Document






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
 
 
 
 
 
 
 
 
 
 
 
 
 



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.


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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

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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

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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

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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.


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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.

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

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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.


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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

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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;

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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.


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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

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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.


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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.


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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

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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

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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

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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.


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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.

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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.


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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

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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.


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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.


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

We have never paid dividends with respect to our common stock, and we do not expect to pay any dividends, in cash or otherwise, in the foreseeable future. We intend to retain any earnings for use in our business. In addition, our credit 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

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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.


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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.


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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


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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.
 

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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.


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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.


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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.

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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.

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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.


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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

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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.

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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.


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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.


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Outstanding Equity Awards at Fiscal Year-End
 
 
Option Awards
 
Stock Awards
Name
 
Number of
Securities
Underlying
Unexercised
Options (#)
Exercisable
 
Number of
Securities
Underlying
Unexercised
Options (#)
Unexercisable
 
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.


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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.

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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 automa