20, 2019.
The Company does not have the right to force the conversion of shares of the Series E Preferred Stock based on the trading price of the common stock or otherwise.
The Series F Preferred Stock is not convertible into common stock.
Change of Control. Upon the occurrence of a Change of Control (as defined in the Series E Certificate of Designation and the Series F Certificate of Designation), each holder of shares of the Series E Preferred Stock and Series F Preferred Stock will have the option to: (i) cause the Company to redeem all of such holder’s shares of Series E Preferred Stock or Series F Preferred Stock for cash in an amount per share equal to the applicable Optional Redemption Price; (ii) in the case of the Series E Preferred Stock, convert all of such holder’s shares of Series E Preferred Stock into common stock at the Conversion Rate; or (iii) continue to hold such holder’s shares of Series E Preferred Stock or Series F Preferred Stock, subject to the Company’s or its successor’s optional redemption rights described above and, in the case of the Series E Preferred Stock, subject to any adjustments to the Conversion Price or the number and kind of securities or other property issuable upon conversion resulting from the Change of Control.
Liquidation Preference. Upon any liquidation, dissolution or winding up of the Company, holders of shares of Series F Preferred Stock will be entitled to receive, prior to any distributions on the Series E Preferred Stock, the Series D Preferred Stock, the Series C Preferred Stock, the common stock or other capital stock of the Company ranking junior to the Series F Preferred Stock, an amount per share equal to the greater of (i) the Series F Optional Redemption Price then in effect and (ii) the proceeds the holders of Series F Preferred Stock would be entitled to receive if, immediately prior to the payment of such amount, each then-outstanding share of the Series F Preferred Stock had been converted into a number of shares of common stock equal to the Series F Optional Redemption Price divided by the Participation Price (as defined in the certificate of designation for the Series F Preferred Stock), regardless of the fact that shares of the Series F Preferred Stock are not convertible into common stock.
Upon any liquidation, dissolution or winding up of the Company, holders of shares of Series E Preferred Stock will be entitled to receive, after any distributions on the Series F Preferred Stock and prior to any distributions on the Series D Preferred Stock, the Series C Preferred Stock, the common stock or other capital stock of the Company ranking junior to the Series E Preferred Stock, an amount per share of Series E Preferred Stock equal to the greater of (i) the Series E Optional Redemption Price then in effect and (ii) the amount such holder would receive in respect of the number of shares of common stock into which such share of Series E Preferred Stock is then convertible.
Board Designation Rights. The Series E Certificate of Designation provides that holders of the Series E Preferred Stock have the right, voting separately as a class, to designate one member of the Board for as long as the shares of common stock issuable on conversion of the outstanding shares of Series E Preferred Stock represent at least 5% of the outstanding shares of common stock (giving effect to conversion of all outstanding shares of the Series E Preferred Stock).
The Series F Certificate of Designation provides that holders of the Series F Preferred Stock have the right, voting separately as a class, to designate one member of the Board for as long as the aggregate Stated Value of all outstanding shares of the Series F Preferred Stock is at least equal to $13.8 million.
Voting Rights. In addition to the Board designation rights described above, holders of Series E Preferred Stock are entitled to vote with the holders of the common stock, as a single class, on all matters submitted for a vote of holders of the common stock. When voting together with the common stock, each share of Series E Preferred Stock will entitle the holder to a number of votes equal to the applicable Stated Value as of the applicable record date or other determination date divided by the greater of (i) the then-applicable Conversion Price and (ii) the then-applicable Initial Market Price.

125







Holders of shares of Series F Preferred Stock are not entitled to vote with the holders of the common stock as a single class on any matter.
 
Negative Covenants. The Series E Certificate of Designation and Series F Certificate of Designation contain customary negative covenants.
Transfer Restrictions. Shares of Series E Preferred Stock and Series F Preferred Stock and shares of common stock issued on conversion of shares of Series E Preferred Stock may not be transferred by the holder of such shares, other than to an affiliate of such holder, prior to September 5, 2019. After September 5, 2019, such shares will be freely transferable, subject to applicable securities laws.

NOTE 16 - STOCKHOLDERS' EQUITY

Issuance of Common Stock

On March 5, 2019, pursuant to the 2019 Transaction Agreement, as (i) partial consideration for the satisfaction in full of the Second Lien Term Loan as discussed in Note 11 - Long-Term Debt and (ii) consideration for the amendment of the terms of the Series C Preferred Stock and the Series D Preferred Stock as discussed in Note 15 - Preferred Stock, the Company issued an aggregate of 17,641,638 shares of the Company’s common stock, par value 0.0001 per share.

  
Warrants

The following table provides a summary of warrant activity as of December 31, 2019 and 2018:
 
Warrants
 
Weighted-
Average
Exercise
Price
Outstanding at Outstanding at January 1, 2018
11,882,800

 
$
3.34

Exercised
(3,975,957
)
 
2.21

Forfeited or expired
(2,889,514
)
 
3.35
Outstanding at Outstanding at January 1, 2019
5,017,329

 
3.83
Forfeited or expired
(2,263,267
)
 
2.81
Outstanding at December 31, 2019
2,754,062

 
$
4.67


The outstanding warrants at December 31, 2019 will expire as follows:
Year
Warrants
2020
174,642

2021

2022
2,579,420

 
2,754,062


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 December 31, 2018 the Company purchased 253,598 shares of the Company’s common stock for approximately $1.0 million.

NOTE 17 - SHARE BASED AND OTHER COMPENSATION
 
On April 20, 2016, the Company’s Board and the Compensation Committee of the Board approved the Company’s 2016 Omnibus Incentive Plan (the “2016 Plan”). As of December 31, 2019, 5.4 million shares of the 18 million shares of the Company’s

126







common stock authorized for awards under the 2016 Plan remained available for future issuances. The Company generally issues new shares to satisfy awards under employee stock based payment plans. The Company no longer grants any awards under the Lilis 2012 Omnibus Incentive Plan (the “2012 Plan”).

The following table sets forth the stock based compensation expense recognized during the years ended December 31, 2019 and 2018 and the unamortized portion of the stock based compensation expense and weighted average amortization period of the remaining vesting period for the year ended December 31, 2019 and 2018, the Company’s share-based compensation consisted of the following (dollars in thousands)
 
Year Ended December 31,
 
2019
 
2018
 
Stock  
Options
 
Restricted  Stock
 
Total
 
Stock  
Options
 
Restricted Stock
 
Total
Share based compensation expensed
$
317

 
$
6,189

 
$
6,506

 
$
2,158

 
$
6,842

 
$
9,000

Unrecognized share-based compensation costs
$
100

 
$
1,228

 
$
1,328

 
$
487

 
$
3,501

 
$
3,988

Weighted average amortization period remaining (in years)
1.55

 
1.05

 


 
0.03

 
0.50

 



Restricted Stock
 
Employees may be granted restricted stock in the form of restricted stock awards or restricted stock units. Restricted stock is subject to forfeiture restrictions and cannot be sold, transferred, or disposed of during the restriction period. The holders of restricted stock awards have the same rights as a stockholder of the Company with respect to such shares, including the right to vote and receive dividends or other distributions paid with respect to the shares. Restricted stock vests over service periods ranging from the date of grant generally up to two or three years. The company expenses the grant date fair value of restricted shares, determined to be share price on the date of grant, ratably over the service period.

A summary of restricted stock grant activity pursuant to the 2012 Plan and the 2016 Plan for the year ended December 31, 2019, is presented below: 
 
Number of
Shares
 
Weighted
Average Grant
Date Price
Outstanding at January 1, 2018
2,475,266

 
$
4.22

Granted
1,194,944

 
$
4.59

Vested and issued
(1,436,146
)
 
$
2.38

Forfeited or canceled (1)
(1,280,480
)
 
$
4.44

Outstanding at December 31, 2018
953,584

 
$
4.85

Granted
3,684,372

 
$
1.46

Vested and issued
(2,341,269
)
 
$
2.39

Forfeited or canceled (1)
(894,512
)
 
$
2.94

Outstanding at December 31, 2019
1,402,175

 
$
1.26

(1) Forfeitures are accounted for as and when incurred.
 
Stock Options
 
Employees may be granted incentive stock options to purchase shares of the Company’s common stock with an exercise price equal to, or greater than, the fair market value of the Company’s common stock on the date of grant. These stock options generally vest over two years from the date of grant and terminate at the earlier of the date of exercise or ten years from the date of grant. During the year ended December 31, 2018, the Company received cash proceeds of approximately $2.6 million from the exercise of vested stock options. There were no stock options exercised during the year ended December 31, 2019.

127








A summary of stock option activity pursuant to the 2016 Plan for the years ended December 31, 2019 and 2018, is presented below: 
 
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
(1,024,877
)
 
$
2.67

 
 
 
 
Forfeited or canceled
(1,601,045
)
 
$
4.20

 
 
 
 
Outstanding at December 31, 2018
5,031,578

 
$
3.81

 
5,035,317

 
7.9
Granted
135,000

 
$
2.17

 

 

Exercised

 
$

 

 

Forfeited or canceled (1)
(1,578,228
)
 
$
3.14

 

 

Outstanding at December 31, 2019
3,588,350

 
$
4.05

 
4,125,842

 
7.2
(1) Forfeitures are accounted for as and when incurred.

During the year ended December 31, 2019, options to purchase 135,000 shares of the Company’s common stock were granted under the 2016 Plan. The weighted average fair value of these options was $1.47 utilizing the weighted average expected term of 10 years, expected volatility of 30%, no expected dividends, and risk-free interest rate of 2.67%.

The Company estimates expected volatility based on an analysis of its historical stock prices since the initial public offering date in 2007. The Company estimates the expected term of its option awards based on the vesting period. The Company uses this method to provide a reasonable basis for estimating its expected term due to the lack of sufficient historical employee exercise data on stock option awards.


128







NOTE 18 - INCOME (LOSS) PER COMMON SHARE
 
The following table shows the computation of basic and diluted net loss per share for the years ended December 31, 2019 and 2018 (in thousands):
 
2019
 
2018
Net loss
$
(272,121
)
 
$
(4,143
)
Dividends on preferred stock
(25,397
)
 
(10,687
)
Unallocated net loss
$
(297,518
)
 
$
(14,830
)
 
 
 
 
Numerator for basic loss per share:
 
 
 
Net loss attributable to common stockholders
$
(297,518
)
 
$
(14,830
)
 
 
 
 
Denominator for basic loss per share:
 
 
 
Basic weighted average common shares outstanding
87,912,362

 
62,854,214

 
 
 
 
Net loss per share:
 
 
 
Basic attributable to common stockholders
$
(3.38
)
 
$
(0.24
)
 
 
 
 
Numerator for diluted loss per share:
 
 
 
Net loss attributable to common stockholders
$
(297,518
)
 
$
(14,830
)
Add: interest expense on convertible Second Lien Term Loan

 
13,429

Less: gain on fair value change of embedded derivatives associated with Second Lien Term Loan

 
(35,471
)
Net loss attributable to common stockholders
$
(297,518
)
 
$
(36,872
)
 
 
 
 
Denominator for diluted net loss per share:
 
 
 
Basic weighted average common shares outstanding
87,912,362

 
62,854,214

Dilution effect of if-converted Second Lien Term Loan

 
15,597,127

Diluted weighted average common shares outstanding
87,912,362

 
78,451,341

 
 
 
 
Net loss per share - diluted:
 
 
 
Common shares (diluted)
$
(3.38
)
 
$
(0.47
)

The Company excluded the following shares from the diluted loss per share calculations above because they were anti-dilutive at December 31, 2019 and 2018
 
December 31,
 
2019
 
2018
Stock Options
3,588,350

 
5,031,578

Series C Preferred Stock

 
26,295,616

Series D Preferred Stock

 
8,543,670

Stock Purchase Warrants
2,754,062

 
5,017,329

Series E Preferred Stock
25,667,871

 

Conversion of term loans

 

 
32,010,283

 
44,888,193



129







NOTE 19 - SUPPLEMENTAL NON-CASH TRANSACTIONS
 
The following table presents the supplemental disclosure of cash flow information for the years ended December 31, 2019 and 2018
 
Year Ended December 31,
 
2019
 
2018
 
(in thousands)
Non-cash investing and financing activities excluded from the statement of cash flows:
 
 
 
Issued shares of common stock and preferred stock upon extinguishment of debt and modification of Series C Preferred Stock and Series D Preferred Stock
$
141,787


$
64,504

Common stock issued for acquisition of oil and natural gas properties

 
24,778

Cashless exercise of warrants

 
359

Deferred revenue realized upon purchase option exercise
16,700

 

Right of use assets obtained in exchange for operating lease obligations
7,500

 

Change in capital expenditures for drilling costs in accrued liabilities
2,010

 
7,850

Accrued cumulative paid in kind dividends on preferred stock
25,397

 
10,687

Change in asset retirement obligations
546

 
1,495

Reduction of fair value for converted embedded derivatives

 
12,406

Transfer of warrant derivative instruments to equity

 
223

 
NOTE 20 - SEGMENT INFORMATION
 
Operating segments are defined as components of an entity that engage in activities from which it may earn revenues and incur expenses for which separate operational financial information is available and are regularly evaluated by the chief operating decision maker for the purposes of allocating resources and assessing performance. The Company currently has only one reportable operating segment, which is oil and natural gas development, exploration and production, for which the Company has a single management team that allocates capital resources to maximize profitability and measures financial performance as a single entity.

NOTE 21 - COMMITMENTS AND CONTINGENCIES
  
ARM Sales Agreement

On August 2, 2018, the Company executed a five-year agreement with SCM Crude, LLC, an affiliate of SCM, to secure firm takeaway pipeline capacity and pricing on a long-haul pipeline to the Gulf Coast region commencing July 1, 2019. On March 11, 2019, the agreement was replaced with a five-year agreement between the Company and ARM, a related company to SCM. The new agreement accelerated the start date to March 2019 and guarantees firm takeaway capacity on a long-haul pipeline to Corpus Christi, Texas, once completed, at a specified price. Under the terms of the new contract, the Company received pricing differentials on the crude oil sales contract subject to minimum quantities of crude oil to be delivered as follows:
Date
Quantity (Barrels per Day)
March 2019 - June 2019
5,000
July 2019 - December 2019
4,000
January 2020 - June 2020
5,000
July 2020 - June 2021
6,000
July 2021 - December 2024 (1)
7,500
(1) Extending to the later of December 2024 or 5 years from the EPIC Crude Oil pipeline in-service date (February 2025).

Further, ARM has agreed to purchase crude from the Company based upon Magellan East Houston pricing with a fixed “differential basis”. As of December 31, 2019, the agreement no longer meets the criteria for the “normal purchase normal sales” exception under ASC 815, “Derivatives and Hedging”, due to the Company not meeting the minimum quantities deliverable under the contract and the net settlement criteria being met. See Note 9 - Derivatives for information regarding the recognition of the net settlement mechanism as an embedded derivative over the remainder of the contract.

130








Environmental and Governmental Regulation
 
As of December 31, 2019, there were no known environmental or regulatory matters which are reasonably expected to result in a material liability to the Company. Many aspects of the oil and natural gas industry are extensively regulated by federal, state, and local governments and regulatory agencies in all areas in which the Company has operations. Regulations govern such things as drilling permits, environmental protection and air emissions/pollution control, spacing of wells, the unitization and pooling of properties, reports concerning operations, land use, taxation, and various other matters. Oil and natural gas industry legislation and administrative regulations are periodically changed for a variety of political, economic, and other reasons. As of December 31, 2019, the Company had not been fined or cited for any violations of governmental regulations that would have a material adverse effect on the financial condition of the Company.
 
Legal Proceedings
 
The Company may from time to time be involved in various legal actions arising in the ordinary course of business. In the opinion of management, the Company’s liability, if any, in these pending actions would not have a material adverse effect on the financial position of the Company. The Company’s general and administrative expenses would include amounts incurred to resolve claims made against the Company.
 
The Company believes there is no litigation pending that could have, individually or in the aggregate, a material adverse effect on its results of operations or financial condition.

Liens
As of the most recent date available, statutory mechanic's and materialman’s liens which remain unpaid in the amount of $8.7 million have been filed against the related assets.

NOTE 22 - SUBSEQUENT EVENTS

COVID-19
    
On January 30, 2020, the World Health Organization (“WHO”) announced a global health emergency due to the COVID-19 outbreak, which originated in Wuhan, China, and the risks to the international community as the virus spreads globally beyond its point of origin. In March 2020, the WHO classified the COVID-19 outbreak as a pandemic, based on the rapid increase in exposure globally.

In addition, in March 2020, members of OPEC failed to agree on production levels which has caused an increased supply and has led to a substantial decrease in oil prices and an increasingly volatile market. The oil price war ended with a deal to cut global petroleum output but did not go far enough to offset the impact of COVID-19 on demand. There has been an increase in supply which has pushed prices down further since March. If the depressed pricing continues for an extended period it will lead to i) additional reductions in the borrowing base under our credit facility which would require us to make additional borrowing base deficiency payments, ii) reductions in reserves, and iii) additional impairment of proved and unproved oil and gas properties. We also expect disclosures of supplemental oil and gas information to be impacted by price declines.

In response to recent commodity prices and our efforts to strengthen our capital through reducing operating costs, during April 2020 the Company elected to shut-in 12 wells which were identified as uneconomic as a result of the continued decline in commodity prices in 2020 and 19 additional wells have been identified for short term shut-in through May and June. The 19 wells identified for short term shut-in are naturally flowing wells and could be turned back to sales quickly as market conditions dictate. The Company has also implemented an employee furlough program to further reduce general and administrative costs.  The furloughed employees will not receive compensation from the Company during the furlough period; however, subject to local regulations, these employees will be eligible for unemployment benefits.  The furlough period is uncertain at this time and will be reassessed as business conditions dictate.

The full impact of the COVID-19 outbreak and the decline in oil prices continues to evolve as of the date of this Annual Report. As such, it is uncertain as to the full magnitude that they will have on the Company’s financial condition, liquidity, and future results of operations.


131







Management is actively monitoring the global situation on its financial condition, liquidity, operations, suppliers, industry, and workforce. Given the daily evolution of the COVID-19 outbreak and the global responses to curb its spread, the Company is not able to estimate the effects of the COVID-19 outbreak on its results of operations, financial condition, or liquidity for fiscal year 2020.

These matters could have a continued material adverse impact on economic and market conditions and trigger a period of global economic slowdown, which may impair the Company’s asset values, including reserve estimates.  Further, consumer demand has decreased since the spread of the outbreak and new travel restrictions placed by governments in an effort to curtail the spread of the coronavirus. Although the Company cannot estimate the length or gravity of the impacts of these events at this time, if the pandemic and/or decreased oil prices continue, they will have a material adverse effect on the Company’s results of future operations, financial position, and liquidity in fiscal year 2020. 

Coronavirus Aid, Relief, and Economic Security Act

On March 27, 2020, President Trump signed into law the Coronavirus Aid, Relief, and Economic Security (the “CARES Act”). The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer side social security payments, net operating loss carryback periods, alternative minimum tax credit refunds, modifications to the net interest deduction limitations, increased limitations on qualified charitable contributions, and technical corrections to tax depreciation methods for qualified improvement property.

It also appropriated funds for the SBA Paycheck Protection Program loans that are forgivable in certain situations to promote continued employment, as well as Economic Injury Disaster Loans to provide liquidity to small businesses harmed by COVID-19. There is no assurance we are eligible for these funds or will be able to obtain them.

We continue to examine the impact that the CARES Act may have on our business. Currently, we are unable to determine the impact that the CARES Act will have on our financial condition, results of operations, or liquidity.




132







Lilis Energy, Inc. and Subsidiaries
Supplementary Information on Oil and Natural Gas Exploration,
Development and Production Activities
(Unaudited)

The Company’s oil and natural gas reserves are attributable solely to properties within the United States, which constitutes one cost center.
 
Costs Incurred for Oil and Natural Gas Producing Activities

The following table sets forth the costs incurred in the Companys oil and natural gas acquisition, exploration and development activities and includes costs whether capitalized or expensed as well as revisions and additions to the estimated future asset retirement obligations:
 
December 31,
 
2019
 
2018
 
(In thousands)
Acquisition costs:
 

 
 

Unproved properties
$
1,644

 
$
93,926

Proved properties

 
22,356

Exploration costs
40,284

 
89,351

Development costs
51,198

 
78,103

Total
$
93,126

 
$
283,736


Results of Operations for Oil and Natural Gas Producing Activities

The following table sets forth the results of operations for oil and natural gas producing activities:
 
December 31,
 
2019
 
2018
 
(In thousands)
Revenues
$
66,063

 
$
70,216

Production costs
(16,127
)
 
(13,843
)
Production taxes
(3,302
)
 
(3,709
)
Accretion of asset retirement obligation
(433
)
 
(85
)
Depletion, depreciation and amortization
(33,071
)
 
(25,159
)
Full cost ceiling impairment
(228,324
)
 

Total
$
(215,194
)
 
$
27,420




133







Reserves Quantity Information
 
The following table provides a roll forward of the total proved reserves for the years ended December 31, 2019 and 2018, as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year:
 
Crude Oil
(Bbls)
 
Natural Gas
(Mcf)
 
NGLs
(Bbls)
January 1, 2018
7,171,339

 
16,059,926

 
1,604,570

Extensions and discoveries
15,881,727

 
38,957,588

 
4,565,994

Purchase of reserves
1,883,047

 
8,897,115

 
682,964

Revisions of previous estimates
(2,641,353
)
 
17,690,723

 
1,769,448

Production
(1,089,724
)
 
(2,855,739
)
 
(246,425
)
December 31, 2018
21,205,036

 
78,749,613

 
8,376,551

Extensions and discoveries
856,838

 
2,477,061

 
190,203

Revisions of previous estimates
(15,596,115
)
 
(48,718,235
)
 
(6,067,700
)
Production
(1,130,855
)
 
(3,063,927
)
 
(220,832
)
December 31, 2019
5,334,904

 
29,444,512

 
2,278,222

 

 

 

Proved Developed Reserves, included above:

 

 

Balance, January 1, 2018
2,531,397

 
6,594,446

 
644,102

Balance, December 31, 2018
6,278,036

 
27,046,195

 
2,653,908

Balance, December 31, 2019
5,334,904

 
29,444,512

 
2,278,222

Proved Undeveloped Reserves, included above:

 

 

Balance, January 1, 2018
4,639,942

 
9,465,480

 
960,468

Balance, December 31, 2018
14,927,000

 
51,703,418

 
5,722,643

Balance, December 31, 2019

 

 


Extensions and discoveries of 1.5 MBOE during the year ended December 31, 2019, resulted from the drilling of exploratory wells during the year that are included in proved reserves and productive wells as of December 31, 2019.

Revisions of previous reserves estimates decreased 2019 proved reserves by 29.8 MBOE. Reserves decreased by approximately 8.3 MBOE as a result of lower SEC pricing and costs for 2019 compared to 2018, as well as operational factors. The remaining revisions of 21.5 MBOE were the result of reclassification of all PUD reserves to unproved because of the uncertainty regarding the availability of capital to us for development these reserves as of December 31, 2019.

Standardized Measure of Discounted Future Net Cash Flows
 
The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the properties. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties and consideration of expected future economic and operating conditions.
 
The estimates of future cash flows and future production and development costs as of December 31, 2019 and 2018 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions which are held constant throughout the life of the properties. All wellhead prices are held flat over the forecast period for all reserves categories. The estimated future net cash flows are then discounted at a rate of 10%.
 

134







The standardized measure of discounted future net cash flows relating to proved oil, natural gas and NGL reserves is as follows:
 
December 31,
 
2019
 
2018
 
(In thousands)
Future cash inflows
$
358,127

 
$
1,500,263

Future production costs
(176,498
)
 
(414,117
)
Future development costs
(7,284
)
 
(346,225
)
Future income tax expense

 
(62,842
)
Future net cash flows
174,345

 
677,079

10% discount to reflect timing of cash flows
(54,171
)
 
(384,345
)
Total
$
120,174

 
$
292,734

 
In the foregoing determination of future cash inflows, sales prices used for oil, natural gas and NGLs for December 31, 2019 and 2018, were estimated using the average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-month price for each month. Prices were adjusted by lease for quality, transportation fees and regional price differentials. Future costs of developing and producing the proved natural gas and oil reserves reported at the end of each year shown were based on costs determined at each such year-end, assuming the continuation of existing economic conditions.

At December 31, 2019, the tax basis of our oil and gas properties exceeded the pre-tax cash inflows; therefore, in the preparation of the Standardized Measure no future taxable income is expected to be generated from our oil and natural gas properties, primarily due to the reclassification of all PUD reserves to unproved because of the uncertainty regarding the availability of capital for developing those reserves.
 
The Company cautions that the disclosures shown are based on estimates of proved reserves quantities and future production schedules which are inherently imprecise and subject to revision and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations and no value may be assigned to probable or possible reserves.
 
Changes in the standardized measure of discounted future net cash flows relating to proved oil, natural gas and NGL reserves are as follows:
 
Year Ended December 31,
 
2019
 
2018
 
(In thousands)
Balance at beginning of period
$
292,734

 
$
68,812

Net changes in prices and production costs (1)
(275,539
)
 
24,261

Sales of oil and natural gas produced during the year, net
(42,442
)
 
(49,271
)
Changes in estimated future development costs (2)
272,579

 
(39,938
)
Net change due to extensions and discoveries
18,044

 
161,785

Net change due to purchases of minerals in place

 
55,278

Previously estimated development costs incurred during the year
36,298

 
68,349

Net changes due to revision of previous quantity estimates (3)
(255,125
)
 
28,350

Accretion of discount
29,273

 
6,881

Other - unspecified (4)
9,327

 
3,252

Net change in income taxes
35,025

 
(35,025
)
Balance at end of period
$
120,174

 
$
292,734


(1) Net changes from prices and production costs were primarily the result of a 19% decrease in oil and natural gas prices and 45% increase in production costs from December 31, 2018 to December 31, 2019.


135







(2) Future development costs decreased $272.6 million from December 31, 2018 to December 31, 2019. Our December 31, 2019 proved reserves report reflects the reclassification of all PUD reserves to unproved because of the uncertainty regarding the availability of capital for developing those reserves. Our December 31, 2018 proved reserves report included future development costs of $329.5 million associated with PUD reserves not included in our December 31, 2019 proved reserves report.

(3) Negative revisions for 2019 are primarily the result of the reclassification of proved undeveloped reserves to unproved as reflected in our December 31, 2019 reserves report.

(4) Other changes are the result of significant changes to our proved reserves from December 31, 2018 to December 31, 2019 and include significant estimates of the effects of changes in the economic lives of producing wells and reclassification of proved undeveloped reserves to unproved as reflected in our December 31, 2019 reserves report.

136
Lilis Energy (AMEX:LLEX)
Historical Stock Chart
From Feb 2024 to Mar 2024 Click Here for more Lilis Energy Charts.
Lilis Energy (AMEX:LLEX)
Historical Stock Chart
From Mar 2023 to Mar 2024 Click Here for more Lilis Energy Charts.