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, 2018 
or 
¨    TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
For the transition period from __________to_________ 
Commission file number: 001-35330 
Lilis Energy, Inc.
(Name of registrant as specified in its charter)
Nevada
 
74-3231613
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
1800 Bering Drive, Suite 510, Houston, Texas 77057
(Address of principal executive offices, including zip code)
 
Registrant’s telephone number including area code: (817) 585-9001
 
Securities registered under Section 12(b) of the Act: 
Common Stock, $0.0001 par value
 
NYSE American
Title of class
 
Name of exchange on which registered
 
Securities registered under Section 12(g) of the 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 15(d) of the Exchange 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 (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes  ý      No  ¨
Indicate by check mark if disclosure of delinquent filers in response to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company (as defined in Rule 12b-2 of the Act):
Large accelerated filer
¨ 
Accelerated filer
ý 
Non-accelerated filer   
¨ 
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 30, 2018, 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 $211,811,267 based on the closing sales price of $5.20 per share of the registrant’s common stock on June 30, 2018 on the NYSE American. 
As of March 5, 2019, 71,496,979 shares of the registrant’s common stock were issued and outstanding.

 
 
 

 
 
 


DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive Proxy Statement of Lilis Energy, Inc. (to be filed no later than 120 days after December 31, 2018) relating to the Company’s 2019 Annual Meeting of Stockholders are incorporated into Part III of this Form 10-K.

 
 
 



TABLE OF CONTENTS
 
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 

3



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 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, 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 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 Form 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.
 
For a detailed description of factors that could cause actual results to differ materially from those expressed in any forward-looking statement, we urge you to carefully review and consider the disclosures made in the “Risk Factors” sections of our SEC filings, available free of charge at the website of the U.S. Securities Exchange Commission (the “SEC”) - www.sec.gov.

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.

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PART I
 

Items 1 and 2. Business and Properties

Overview

Lilis is an independent oil and gas company focused on the exploration, development, production, and acquisition of oil, natural gas and natural gas liquids, or 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% crude oil and NGLs, or Liquids, a relatively high liquid production ratio compared to many of our peers. Over 90% our of revenues are generated from the sale of Liquids.

The Company is managed by a focused and experienced management team that is dedicated to rapidly increasing the Company’s production, reserves, and acreage position.

Our History

The Company was incorporated in the State of Nevada in 2007. The name of the corporation was changed 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 a substantial portion of the Company’s current 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 gas properties located in the DJ Basin in March 2017.

Our Business

We are a pure play Permian Basin company focused on realizing the highest returns and delineating our acreage position to increase the value of our stock for our stockholders.

Our Business Strategy

Our goal is to grow our Company and increase stockholder value by generating cash flow primarily from new production of Liquids, as well as through delineation drilling on our existing acreage.

We continue to focus on developing our existing acreage position, growing our production and reserves, and expanding our core assets in the Delaware Basin through strategic acquisitions, acreage exchanges, and organic leasing. We plan to achieve our objectives by implementing a business strategy focused on the following:

Leverage our Extensive Operational Expertise to Reduce Costs and Plan for Cash Flow Neutrality. We actively manage the level of our development, leasing and acquisition activity in response to commodity prices, access to capital, and the performance of our wells. We recently announced our recapitalization, which allows us to better manage our assets (See "2019 Second Lien Term Loan Conversion and Borrowing Base Redetermination" and "Subsequent Events" for further information regarding our recapitalization).
As of December 31, 2018, we operated approximately 99% of our acreage position, giving us significant control over the pace of our development and allowing us to increase value through operational and cost efficiencies. We intend to obtain the highest possible returns on the capital we expend on our development projects using results from the wells we have completed and the operational expertise of our management team. We will continue to focus on operational efficiencies, including midstream costs, salt water disposal, and capital costs of our development wells in order to maximize returns to our stockholders. We have increased our operational efficiency by entering into various infrastructure transactions, and we have structured our balance sheet with the intent to achieve cash flow neutrality in 2019 and significantly reduce our leverage profile over time. Additionally, we have an active hedging program to provide certainty regarding our cash flow and protect returns from our development activity in the event of decreases in the prices received for our production.

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Realizing Highest Returns and Delineating Acreage. We plan to drill and develop our existing acreage base of approximately 28,500 gross (20,400 net) acres in the Delaware Basin, which we believe will maximize our resource potential and increase value to our stockholders. Our drilling activity during 2018 was predominantly focused on the horizontal development and delineation of our core acreage position in the Delaware Basin. We increased our net sales production volumes by 215% to 4,965 BOE/d in 2018, as compared to 2017. We averaged 8,081 net BOE/d from December 25 through December 31, 2018, achieving our 2018 year-end exit rate target of 8,000 BOE/d. Additionally, as a result of our development efforts, acreage exchanges and acquisitions, our proved reserves increased 273% from December 31, 2017, to approximately 42,707 MBOE (thousand barrels of oil equivalent) as of December 31, 2018. Our proved reserves were Liquids rich, being comprised of approximately 69% Liquids (50% oil and 19% NGLs) and 31% natural gas.

Through the continued development of our properties, we plan to de-risk our acreage position and substantially increase our Liquids production and cash flow, thereby increasing the value of our properties. Our current leasehold position in the Delaware Basin has significant stacked-pay potential, which we believe includes at least five to seven productive zones in the Wolfcamp and Bone Springs formations. We estimate that all productive zones within our properties may support approximately 1,175 future drilling locations.

Increasing our Inventory and Improving Delineation. We plan to expand our inventory through delineation drilling of zones on our existing acreage and through acquisitions, acreage exchanges, and organic leasing. Since entering the Delaware Basin in June 2016, we have extensively grown our acreage position by over 500% from 7,200 gross (3,400 net) acres to approximately 28,500 gross (20,400 net) acres and increased our average operated working interest to approximately 76% at December 31, 2018, through various strategic acquisitions, acreage exchanges, and organic leasing, and we operate approximately 99% of our acreage. Our acquisitions to date have added over 17,000 acres which represent a multi-year inventory of approximately 1,175 identified, potential drilling locations across at least five to seven productive pay zones.

We plan to continue evaluating opportunities for strategic acquisitions, acreage exchanges, and organic leasing in our core areas of operation. We also expect that our drilling activity will grow our inventory and the identified resource potential of our Delaware Basin properties. Throughout 2018, we successfully drilled and announced our average 24-hour, 30-day initial production data on 12 wells targeting the Wolfcamp A, Wolfcamp B, Wolfcamp XY, 2nd Bone Spring, and 3rd Bone Spring formations. We believe that our current reserves represent only a small portion of the resource potential within our acreage. Our development plan for 2019 contemplates the continued delineation of our acreage both geographically and geologically and by drilling and completing wells within additional prospective benches.

Utilizing our Cost-Efficient Infrastructure Solutions. To support our operations and sales of our production, we have entered into various infrastructure and sales agreements that we believe secures cost-effective movement of our Liquids and natural gas in Texas and New Mexico.

We entered into several agreements with Salt Creek Midstream ("SCM") and its affiliates to provide crude gathering and transportation and water gathering and disposal infrastructure and services, including a crude oil transportation and sales agreement to secure pipeline capacity on a long-haul crude oil pipeline to the Gulf Coast, pursuant to which all volumes will have Gulf Coast pricing based on Magellan East Houston pricing throughout the 5-year term. We anticipate significantly lower crude transportation costs from approximately $5.15 per Bbl at December 31, 2018, to approximately $0.75 per Bbl commencing in March 2019, as a result of increased pipeline transportation of our crude oil under the gathering agreement with SCM. As a result of our infrastructure agreements, our salt water disposal costs decreased from approximately $2.50 per barrel in 2018 to approximately $0.49 per barrel in 2019.

In 2017, we entered into a long-term gas gathering and processing agreement with an affiliate of Lucid Energy Group (“Lucid”) to support our active drilling program in the Delaware Basin. Pursuant to our agreement with Lucid, there are no minimum volume commitments and all gas transported via Lucid is sent to Lucid’s 310 million cubic feet per day Red Hills Natural Gas Process Complex located in Lea County, New Mexico, where it is treated and processed then transported pursuant to transportation contracts through various long-haul pipelines with access to west coast markets, gulf coast markets, Permian markets and MidCon markets. Lucid is responsible for all capital costs in New Mexico and Texas, other than gathering lines from the wellhead to various Lucid receipt points.

We believe that our infrastructure and sales agreements will further our operational efficiency, as well as provide us significant cost savings, advantaged crude pricing in the Gulf Coast markets, and more consistent production flowing to sales in 2019 and future years.




6



Our Strengths

Established Acreage Position in the Core of the Delaware Basin. We believe we have assembled a substantial portfolio of Delaware Basin properties that offers high rate of return exploration and development opportunities. As of December 31, 2018, we held over 28,500 gross (20,400 net) acres in the core of the Delaware Basin, where we had an average operated working interest of approximately 76%. As of December 31, 2018, we operated approximately 99% of such acreage. Our acreage is geographically concentrated and highly contiguous, allowing us to capitalize on economies of scale with respect to drilling and production costs. We believe those efficiencies provide us with an advantage in competing for acquisitions, acreage exchanges, and organic leasing opportunities on and around our acreage.
Multi-year Portfolio of Drilling and Development Opportunities. We have a significant inventory of drilling and development locations in Winkler, Loving and Reeves Counties, Texas and Lea County, New Mexico. We believe our properties form part of the core of the Delaware Basin. Based on our drilling to date and results from nearby wells, we have identified approximately 1,175 potential horizontal well locations on our acreage, including approximately 700 longer lateral locations. Our leasehold position has significant stacked-pay potential, which we believe includes at least five to seven productive zones. We believe that our inventory of drilling locations will allow us to grow our reserves and production at attractive rates of return based on current expectations for commodity prices.
High Degree of Operational Control. We operate approximately 99% of our acreage, which gives us significant control over the pace of our development and the ability to design a more efficient and profitable drilling program to maximize recovery of oil and natural gas. Based on our drilling and production results to date and well-established offset operator activity in and around our project areas, we believe there are relatively low geologic risks and ample repeatable drilling opportunities across our core acreage.
Strengthening Financial Position and Flexibility. We believe our financial position is strong and sufficient to fund our drilling and completion operations currently planned for 2019. In October 2018, we announced our entry into a new five-year $500 million senior secured reserve based revolving credit facility (“Revolving Credit Agreement”) with an initial borrowing base of $95 million, that refinanced our first-lien term loan with Riverstone Credit Partners, LLC. As of December 7, 2018, the borrowing base of our Revolving Credit Agreement had increased to $108 million. The Company enhanced liquidity through the Revolving Credit Agreement and through a tack-on to the outstanding Series C Preferred Stock (as hereinafter defined). Additionally, the Company converted a portion of its Second Lien Term Loan (as hereinafter defined) to a combination of preferred and common equity, which resulted in a significant paid-in-kind interest expense savings. We have a solid relationship with Värde Partners, Inc. and its affiliates, who have partnered with us since the time of the Brushy Resources transaction and provided us with access to significant capital resources and financing opportunities. The Company had increased its liquidity to $54.1 million as of year-end 2018, including $33 million in availability under its Revolving Credit Agreement and $21.1 million in cash. Additionally, we recently announced our recapitalization, which allows us to better manage our assets (See "2019 Second Lien Term Loan Conversion and Borrowing Base Redetermination" and "Subsequent Events" for further information regarding our recapitalization).
We believe our financial liquidity position provides us operational flexibility and a path toward continued growth in our oil and natural gas production, proved reserves, and cash flows.
Experienced Management Team. We have an experienced and skilled management team with a long track record of driving growth through asset development and strategic acquisitions. We believe that our team’s operational expertise and extensive experience through various commodity price cycles position us to operate effectively and efficiently and, in turn, will help increase returns and value to our stockholders.

Oil and Natural Gas Properties

As of December 31, 2018, we owned leasehold acreage in approximately 28,500 gross (20,400 net) acres in the Delaware Basin, comprised of approximately 16,300 net acres in Winkler, Loving, and Reeves Counties, Texas and approximately 4,100 net acres in Lea County, New Mexico. Average net sales production volumes from our properties increased approximately 215% to 4,965 BOE/d in 2018 from 1,576 BOE/d in 2017. We averaged 8,081 net BOE/d from December 25 through December 31, 2018, achieving our 2018 year-end exit rate target of 8,000 BOE/d.

We currently estimate our properties include at least five to seven productive zones and hold approximately 1,175 future drilling locations across all of the productive zones within this position. Our reserve estimates include 37 horizontal PUD wells, as well as the capital costs required to develop these wells.



7





Reserve Data

Proved Reserves

The following table presents our estimated net proved oil and natural gas reserves as of December 31, 2018, 2017 and 2016, based on the reserve reports prepared by Cawley, Gillespie & Associates, Inc. Each reserve report has been prepared in accordance with the rules and regulations of the SEC. All of our proved reserves included in the reserve reports are located in the Delaware Basin of the Permian Basin:
Summary of Oil and Gas Reserves
 
For the Year Ended December 31,
 
2018
 
2017
 
2016
Proved Developed Reserves
 
 
 
 
 
Oil (MBbls)
6,278

 
2,531

 
551

NGLs (MBbls)
2,654

 
645

 
3

Total Liquids (MBbls)
8,932

 
3,176

 
554

Natural Gas (MMcf)
27,046

 
6,594

 
3,872

Total MBOE
13,440

 
4,275

 
1,199

 
 
 
 
 
 
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)
21,205

 
7,171

 
551

NGLs (MBbls)
8,377

 
1,605

 
3

Total Liquids (MBbls)
29,582

 
8,776

 
554

Natural Gas (MMcf)
78,749

 
16,060

 
3,872

Total MBOE
42,707

 
11,453

 
1,199


Proved Undeveloped Reserves

As of December 31, 2018, we had a total of 29,267 MBOE proved undeveloped reserves. During 2018, we added 22,088 MBOE of proved undeveloped (“PUD”) reserves through the extension of proved acreage, primarily as a result of successful drilling on properties in the core of the Delaware Basin in Winkler, Loving, and Reeves Counties, Texas and Lea County, New Mexico.

The increase in our PUDs was partially offset by the reclassification of 2,470 MBOE, previously included in the year-end 2017 PUDs, to PDPs as a result of our horizontal development of our properties.  Costs incurred relating to the development of PUDs were approximately $68.3 million during 2018.

Estimated future development costs relating to the development of PUDs are projected to be approximately $34.3 million in 2019, $128.0 million in 2020, $104.0 million in 2021 and $72.1 million in 2022.

Our estimates of proved undeveloped reserve quantities are limited by development drilling activity that we intend to undertake during the 2019 to 2022 timeframe. At December 31, 2018, we had no reserves that remained undeveloped for five or more years, and all PUD drilling locations are currently scheduled to be drilled within five years of their initial recording.  For

8



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

Control over Reserve Estimates

Our reserve data and estimates were compiled and prepared internally and audited by our third-party independent consultants, Cawley, Gillespie & Associates, Inc. (“CG&A”), 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 gas reserve quantities and values in compliance with the regulations of the SEC. Responsibility for compliance in reserve bookings is delegated to our Chief Financial Officer with assistance from our senior geologist and a senior reservoir engineer.

Technical reviews are performed throughout the year by our senior reservoir engineer and our senior geologist and other consultants who evaluate all available geological and engineering data, under the guidance of our Chief Financial Officer. This data, in conjunction with economic data and ownership information, is used in making a determination of estimated proved reserve quantities. Chris Cantrell, our senior reservoir engineer, has overseen our reserve processes since 2016. Mr. Cantrell received a Bachelor of Science degree in Petroleum Engineering from Texas A&M University in 1995. He is a registered professional engineer licensed in the State of Texas. He has been continuously involved in evaluating oil and gas properties since 1997 and is a member of the Society of Petroleum Engineers and the American Petroleum Institute.

Our Reserves Committee, a committee of our Board of Directors, assists management and the Board with their oversight of our reserves estimation and certification process and the work of our independent reserve engineer. The members of the Reserves Committee currently consist of R. Glenn Dawson, John Johanning, and Nicholas Steinsberger. Mr. Dawson serves as the Chairman of the Reserves Committee. The Committee’s charter specifies the oversight responsibilities of the Reserves Committee, which include, without limitation, oversight of the Company’s reserve estimates and related disclosures of same by the Company; oversight of the qualifications, training, and independence of the independent reservoir petroleum engineers and other geoscientists proposed to be engaged to audit or report on the reserves of the Company; oversight of the evaluation of oil and gas producing activities and operations and acquisition opportunities; and oversight of hydrocarbon reserve and resource matters as deemed necessary or appropriate in the interest of the Company and its stockholders.

Our reserves estimates and the corresponding report from CG&A, 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 CG&A’s audit letter.

Third-Party Reserves Study

Our controls over reserve estimates include retaining an independent third-party consultant, CG&A, as our independent petroleum engineering consulting firm to perform a reserves audit of our reserves estimates. We provided to CG&A information about our oil and gas properties, including production information, prices and costs, and CG&A performed reserve studies using its own engineering assumptions and the economic data provided by us. All of our total calculated proved reserve value was audited by CG&A, and all of the information regarding our 2018, 2017, and 2016 reserves in this Annual Report is derived from CG&A’s reports.

CG&A is an independent petroleum engineering consulting firm that has been providing petroleum engineering consulting services for over 20 years. The individual at CG&A primarily responsible for overseeing our reserve audit is Todd Brooker, President of CG&A, who received a Bachelor of Science degree in Petroleum Engineering from the University of Texas and is a registered Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers. Mr. Brooker and the other technical persons employed by CG&A engaged in the reserve study met the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Natural Gas Reserves Information promulgated by the Society of Petroleum Engineer.

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. Reserve calculations involve the estimate of future net recoverable reserves of oil and natural gas and the timing and amount of future net

9



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 reserve 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, 2018, 2017, and 2016, we based the estimated discounted future net cash flows from proved reserves on the 12-month average 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.


Oil and 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,
 
2018
 
2017
 
2016
Production
 
 
 
 
 
Oil (Bbls)-net production
1,089,724

 
371,993

 
61,088

Oil (per Bbl)-average realized price
$
53.26

 
$
47.92

 
$
39.59

Natural gas liquids (Bbls)-net production
246,425

 
73,875

 
11,355

Natural gas liquids (per Bbl)-average realized price
$
28.11

 
$
22.49

 
$
15.22

Natural Gas (Mcf)-production
2,855,739

 
776,164

 
332,643

Natural Gas (per Mcf)-average realized price
$
1.84

 
$
2.74

 
$
2.54

Barrels of oil equivalent (BOE)
1,812,106

 
575,229

 
127,863

Average daily net production (BOE)
4,965

 
1,576

 
350

Average Sales Price per BOE
$
38.75

 
$
37.57

 
$
26.87


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,
 
2018
 
2017
 
2016
Production costs per BOE
$
9.51

 
$
12.21

 
$
12.43

Production taxes per BOE
2.05

 
2.06

 
(1.30
)
Depreciation, depletion, and amortization per BOE
14.00

 
12.21

 
12.25

Total operating costs per BOE
$
25.56

 
$
26.48

 
$
23.38


The average oil and NGL sales prices above are calculated by dividing revenue from oil sales by volume of oil sold, in barrels “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 thousand cubic feet “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.

Acreage

The following table sets forth our approximate gross and net developed and undeveloped leasehold acreage as of December 31, 2018:

10



 
Undeveloped Acreage
 
Developed Acreage
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Delaware Basin
14,200

 
9,000

 
14,300

 
11,400

 
28,500

 
20,400


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, 2018, 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:

 
2019
 
2020
 
2021
Delaware Basin
1,840

 
6,197

 
1,350


We plan to maintain our undeveloped acreage by establishing production within the spacing units covering the acreage or extending or renewing the leases prior to their expiration.

Productive Wells

As of December 31, 2018, we have had 27.0 gross (24.9 net) oil wells and 11.0 gross (8.1 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, 2018, we drilled 16.0 gross (13.5 net) horizontal wells in the Delaware Basin. We completed and placed on production 15.0 gross (14.3 net) horizontal wells. As of December 31, 2018, 6.0 gross (3.8 net) wells were drilled but not yet completed. All of these wells were successful, and none were a dry hole.

The following table sets forth information with respect to the number of wells completed during the periods indicated. Each of these wells was drilled in the Delaware Basin in the Permian Basin.
 
Year Ended December 31,
 
2018
 
2017
2016
 
Gross
 
Net
 
Gross
 
Net
Gross
 
Net
Exploratory:
 
 
 
 
 
 
 
 
 
 
Productive
9.00

 
8.7

 
5.0

 
4.2


 

Dry

 

 

 


 

Development:
 
 
 
 
 
 
 
 
 
 
Productive
6.0

 
5.6
 

 


 

Dry

 

 

 


 

Total:
 
 
 
 
 
 
 
 
 
 
Productive
15.0

 
14.3

 
5.0

 
4.2


 

Dry

 
 
 

 


 


Present Activities


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As of December 31, 2018, we had 6.0 gross (3.8 net) wells in the process of drilling, completing, dewatering or shut-in awaiting infrastructure.


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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. Our properties are potentially subject to customary royalty and other interests, liens for current taxes, and other burdens which we be 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 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 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 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 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.

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.

We have an active hedging program to provide certainty 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 gas industry. The following table outlines our major customers and their percentage contribution to our total revenues for the years ended December 31, 2018 and 2017:


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Year Ended December 31,
 
2018
 
2017
  Texican Crude & Hydrocarbons
 
87
%
 
85
%
  ETC Field Services
 
2
%
 
14
%
  Lucid Energy
 
10
%
 
%
  Others below 10%
 
1
%
 
1
%
 
 
100
%
 
100
%

Delivery Commitments

As of December 31, 2018, we were not committed to providing a fixed quantity of oil or natural gas under any existing contracts.

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 continued 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 or 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 (“EHS”). 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 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, 2018 and 2017, we incurred approximately $38,000 and approximately $32,000, respectively, related to compliance with environmental laws for our oil and natural gas properties.

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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 that allows certain oil and natural gas exploration and production waste to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. As a 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. In 2016, the EPA agreed in a consent decree to review its regulation of oil and gas waste and has until March 2019 to determine whether revisions are necessary.

In the event that we fail to comply with requirements for the handling of hazardous waste, administrative, civil and criminal penalties can be imposed. We believe that we are in substantial compliance with applicable requirements related to hazardous waste handling. Repeal or modification of the RCRA oil and gas exemption, or modification of similar exemptions in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would 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 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.

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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 gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major 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 federal 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 (“GHGs”) 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 GHGs, 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 GHGs. 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 GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs 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 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

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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 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.

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 the 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 gas activities, the conduct of salt water disposal operations, and the methods of plugging and abandonment of oil and 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.





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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, or 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.

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.






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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 gas leases administered by the Bureau of Land Management, or 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.

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, 2018, we had 39 employees, all of whom were full-time employees, and we intend to continue to add personnel as our operational requirements grow. Our employees are not represented by any labor union or covered by any collective bargaining agreements.

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.






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Principal Executive Office and Corporate Offices

Our principal executive offices are in leased office space located at 1800 Bering Drive, Suite 510, Houston, Texas 77057, and our telephone number is (817) 585-9001. We also maintain offices in leased office space in Fort Worth, Texas and San Antonio, Texas.

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 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.

Item 1A. Risk Factors

Investing in our shares of common stock involves significant risks, including the potential loss of all or part of your investment. These risks could materially affect our business, financial condition and results of operations and cause a decline in the market price of our common stock. You should carefully consider all of the risks described in this Annual Report, in addition to the other information contained in this Annual Report, before you make an investment in our common stock. Additional risks not presently known to us or that we currently deem immaterial may also adversely affect our business. In addition to other matters identified or described by us from time to time in filings with the SEC, there are several important factors that could cause our future results to differ materially from historical results or trends, results anticipated or planned by us, or results that are reflected from time to time in any forward-looking statement. Some of these important factors, but not necessarily all important factors include the following:

Risks Relating to Our Business

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
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 2019 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.

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


20



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. If the prices of oil, natural gas and NGLs experience a substantial decline, our operations, financial condition and level of expenditures for the development of our oil, natural gas and NGL reserves may 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 actions of the Organization of Petroleum Exporting Countries, or 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;
technological advances affecting energy consumption; and
the price and availability of alternative fuels.

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 fall. A significant decline in the prices of natural gas or oil could adversely affect our financial position, financial results, cash flows, access to capital and ability to grow.

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 Second Lien Credit Agreement in 2017 and the Revolving Credit Agreement in 2018 (hereinafter defined and described in more detail). As of December 31, 2018, $75.0 million was outstanding under our Revolving Credit Agreement and $111.6 million was outstanding under our Second Lien Credit Agreement.

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 further utilize our credit facilities in the future or 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.

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;

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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 Form 10-K and the associated financial statements, the Company became aware, and promptly informed its Lenders, that it did not satisfy the leverage ratio covenant in the Revolving Credit Agreement, as of the fiscal quarter ended December 31, 2018. Accordingly, the Company requested that the Lenders consent to a waiver with respect to such provision. On March 1, 2019, the Company entered into that certain First Amendment and Waiver to Second Amended and Restated Credit Agreement, whereby the Lenders granted a waiver with respect to the breach of the leverage ratio covenant. 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.

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 and Series D 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 Second Lien Credit Agreement, the Series C Preferred Stock (as hereinafter defined and described) and the Series D 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 C Preferred Stock and the Series D 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

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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.

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 did not incur an impairment expense for the year ended December 31, 2018. We recognized an impairment expense of approximately $10.5 million for the year ended December 31, 2017.

Future write-downs could occur for numerous 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 reserve 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 reserve 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. 






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

Oil and natural gas reserve 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 reserve 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.

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 reserve 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 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:


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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.

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 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 problems 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 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 reserve 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 is to pursue selective acquisitions of undeveloped acreage potentially containing oil and natural gas reserves. If we choose 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.



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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 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, 2018, 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 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, 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.




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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, 2018, we had 3 gross (2.60 net) wells shut-in.

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.

The results of our planned 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.

The oil and 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 our Company, 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, 2018, we had 39 full-time 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. 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.


30



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 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.

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;

31



the timing and development of our products;
general and industry-specific economic conditions;
actual or anticipated fluctuations in our operating results;
liquidity;
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; and
the loss of any of our key management personnel.

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 two 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.

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.

Item 1B. Unresolved Staff Comments


32



As a smaller reporting company, we are not required to provide disclosure pursuant to this Item.

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.

33



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 March 5, 2019, there were 147 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 2018, we did not pay cash dividends on our outstanding preferred stock. As of December 31, 2018, the Company accrued a cumulative balance of $10.7 million of paid-in-kinds dividends. See Note 13 to our Consolidated Financial Statements.

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.

We are currently restricted from declaring dividends pursuant to the terms of our Second Lien Credit Agreement and outstanding preferred stock. Our Revolving Credit Agreement also includes customary limitations on our ability to pay dividends. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - “Liquidity and Capital Resources” for further information.

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, 2018:
໿
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
 
5,031,578

 
$
2.67

 
6,692,285

Equity compensation plans not approved by security holders
 

 

 

Total
 
5,031,578

 
$
2.67

 
6,692,285


For additional information regarding the Company’s benefit plans and share-based compensation expense, see Note 15 in Notes to Consolidated Financial Statements.


34



Item 6.     Selected Financial Data

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



Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis 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.

Our Company
We are a focused Permian Basin 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, with a focus on Liquids. In each of the past two years, over 90% of our revenues have been generated from the sale of Liquids (crude oil and NGLs). We have a highly contiguous acreage position with significant stacked-pay potential, which we believe includes at least five to seven productive zones and approximately 1,175 future drilling locations.
Our focus is growing our Company and increasing value to our stockholders by generating cash flow from our existing acreage base, as well as through delineation drilling on our acreage and future acquisitions, acreage exchanges and organic leasing.
2018 Operational and Financial Highlights
Increased our net sales production volumes by 215% to 4,965 BOE/d, as compared to 2017;
Increased our proved reserves by 273% to 42,707 MBOE (69% Liquids), as compared to 2017;
Averaged 8,081 net BOE/d from December 25 through December 31, 2018, achieving our 2018 year-end exit rate target of 8,000 BOE/d;
Increased our net acreage in the Delaware Basin to 28,500 gross (20,400 net) acres, where we have increased our average operated working interest to 76% and our operatorship to approximately 99% through acquisitions, acreage exchanges, and organic leasing;
Entered into several significant infrastructure and sales agreements, including agreements providing for crude gathering and transportation and water gathering and water disposal infrastructure, which we believe will provide us significant cost savings in 2019, advantaged crude pricing in the Gulf Coast markets, and more consistent production flowing to sales;
Reducing our crude transportation costs from approximately $5.15 per Bbl at December 31, 2018, to approximately $0.75 per Bbl in March 2019 through our infrastructure and sales agreements;
Reducing our salt water disposal costs from approximately $2.50 per Bbl to approximately $0.49 as of December 2018 through our infrastructure and sales agreements;
Entered into a new $500 million senior secured revolving credit facility with an initial borrowing base of $95 million (which was subsequently increased to $108 million in December 2018 as a result of our scheduled borrowing base redetermination), that re-financed our first-lien term loan with Riverstone Credit Partners, LLC and lowered our cost of capital and enhanced our liquidity;

Improved our capital structure through the conversion of approximately $68.0 million of our Second Lien Loans under our Second Lien Credit Agreement to a combination of preferred stock and common stock, of which 57.5% was converted into a new class of Series D Preferred Stock and 42.5% was converted into common stock based on a $5.00 per share conversion price, resulting in approximately $2.4 million in annualized PIK interest expense savings as a result of the conversion and also through the issuance of 25,000 shares of Series C-2 9.75% Convertible Participating Preferred Stock for $25.0 million; and
 
Decreased our general and administrative expense by 33% to $33.3 million in 2018 from $49.9 million in 2017.


35



2019 Updates
Improved our capital structure through the exchange and conversion of our outstanding Second Lien Loans under our Second Lien Credit Agreement to a combination of two newly created series of preferred stock (Series E Preferred Stock and Series F Preferred Stock) and common stock;
Eliminated the conversion features and voting rights on our existing Series C Preferred Stock and Series D Preferred Stock and reduced the redemption premium for the Series C Preferred Stock;
Increased the number of directors constituting our Board of Directors by two directors (to total eleven), which such vacancies created by the increase will be filled by the person designated by the holders of the Series E Preferred Stock and the person designated by the holders of the Series F Preferred Stock; and
Realized a 16% increase our borrowing base from $108 million to $125 million on March 1, 2019, as a result of our accelerated borrowing base redetermination.

Production Growth

Our producing properties are all located in the Delaware Basin of the Permian Basin in Winkler, Loving and Reeves Counties, Texas and Lea County, New Mexico. As a result of our horizontal development efforts, in 2018, we increased our net sales production volumes by 215% to 4,965 BOE/d in 2018 from 1,576 BOE/d in 2017.

Reserves Growth

As a result of our development efforts, acreage exchanges and acquisitions, our proved reserves increased 273% to approximately 42,707 MBOE as of December 31, 2018. Our reserves are Liquids rich, being comprised of approximately 69% Liquids (50% oil and 19% NGLs) and 31% natural gas. We believe that our current reserves represent only a small portion of the resource potential within our acreage, and we plan to further expand our inventory through continued delineation of our acreage both geographically and geologically and by drilling and completing additional prospective benches within our acreage position.

2018 Acreage Transactions
In 2018, we completed several acquisitions and acreage exchanges which increased our gross and net acreage position and proved reserves. As a result of our acquisitions, acreage exchanges and organic leasing, we increased our acreage position by 29% to 28,500 gross (20,400 net) acres and increased our operated working interest to an average of 76% and operated properties to approximately 99% of our acreage.
Below is a summary of some of the key transactions we completed in 2018:
In February 2018, we completed the acquisition of certain leasehold interests and other oil and gas assets in Loving and Winkler Counties, Texas from VPD Texas, L.P., for total cash consideration of approximately $10.7 million;
In March 2018, we closed the purchase of certain oil and natural gas properties and related assets in the Delaware Basin in Lea County, New Mexico, from OneEnergy Partners Operating, LLC, for stock and cash consideration valued at approximately $64.9 million, before acquisition costs and customary purchase price adjustments;
In May 2018, we completed the acquisition of certain leasehold interests and other oil and gas assets, including unproved leaseholds and non-consent proved producing oil and natural gas properties in Loving and Winkler Counties, Texas, from Anadarko for cash consideration of $7.1 million;
In June 2018, we closed a Leasehold Exchange Agreement with Felix Energy Holdings II, LLC (“Felix”) to exchange certain leasehold interest located in Loving and Winkler Counties, Texas, owned by us for certain leasehold interest located in the same counties owned by Felix and acquired certain working interests in two wells operated by us in Winkler County, Texas;
In August 2018, we closed an acre-for-acre trade of approximately 750 net acres in the Delaware Basin in Lea County, New Mexico, and assumed the working interests in four wells, pursuant to a Leasehold Exchange Agreement with Ameredev II, LLC. This exchange agreement increased our gross working interest in our Delaware Basin acreage in New Mexico up to 100% in core areas of our operations; and
In October 2018, we acquired the position of Southwest Royalties, Inc., our largest non-operating working interest partner in our core area of operations, which included approximately 570 net acres and 349 BOE/d production, for total cash consideration of $17.0 million.

36




Access to Infrastructure
We entered into several significant infrastructure agreements 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 production in Texas and Mexico.
In May 2018, we entered into a crude oil gathering agreement and option agreement with Salt Creek Midstream, LLC (“SCM”). The crude oil gathering agreement (the “Gathering Agreement”) enables SCM to (i) design, engineer, and construct a gathering system which will provide gathering services for our crude oil and (ii) gather our crude oil on the gathering system in certain production areas located in Winkler and Loving Counties, Texas and Lea County, New Mexico. The Gathering Agreement has a term of 12 years that automatically renews on a year to year basis until terminated by either party. In the Option Agreement, we granted an option to SCM to provide certain midstream services related to natural gas in Winkler and Loving Counties, Texas and Lea County, New Mexico, subject to expiration and terms of our existing gas agreement. The Option Agreement has a term commencing May 21, 2018 and terminating on January 1, 2027, pursuant to its one-time option. As consideration for this option, we received a one-time of payment $35 million from SCM.

In July 2018, the Company entered into a water gathering and disposal agreement and various ancillary agreements with SCM Water, LLC (“SCM Water”), an affiliate of SCM.  The agreements support our strategic efforts to secure long-term infrastructure solutions for our operations in the Delaware Basin. The water gathering project will complement our existing water disposal infrastructure, and we have reserved the right to recycle our produced water. SCM Water will commence, upon receipt of regulatory approval, to build out new gathering and disposal infrastructure to our current and future well locations in Lea County, New Mexico, and Winkler County, Texas. All future capital expenditures will be funded by SCM Water and will be designed to accommodate the water produced by our operations.  We will act as contract operator of SCM Water’s salt water disposal wells (SWD).  We have sold to SCM Water for cash consideration of up to $20 million, with $15 million upfront, an option to acquire our existing water infrastructure, a system which is comprised of approximately 14 miles of pipeline and one SWD.  We anticipate that the majority of our water will be disposed through the future SCM Water system at a competitive gathering rate under the agreement.

In August 2018, we secured pricing into a crude oil transportation and sales agreement with SCM Crude, LLC, an affiliate of SCM, to secure firm pipeline capacity on a long-haul crude oil pipeline to the Gulf Coast. Under the terms of the agreement, 6,000 Bbl/d of firm capacity will be delivered to the Gulf Coast for one year, beginning on July 1, 2019. During the next four years, from July 1, 2020 through June 30, 2024, firm capacity will adjust to 5,000 Bbl/d. All volumes will have Gulf Coast pricing based on Magellan East Houston pricing throughout the 5-year term. We also have the ability to expand our capacity during the term of the agreement as we believe having flexibility with barrels in the future is desirable.
In 2017, we entered into our long-term gas gathering and processing agreement with an affiliate of Lucid Energy Group (“Lucid”) to support our drilling program. Lucid has commenced receiving, gathering, and processing our gas production for certain areas in Winkler and Loving Counties, Texas and Lea County, New Mexico. Our agreement with Lucid secures sufficient term and capacity in the production areas committed to the agreement. Pursuant to our agreements with Lucid, there are no minimum volume commitments and all gas transported via Lucid is sent to Lucid’s 310 million cubic feet per day Red Hills Natural Gas Process Complex located in Lea County, New Mexico, where it is treated and processed then transported pursuant to transportation contracts through various long-haul pipelines with access to west coast markets, gulf coast markets, Permian markets and MidCon markets. Lucid is responsible for all capital costs in New Mexico and Texas, other than gathering lines from wellhead to various Lucid receipt points.

We believe these infrastructure and sales agreements will significantly reduce our operational costs in 2019 and future years, as well as more efficiently move our production to market.
Financial Resources
We have increased our liquidity position through several transactions in 2018, which we believe puts us in a financial position to fund our drilling and completion operations for 2019. On October 10, 2018, we announced our entry into the Revolving Credit Agreement, a new five-year senior secured reserve based revolving credit facility with an initial borrowing base of $95 million, that refinanced our first-lien term loan with Riverstone Credit Partners, LLC. The Company enhanced liquidity by $60 million, including $35 million in initial capacity under the Revolving Credit Agreement and $25 million raised through a tack-on to the outstanding Series C preferred stock. The Company reduced interest expense associated with the Riverstone First Lien Loans by 4.00%, from LIBOR plus 6.75% to LIBOR plus 2.75%. On December 7, 2018, the Company’s borrowing base under the Revolving Credit Agreement was increased to $108 million as a result of its regularly scheduled fall redetermination process.

37



Additionally, the Company converted approximately $68 million of the loans under its Second Lien Credit Agreement (as defined below) to a combination of preferred stock and common stock, of which 57.5% was converted into a new class of Series D preferred stock and 42.5% was converted into common stock based on a $5.00 per share conversion price. The Company realized approximately $2.4 million in annualized PIK interest expense savings as a result of the conversion.

The Company had $54.1 million in liquidity as of year-end 2018, including $33 million in availability under the Revolving Credit Agreement and $21.1 million in cash. We believe that our existing liquidity, Revolving Credit Agreement, and cash flow from operations will provide sufficient capital to execute our business plan for 2019, and we are currently targeting cash flow neutrality in 2019.

2019 Second Lien Term Loan Conversion and Borrowing Base Redetermination

On March 5, 2019, the Company agreed to convert the remaining Second Lien Loans 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 a new class of convertible preferred stock (Series E Preferred Stock), $55.0 million was converted into a new class of non-convertible preferred stock (Series F Preferred Stock), and $18.6 million was converted into common stock based on a $1.88 per share issuance price. The conversion of the Second Lien Loans in their entirety substantially improves our capital structure, resulting in the elimination of debt repayments and quarterly interest obligations on the Second Lien Loans. Subsequent to the conversion, our long-term debt consists solely of our Revolving Credit Agreement with no scheduled principle requirements until maturity in 2021.
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 approximately 7.8 million shares of our common stock. The potential dilution of our common stockholders resulting from the conversion of the Second Lien Loans, the Series C Preferred Stock and Series D Preferred Stock was reduced from approximately 53.5 million shares of common stock to approximately 41.6 million shares of common stock, including the issuance of approximately 17.6 million shares of common stock and the effect of the possible conversion of the Series E Preferred Stock. The newly created Series E Preferred Stock is the only potentially dilutive instrument outstanding.

Concurrently, we accelerated our May Revolving Credit borrowing base redetermination resulting in an increase in our borrowing base to $125.0 million as of March 1, 2019. We added an additional borrowing base redetermination in July that will include results of our 2019 drilling activity. Subsequent redeterminations are scheduled in November and May of each year.

                See "Subsequent Events" below for further information regarding our 2019 recapitalization transactions.

    

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, the sale of natural gas. The prices 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. Declines in the prices of oil, natural gas and NGLs would reduce our revenues and result in lower cash inflow which would make it more difficult for us to pursue our plans to acquire new properties and develop our existing properties. Declines in oil, natural gas, and NGL prices may also adversely affect our ability to obtain additional funding on favorable terms.

We believe that we are well-positioned to manage the challenges presented in a lower pricing environment, and we can execute our planned 2019 development program and capital expenditures with our current cash on hand, proceeds from operations and draws from the existing revolving credit facility as required.

Results of Operations

During the year ended December 31, 2018, we worked actively to increase our natural gas transportation, processing, and sales capacity for our expanding production. We successfully brought online our fourth Wolfcamp horizontal well. This well is our most geologically eastern well and is the closest well to the Central Basin Platform in our current acreage position. As of December 31, 2018, we have production flowing from our 24 horizontal wells and 14 legacy vertical wells.

Year Ended December 31, 2018 Compared to Year Ended December 31, 2017


38



The following sets forth selected revenue and sales data for the years ended December 31, 2018 and 2017:
 
For the Year Ended
December 31,
 
 
 
2018
 
2017
 
Change
 
%
Change
Net sales volumes:
 
 
 
 
 
 
 
Oil (Bbls)
1,089,724
 
371,993

 
717,731

 
193
 %
Natural gas (Mcf)
2,855,739
 
776,164

 
2,079,575

 
268
 %
NGL (Bbls)
246,425
 
73,875

 
172,550

 
234
 %
Total (BOE)
1,812,106
 
575,229

 
1,236,877

 
215
 %
Average daily sales volume (BOE/d)
4,965

 
1,576

 
3,389

 
215
 %
Average realized sales price:
 
 
 
 
 
 
 
Oil (per Bbl)
$
53.26

 
$
47.92

 
$
5.34

 
11
 %
Natural gas (per Mcf)
1.84

 
2.74

 
(0.90
)
 
(33
)%
NGL (per Bbl)
28.11

 
22.49

 
5.62

 
25
 %
Total (per BOE)
$
38.75

 
$
37.57

 
$
1.18

 
3
 %
Oil, natural gas and NGL revenues (in thousands):
 
 
 
 
 
 
 
Oil revenue
$
58,042

 
$
17,826

 
$
40,216

 
226
 %
Natural gas revenue
5,246

 
2,125

 
3,121

 
147
 %
NGL revenue
6,928

 
1,661

 
5,267

 
317
 %
Total
$
70,216

 
$
21,612

 
$
48,604

 
225
 %

Revenues

Total revenue increased $48.6 million to $70.2 million for the year ended December 31, 2018, as compared to $21.6 million for the year ended December 31, 2017, representing a 225% increase. Our significant increase in total revenue in 2018 is primarily attributable to an additional 15 wells being placed on production in the Delaware Basin during 2018. Total sales volume climbed 215% to 1,812,106 BOE during 2018, compared to 575,229 BOE in 2017, an increase of 1,236,877 BOE.

The Company’s increase in revenues in 2018 was partially offset by increased crude transportation costs, which are deducted from the Company’s gross revenue for crude oil sales. For the year ended December 31, 2018, transportation costs related to crude oil sales increased by $3.7 million to $4.7 million, compared to $1.0 million for the same period in 2017. The Company expects to lower its crude transportation and gathering costs in 2019 as a result of increased pipeline transportation of the Company’s crude oil under the Gathering Agreement with SCM. The Company anticipates savings of approximately $4.50 per Bbl, equal to a decrease of approximately 87.4% in transportation costs utilizing pipe gathering as opposed to trucking.

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

Our production during the year ended December 31, 2018, increased from 575,229 BOE in 2017 to 1,812,106 BOE in 2018, an increase of 215%. This increase in production was primarily attributable to 15 additional wells being completed and placed on production.

The following table shows a comparison of production costs for the years ended December 31, 2018 and 2017:

39



 
For the Year Ended
December 31,
 
 
 
2018
 
2017
 
Change
 
%
Change
Operating Expenses per BOE:
 
 
 
 
 
 
 
Production costs (1)
$
7.64

 
$
10.14

 
$
(2.50
)
 
(25
)%
Gathering, processing and transportation
1.87

 
2.07

 
(0.20
)
 
(10
)%
Production taxes
2.05

 
2.06

 
(0.01
)
 
(1
)%
General and administrative
18.35

 
86.66

 
(68.31
)
 
(79
)%
Depreciation, depletion, amortization and accretion
14.00

 
12.21

 
1.79

 
15
 %
Impairment of evaluated oil and natural gas properties

 
18.27

 
(18.27
)
 
(100
)%
Total (BOE)
$
43.91

 
$
131.41

 
$
(87.50
)
 
(67
)%
Operating Expenses
 
 
 
 
 
 
 
Production costs
$
13,843

 
$
5,832

 
$
8,011

 
137
 %
Gathering, processing and transportation
3,392

 
1,191

 
2,201

 
185
 %
Production taxes
3,709

 
1,187

 
2,522

 
212
 %
General and administrative
33,251

 
49,851

 
(16,600
)
 
(33
)%
Depreciation, depletion, amortization and accretion
25,367

 
7,025

 
18,342

 
261
 %
Impairment of evaluated oil and natural gas properties

 
10,505

 
(10,505
)
 
(100
)%
Total Operating Expenses
$
79,562

 
$
75,591

 
$
3,971

 
5
 %

(1) Production costs include ad valorem taxes.

Production Costs

Production costs increased by $8.0 million, or 137%, to $13.8 million for the year ended December 31, 2018 compared to $5.8 million for the year ended December 31, 2017, primarily due to an increase in production volumes. Our production costs on a per BOE basis decreased by $2.50, or 25%, from $10.14 per BOE for the year ended December 31, 2017 to $7.64 for the year ended December 31, 2018. The decreased production costs per BOE are reflective of higher product sales relative to saltwater disposal costs. Product sales were also higher relative to various other costs, particularly workovers and repairs, rentals, and testing.

Gathering, Processing and Transportation
    
Gathering, processing and transportation costs related to natural gas sales increased by $2.2 million to $3.4 million for the year ended December 31, 2018, compared to $1.2 million during the same period in 2017. This cost increase was primarily the result of higher natural gas sales volumes. The cost decrease on a per BOE basis was due to lower gathering and treating rates during the year ended December 31, 2018.

Production Taxes
    
Production taxes increased by $2.5 million, or 212%, to $3.7 million for the year ended December 31, 2018, compared to $1.2 million for the year ended December 31, 2017, due to the increase in sales volumes. Our production taxes of $2.05 per BOE for the year ended December 31, 2018, had no material variance from the $2.06 per BOE for the year ended December 31, 2017, which is a reflection of stable taxation rates in our areas of operation.

General and Administrative Expenses

General and administrative expenses (“G&A”) were $33.3 million during the year ended December 31, 2018, compared to $49.9 million during the year ended December 31, 2017, a decrease of $16.6 million or 33%. The decrease in G&A was primarily due to a decrease of $8.3 million in bonuses paid in 2018 offset by an increase of $4.1 million in professional and legal fees plus a significant decrease of $12.4 million in stock based compensation expense. The decrease of $12.4 million in stock based compensation was primarily attributed to $2.8 million in restricted stock bonuses granted to executive officers that vested at grant date, $6.2 million in restricted stock granted to employees and non-employee directors in October 2017, $1.6 million in incremental expense associated with the modification of stock options awarded to former Chief Executive Officer in 2017 and $1.8 million in restricted stock and stock options granted to three new executive officers hired during the year ended December 31, 2017.

40



During the year ended December 31, 2018, the $9.0 million of stock based compensation includes primarily $5.4 million of amortized expense recognized on stock awards granted in prior years and $3.6 million of expense recognized on vested stock awards granted in 2018.

Depreciation, Depletion, and Amortization

Depreciation, depletion, and amortization (“DD&A”) was $25.3 million during the year ended December 31, 2018, compared to $7.0 million during the year ended December 31, 2017, an increase of $18.3 million, or 261%. Our DD&A rate increased to $14.00 per BOE during the year ended December 31, 2018, from $12.21 per BOE during the year ended December 31, 2017. DD&A expense increased due to a sales volume increase of 1,236,877 BOE or 215% from 575,229 BOE during the year ended December 31, 2017, to 1,812,106 BOE during the year ended December 31, 2018.

Impairment of Evaluated Oil and Natural Gas Properties

There were no impairment charges for the year ended December 31, 2018. We recorded impairment charges of $10.5 million during the year ended December 31, 2017. Under the full cost method of accounting, we are required on a quarterly basis to determine whether the book value of our oil and natural gas properties is less than or equal to the “ceiling,” based upon the expected after-tax present value of the future net cash flows discounted at 10% from our proved reserves. Any excess of the net book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense. For the year ended December 31, 2017, higher capital expenditures with slower than expected development of proved reserves contributed to the excess of net book value of our oil and natural gas properties over the ceiling resulting in the recognition of an impairment charge of $10.5 million.

Other Income and Expense

The following table shows a comparison of other income and expenses for the years ended December 31, 2018 and December 31, 2017:

 
Years Ended December 31,
 
 
 
 
 
2018
 
2017
 
Variance
 
%
 
(In Thousands)
 
 
 
 
Other income (expense):
 
 
 
 
 
 
 
Other income
$
2

 
$
18

 
$
(16
)
 
(89
)%
Loss on early extinguishment of debt
(20,370
)
 

 
(20,370
)
 
(100
)%
Gain (loss) from commodity derivatives
55

 
(1,063
)
 
1,118

 
(105
)%
Gain (loss) from embedded derivatives
58,343

 
(6,260
)
 
64,603

 
(1,032
)%
Loss from conditionally redeemable preferred stock

 
(41
)
 
41

 
(100
)%
Interest expense
(32,827
)
 
(18,757
)
 
(14,070
)
 
75
 %
Total other income (expense)
$
5,203

 
$
(26,103
)
 
$
31,306

 
(120
)%

Loss on Early Extinguishment of Debt

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 of such transactions, 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 of the prepayment of the Riverstone First Lien Credit Agreement, we recorded a loss of approximately $8.1 on early extinguishment of debt.

Gain (Loss) from Commodity Derivatives

Gain on our commodity derivatives increased by $1.1 million or 105% during the year ended December 31, 2018, which primarily resulted from the function of fluctuations in the underlying commodity prices versus fixed hedge prices and the monthly

41



settlement of the hedged instruments. During the year ended December 31, 2018, we had unrealized net gains of $1.9 million on mark-to-market adjustments on unsettled positions, which were partially offset by net losses of $1.9 million on cash settlement and resulted in a net gain of $55,000. During the year ended 2017, our net loss from commodity derivatives consisted primarily of net losses of $0.2 million on cash settlements and $0.9 million on mark-to-market adjustments on unsettled position.

Gain (Loss) from Fair Value Changes of Debt Conversion and Warrant Derivatives

The change in fair values of derivative instruments consisted of a gain of $58.3 million during the year ended December 31, 2018, as compared to a loss of $6.3 million during the year ended December 31, 2017. The $58.3 million gain was primarily attributed to the change in fair value of embedded derivatives resulting from the decrease of the Company’s stock price to $1.37 per share at December 31, 2018, as compared to $5.11 per share at December 31, 2017, net of the embedded derivatives associated with the partial conversion of the Second Lien Loans on October 10, 2018.

Interest Expense

Interest expense was $32.8 million for the year ended December 31, 2018, compared to $18.8 million for the year ended December 31, 2017. For the year ended December 31, 2018, we incurred interest expense of $3.0 million for quarterly interest payments and amortized debt issuance costs on the Riverstone First Lien Loans and the incremental bridge loans under the First Lien Credit Agreement, $12.2 million of paid-in-kind (“PIK”) interest, $14.4 million related to amortized debt discount on our Second Lien Term Loan and $3.2 million of amortized debt issuance costs. During the year ended December 31, 2017, we incurred $18.8 million of interest expense relating to amortized debt issuance costs on debentures, convertible notes and non-convertible notes.

Liquidity and Capital Resources
 
We establish a capital budget at the beginning of each calendar year and review it throughout the course of the year. Our capital budgets are based upon our estimate of internally generated sources of cash, as well as cash on hand and the available borrowing capacity of our Revolving Credit Agreement.

We ended the year with $54.1 million of liquidity consisting of $33 million of availability under our Revolving Credit Agreement and $21.1 million of cash and cash equivalents on hand. Accounts payable, which were $47.1 million as of December 31, 2018, have been reduced to $38.8 million as of March 4, 2019. We are focused on reducing payables in 2019 using cash flows from operation while continuing to execute its one rig drilling program and bringing more wells into production.

As operator of over 99% of our properties, we have the ability to structure our capital budget to align with our existing and projected liquidity and cash flows. Our 2019 capital budget of approximately $40 million to $60 million includes a one rig drilling and completion program that we expect to fund with cash on hand, cash flows from operations and current and future availability under our Revolving Credit Agreement. We will continually re-evaluate our liquidity and projected cash flows and we may add additional drilling rigs, temporarily suspend drilling operations, or consider additional financing options as circumstance change.

Our 2019 capital budget does not include acquisitions and leasing activities as we are unable to anticipate the acquisition or leasing opportunities that will be available to us in the future.
Actual capital expenditure levels may vary significantly due to many factors, including drilling results; oil, natural gas and NGL prices; industry conditions; the prices and availability of goods and services; and the extent to which properties are acquired or non-strategic assets are sold. We continue to screen for attractive acquisition, leasing and acreage trade opportunities; however, the timing and size of such transactions are unpredictable. We believe we have the operational flexibility to react quickly with our capital expenditures to changes in circumstances or fluctuations in our cash flows.

We continuously monitor our liquidity needs, coordinate our capital expenditure program with our expected cash flows and projected debt-repayment schedule, and evaluate our available alternative sources of liquidity, including accessing debt and equity capital markets in light of current and expected economic conditions. We believe that our liquidity position and ability to generate cash flows from our operations will be adequate to fund 2019 operations and continue to meet our other obligations.






42




Our cash flows for the years ended December 31, 2018 and 2017, are presented in the following table:
 
Year ended December 31,
 
2018
 
2017
 
 (in thousands)
Operating activities
$
92,132

 
$
(7,243
)
Investing activities
(242,935
)
 
(147,502
)
Financing activities
154,478

 
160,469

Net change in cash
$
3,675

 
$
5,724


Operating Activities. For the year ended December 31, 2018, net cash provided by operating activities was $92.1 million, compared to net cash used in operating of $7.2 million for the year ended December 31, 2017. The increase of $99.4 million in cash used in operating activities was primarily attributable to $35.0 million received from SCM and its affiliates for upfront fees associated with option to provide future gas midstream services. The increase is also the result of a significant increase in revenue production and cash received upon net settlement of commodity derivative instruments.

Investing Activities. For the year ended December 31, 2018, net cash used in investing activities was $242.9 million compared to $147.5 million for the year ended December 31, 2017. The $242.9 million in cash used in investing activities was primarily attributable to the following:

$167.4 million incurred for drilling and completion costs, including drilling and completion costs for 2018 and costs accrued in 2017 which were paid in 2018;
$40.9 million cash consideration paid for the acquisition of leasehold acreage in the Delaware Basin in Lea County, New Mexico from OneEnergy Partners Operating, LLC;
$10.7 million cash consideration paid for the acquisition of proved and unproved oil and gas properties in Loving and Winkler Counties, Texas from VPD Texas, L.P.;
$7.1 million incurred to acquire additional leasehold interests from Anadarko;
$12.8 million incurred to pay for lease bonuses for leases primarily located in Winkler County, Texas and Lea County, New Mexico;
$17.0 million paid to Southwest Royalties for leasehold interests in Winkler County, Texas;
$3.9 million paid in connection with other leasehold exchange transactions and for other leasehold costs; and
$0.6 million paid for other property and equipment.

The costs incurred in investing activities were offset by the $17.5 million of upfront option fees associated with the option to acquire our salt water disposal infrastructure.

Financing Activities. For the year ended December 31, 2018, net cash provided by financing activities was $154.5 million compared to cash provided by financing activities of $160.5 million during the year ended December 31, 2017. The $154.5 million in net cash provided by financing activities included the following:

$75.0 million proceeds from the Revolving Credit Agreement;
$50.0 million proceeds from the Riverstone First Lien Credit Agreement;
$100.0 million and $25.0 million proceeds from the issuance of Series C-1 and C-2 Preferred Stock, respectively; and
$3.7 million in proceeds received from the exercise of stock warrants and stock options.

These increases in proceeds were offset by the following:

$57.0 million for the repayment of Riverstone First Lien Credit Agreement;
$31.8 million for the repayment of the First Lien Term Loan;
$2.2 million relating to payment of taxes withheld on stock based compensation;
$7.2 million of payments in connection with debt and equity issuance costs; and
$1.0 million paid to repurchase 253,598 shares of our common stock.
        

Summary of Existing Capital Structure
Below is a summary of our capital structure as of December 31, 2018 and 2017:

43



Debt and Equity Financing(1)
2018
 
2017
Debt
(in thousands)
Revolving Credit Agreement
$
75,000

 
$

Second Lien Credit Agreement
82,804

 
96,431

Bridge Loans associated with amended First Lien Term Loan

 
30,363

Other notes payable

 
1,011

Total debt
157,804

 
127,805

Mezzanine Equity
 
 
 
Series C-1 Preferred Stock
106,774

 

Series C-2 Preferred Stock
25,522

 

Series D Preferred Stock
40,729

 

Total mezzanine equity
173,025

 

Stockholders' Equity
 
 
 
Common stock
7

 
5

Additional paid-in capital
321,753

 
272,335

Treasury stock
(997
)
 

Accumulative deficit
(307,431
)
 
(303,288
)
Total stockholders' equity (deficit)
13,332

 
(30,948
)
Total
$
344,161

 
$
96,857

(1)
See Notes 9, 13 and 14 in the Notes to Consolidated Financial Statements for additional information about the Company’s outstanding debt and equity.

Revolving Credit Agreement

On October 10, 2018, we entered into a five-year, $500 million senior secured revolving credit agreement by and among the Company, as borrower, certain subsidiaries of the Company, as guarantors (the “Guarantors”), BMO Harris Bank, N.A., as administrative agent, and the lenders party thereto. The Revolving Credit Agreement provides for a senior secured reserve based revolving credit facility with an initial borrowing base of $95 million. The borrowing base is subject to semiannual redetermination in May and November of each year. On December 7, 2018, the Company’s borrowing base under the Revolving Credit Agreement was increased to $108 million as a result of its regularly scheduled fall redetermination process. We accelerated our May Revolving Credit borrowing base redetermination resulting in an increase in our borrowing base to $125 million as of March 1, 2019. We added an additional borrowing base redetermination in July that will include results of our 2019 drilling activity. Subsequent redeterminations are scheduled in November and May 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 Company borrowed $60 million under the Revolving Credit Agreement at closing to repay in full and retire the Company’s previously existing $50 million Riverstone First Lien Credit Agreement, including accrued interest and a prepayment premium, and to pay transaction expenses. (See Note 9 for additional information regarding the Riverstone First Lien Credit Agreement). Future borrowings under the Revolving Credit Agreement may be used to fund working capital requirements, including for the acquisition, exploration and development of oil and gas properties, and for general corporate purposes. The Revolving Credit Agreement also provides for issuance of letters of credit in an aggregate amount up to $5 million.

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. Mandatory and voluntary repayments generally will be made without premium or penalty.

44




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).
    
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” and, together with the Second Lien Term Loan, the “Second Lien Loans”). Each tranche of the Second Lien Loans bears interest at a rate per annum of 8.25%, compounded quarterly in arrears and payable only in-kind by increasing the principal amount of the loan by the amount of the interest due on each interest payment date.

The Second Lien Loans matures on April 26, 2021. The Second Lien Loans are subject to mandatory prepayment with the net proceeds of certain asset sales, casualty events and debt incurrences, subject to the right of the Company to reinvest the net proceeds of asset sales and casualty events within 180 days. The Company may not voluntarily prepay the Second Lien Loans prior to March 31, 2019, except (a) in connection with a Change of Control (as defined in the Second Lien Credit Agreement) or (b) if the closing price of our common stock on the principal exchange on which it is traded has been equal to or greater than 110% of the Conversion Price (as defined below) for at least 20 of the 30 trading days immediately preceding the prepayment. The Company is required to pay a make-whole premium in connection with any mandatory or voluntary prepayment of the Second Lien Loans.

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

70% of the principal amount of each tranche of the Second Lien Loans, together with accrued and unpaid interest and the make-whole premium on such principal amount (the “Conversion Sum”), will convert into a number of newly issued shares of common stock determined by dividing the total of such principal amount, accrued and unpaid interest and make-whole premium by $5.50 (subject to certain customary adjustments, the “Conversion Price”); and

30% of the principal amount of the Conversion Sum will convert on a dollar for dollar basis into a new term loan (the “Take Back Loans”).

The terms of the Take Back Loans will be substantially the same as the terms of the Second Lien Loans, except that the Take Back Loans will not be convertible and will bear interest payable in cash at a rate of LIBOR plus 9% (subject to a 1% LIBOR floor).

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

On January 31, 2018, the Company entered into a fourth amendment to the Second Lien Credit Agreement (“Amendment No. 4 to the Second Lien Credit Agreement”). The purpose of Amendment No. 4 to the Second Lien Credit Agreement was to, among other matters: permit us to enter the Riverstone First Lien Credit Agreement and incur the Riverstone First Lien Loans and related liens; permit us to issue the Series C Preferred Stock; and after the issuance of the Series C Preferred Stock pursuant to the Securities Purchase Agreement, reduce from two to one the maximum number of members of the Board the lenders under the Second Lien Credit Agreement will have the right to appoint following the conversion of the convertible loans under the Second Lien Credit Agreement.


45



On February 20, 2018, the Company entered into a fifth amendment to the Second Lien Credit Agreement (“Amendment No. 5 to the Second Lien Credit Agreement”), together with Amendment No. 1 to the Riverstone First Lien Credit Agreement. Pursuant to such amendments and a consent letter received from the Purchasers (as defined in Note 9 of the Notes to Consolidated Financial Statements), in their capacity as the holders of all of the issued and outstanding shares of Series C Preferred Stock, the Company was granted the right to repurchase shares of its common stock for an aggregate purchase price up to $10 million (subject to certain exceptions and conditions).

On October 10, 2018, the Company entered into a sixth amendment to the Second Lien Amendment (“Amendment No. 6 to the Second Lien Credit Agreement”), by and among the Company, the Guarantors, Wilmington Trust, National Association, as administrative agent, and the lenders party thereto, including Värde Partners, Inc., as lead lender. Among other matters, Amendment No. 6 to the Second Lien Credit Agreement amended the Second Lien Credit Agreement to permit the Company to enter into and incur indebtedness under the Revolving Credit Agreement (as defined and described above) and to provide for the reduction in the principal amount of the Second Lien Term Loan under the Second Lien Credit Agreement pursuant to the Transaction Agreement (as defined and described below).

See Note 9 in the Notes to Consolidated Financial Statements for additional information about the Company’s Second Lien Credit Agreement.

Preferred Stock Issuance

On January 30, 2018, we entered into a Securities Purchase Agreement (the “Securities Purchase Agreement”) with certain private funds affiliated with Värde Partners, Inc. (the “Purchasers”), pursuant to which we agreed to issue and sell to the Purchasers, and the Purchasers agreed to purchase from us, 100,000 shares of a newly created series of preferred stock of the Company, designated as “Series C 9.75% Convertible Participating Preferred Stock” (the “Series C Preferred Stock”), for a purchase price of $1,000 per share, or an aggregate of $100 million.

On October 10, 2018, the Company entered into a Transaction Agreement (the “Transaction Agreement”) by and among the Company and certain private funds affiliated with Värde Partners, Inc. (the “Värde Parties”), pursuant to which the Company agreed to:

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

issue and sell to the Värde Parties 25,000 shares of a newly created subseries of the Company’s Series C 9.75% Convertible Participating Preferred Stock, designated as “Series C-2 9.75% Convertible Participating Preferred Stock” (the Series C-2 Preferred Stock”), for a purchase price of $1,000 per share, or an aggregate of $25 million.

Pursuant to an Amended and Restated Certificate of Designation of Preferences, Rights and Limitations of Series C-1 9.75% Convertible Participating Preferred Stock and Series C-2 9.75% Convertible Participating Preferred Stock (the “Series C Certificate of Designation”), filed by the Company with the Secretary of State of Nevada on October 10, 2018, the outstanding 100,000 shares of the Company’s Series C 9.75% Convertible Participating Preferred Stock were re-designated as “Series C-1 9.75% Convertible Participating Preferred Stock” (the “Series C-1 Preferred Stock” and, together with the Series C-2 Preferred Stock, the “Series C Preferred Stock”). The Series C Preferred Stock and the Series D Preferred Stock are referred to collectively as the “Preferred Stock.”

Closing of the issuance of the shares of common stock and Series D Preferred Stock and the issuance and sale of the shares of Series C-2 Preferred Stock pursuant to the Transaction Agreement occurred on October 10, 2018. The Company intends to use the net proceeds from the sale of the shares of Series C-2 Preferred Stock for general corporate purposes, including the acquisition, exploration and development of oil and gas properties. The Series D Preferred Stock and the Series C-2 Preferred Stock are recorded at fair value of $40.0 million and $25.0 million, respectively, as mezzanine equity as of December 31, 2018.

See Note 13 in the Notes to Consolidated Financial Statements for additional information about the Company’s Preferred Stock.


46



SOS Note

On June 30, 2016, pursuant to the merger agreement with Brushy and as a condition of the fourth amendment to such merger agreement, the Company was required to make a cash payment of $500,000 to SOS Investment LLC (“SOS”), and also executed a subordinated promissory note with SOS, for $1 million, at an interest rate of 6% per annum which matures on June 30, 2019. In conjunction with the cash payment and the note, the Company also issued 200,000 warrants at an exercise price of $25.00. The Company accounted for the cost of warrants of $0.2 million as part of the Brushy merger transaction costs during the year ended December 31, 2017. The SOS note was fully paid on January 22, 2018.

See Note 9 in the Notes to Consolidated Financial Statements for additional information regarding the SOS Note.

Common Stock Repurchase

In March 2018, we entered into a share-repurchase agreement (the “SRA”) with an investment brokerage company (“Broker”) to repurchase $1.0 million of the Company’s common stock as part of the Share Repurchase Plan (the “Plan”). Under the terms of the SRA, the Company paid cash directly to the Broker and received delivery of shares of the Company’s common stock. All of the shares acquired by the Company under the SRA are recorded as treasury stock. For the year ended December 31, 2018 the Company purchased 253,598 shares of the Company’s common stock for approximately $1.0 million.

Related Party Transactions

VPD Acquisition

On February 28, 2018, the Company completed the acquisition of certain leasehold interests and other oil and gas assets in Loving and Winkler Counties, Texas from VPD Texas, L.P. (“VPD”) for cash consideration of $10.6 million including $0.5 million of related acquisition costs (the “VPD Acquisition”). The VPD Acquisition was recorded at fair value which was the total cash consideration and related acquisition costs of approximately $10.7 million. VPD is an affiliate of Värde Partners, Inc. (“Värde”). Värde participated as lead lender in the Company’s Second Lien Term Loan transaction in 2017 and as investor of the Company’s Series C Preferred Stock transaction in January 2018. As a result, the VPD Acquisition is considered a related party transaction. See Note 11 - Related Party Transactions in the Notes to Consolidated Financial Statements.

Subsequent Events
Amendment to Revolving Credit Agreement
        On March 1, 2019, the Company entered into a first amendment and waiver (the “First Amendment and Waiver to Second Amended and Restated Credit Agreement”) to its existing Revolving Credit Agreement. Among other matters, in the First Amendment and Waiver to Second Amended and Restated Credit Agreement, the Company requested, and the Administrative Agent and the Majority Lenders (as defined in the First Amendment and Waiver to Second Amended and Restated Credit Agreement) consented to, a waiver of the requirement to comply with the leverage ratio covenant in Section 9.01(a) of the Revolving Credit Agreement as of the fiscal quarter ended December 31, 2018.
Additionally, the Company agreed upon a borrowing base redetermination under the Company’s First Amendment and Waiver to the Second Amended and Restated Credit Agreement, whereby the Borrowing Base (as defined therein) was increased from $108.0 million to $125.0 million, resulting in a $17.0 million increase in revolver capacity. This redetermination will be in effect until the next scheduled redetermination on or about July 1, 2019, and thereafter, the Borrowing Base will generally be redetermined semi-annually on May 1 and November 1 of each year, beginning on November 1, 2019. The Company may use borrowings to fund capital expenditures, working capital requirements and other general corporate purposes.
Transaction Agreement
On March 5, 2019, the Company entered into a Transaction Agreement (the “2019 Transaction Agreement”) by and among the Company and the Värde Parties), pursuant to which the Company agreed to:
issue to the Värde Parties an aggregate of (i) 9,891,638 shares of the Company’s common stock, par value $0.0001 per share (the “Term Loan Exchanged Common Stock”), (ii) 60,000 shares of a newly created series of preferred stock of the Company, designated as “Series E 8.25% Convertible Participating Preferred Stock” (the “Series E Preferred Stock” or the “Exchanged Series E Shares”), and (iii) 55,000 shares of a newly created series of preferred stock of the Company, designated as “Series F 9.00% Participating Preferred Stock” (the “Series F Preferred Stock” or the “Exchanged Series F Shares” and, together with the Exchanged Series E Shares, the “Exchanged Preferred Shares”), as consideration for

47



the termination of the Second Lien Credit Agreement (as defined in the 2019 Transaction Agreement) and the satisfaction in full, in lieu of repayment in full in cash, of $133.6 million (the “Term Loan Exchange Amount”) pursuant to the Payoff Letter (as defined in the 2019 Transaction Agreement);

issue to the Värde Parties, as consideration for the amendment and restatement of the Second Amended and Restated Series C Certificate of Designation (as defined below) and the Amended and Restated Series D Certificate of Designation (as defined below), 7,750,000 shares of the Common Stock.

Closing of the issuance of the shares of Common Stock, Series E Preferred Stock and Series F Preferred Stock pursuant to the 2019 Transaction Agreement occurred on March 5, 2019.
The terms of the Series F Preferred Stock are set forth in a Certificate of Designation of Preferences, Rights and Limitations of Series F Participating Preferred Stock (the “Series F Certificate of Designation”) and the terms of the Series E Preferred Stock are set forth in a Certificate of Designation of Preferences, Rights and Limitations of Series E Convertible Participating Preferred Stock (the “Series E Certificate of Designation”), each of which was filed by the Company with the Secretary of State of the State of Nevada on March 5, 2019. The terms of the Series C Preferred Stock are set forth in a Second Amended and Restated Certificate of Designation of Preferences, Rights and Limitations of Series C-1 9.75% Participating Preferred Stock and Series C-2 9.75% Participating Preferred Stock (the “Second Amended and Restated Series C Certificate of Designation”), and the terms of the Series D Preferred Stock are set forth in an Amended and Restated Certificate of Designation of Preferences, Rights and Limitations of Series D 8.25% Participating Preferred Stock (the “Amended and Restated Series D Certificate of Designation”).    
See Note 20 to the Financial Statements for additional information regarding the material terms of the Series F Preferred Stock, the Series E Preferred Stock, the amended terms of the Series C Preferred Stock, the amended terms of the Series D Preferred Stock and the 2019 Transaction Agreement.
Amended and Restated Registration Rights Agreement
On March 5, 2019, in connection with the closing of the issuance of shares of Common Stock, Series E Preferred Stock and Series F Preferred Stock pursuant to the 2019 Transaction Agreement, the Company entered into an Amended and Restated Registration Rights Agreement (the “Amended and Restated Registration Rights Agreement”) to amend its existing registration rights agreement, dated October 10, 2018 (the “October Registration Rights Agreement”), by and between the Company and the Värde Parties. Among other matters, the Amended and Restated Registration Rights Agreement amended the October Registration Rights agreement to require the Company to file with the SEC a registration statement under the Securities Act registering for resale the shares of Common Stock issued pursuant to the 2019 Transaction Agreement and the shares of Common Stock issuable upon conversion of the shares of Series E Preferred Stock issued pursuant to the Transaction Agreement. The Amended and Restated Registration Rights Agreement also provides that the Company may satisfy its obligation to file a registration statement by filing an amendment to the October Shelf Registration Statement (as defined in the Amended and Restated Registration Rights Agreement).


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 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

As of December 31, 2018, we did not have any off-balance sheet arrangements, and it is not anticipated that we will enter into any off-balance sheet arrangements.

Critical Accounting Policies and Estimates


48



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 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 preparation of financial statements in conformity with GAAP requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ significantly from those estimates. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment.

Our most significant financial estimates are associated with our estimated proved oil and natural gas reserves, assessments of impairment in the carrying value of undeveloped acreage and proven properties. There are also significant financial estimates associated with the valuation of our options and warrants, inducement transactions, and estimated derivative liabilities.

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 SEC rules, we prepared our oil and natural gas reserve estimates as of December 31, 2018, using the average, first-day-of-the-month price during the 12-month period ended December 31, 2018.

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 reserve 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 reserve 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 reserve estimates will be used. For example, the standardized measure calculation requires us to apply a 10% discount rate. Although reserve 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 reserve 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

49



our oil and natural gas reserves as of December 31, and quarterly throughout the year. For purposes of depletion, depreciation, and impairment, we adjust reserve quantities at all quarterly periods for the estimated impact of acquisitions and dispositions. Changes in depletion, depreciation or impairment calculations caused by changes in reserve 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

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, 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.

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 9 to our consolidated financial statements in Item 16 of this Annual Report on Form 10-K and accounted for separately from the debt.

Revenue Recognition

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


50



Recently Issued Accounting Pronouncements

For a discussion of recently adopted accounting standards and recent accounting standards not yet adopted, see “Note 2 - 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

As a smaller reporting company, we are not required to provide the information required by this Item 7A.

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.

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 and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2018.

We identified a material weakness in the Company’s internal controls over financial reporting relating to our full cost ceiling test calculation during the year ended December 31, 2017. The Company has worked diligently to remediate the material weakness, including implementing measures to remediate the underlying causes that gave rise to the material weaknesses through implementation of processes and controls ensuring compliance with GAAP. The Company has specifically enhanced review procedures and provided additional documentation, analysis and governance over the ceiling test calculation to ensure that these procedures are performed and recorded in accordance with Company’s policies and GAAP. We took the following actions with respect to our full cost ceiling test calculation to address the material weakness:

(i)    implemented procedures to perform enhanced detailed reviews and analytical analysis on our current and projected tax position with respect to the impact of projected income taxes on the ceiling test; and
(ii)    implemented procedures for additional reviews on the ceiling test calculation, including treatment of wells-in-process, future income tax effects, and future development cost along with procedures to validate the ceiling test calculation with the reserve report.
     Management believes that the measures described above have remediated the material weakness identified at December 31, 2017.

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 and Chief Financial Officer assessed the effectiveness of our internal control over financial reporting, as of December 31, 2018, based on the criteria for effective internal

51



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, 2018.

BDO USA, LLP, the Company’s independent registered public accounting firm, has audited our internal control over financial reporting as of December 31, 2018, and issued an attestation report set forth under the caption “Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting.”

Changes in Internal Control Over Financial Reporting
 
There was no change in our internal control over financial reporting during the year ended December 31, 2018, except as mentioned above related to remediation of the material weakness, that materially affected or is reasonably likely to materially affect our internal control over financial reporting.

Item 9B.     Other Information

The registrant elects to disclose under this Item 9B information otherwise disclosable in a report on Form 8-K.
On October 10, 2018, the Company entered into the Revolving Credit Agreement pursuant to which BMO Harris Bank N.A., SunTrust Bank, Capital One, N.A., and Credit Suisse AG, Cayman Islands Branch, (collectively, the “Lenders”) have made certain credit available to and on behalf of the Company. In connection with the preparation of this Form 10-K and the associated financial statements, the Company informed its Lenders, that it did not satisfy the leverage ratio covenant in Section 9.01(a) of the Revolving Credit Agreement, as of the fiscal quarter ended December 31, 2018. Accordingly, the Company requested that the Lenders consent to a waiver with respect to such provision.
On March 1, 2019, the Company entered into that certain First Amendment and Waiver to Second Amended and Restated Credit Agreement (“Waiver”) whereby the Lenders granted a waiver with respect to the breach of the leverage ratio covenant contained in Section 9.01(a) of the Revolving Credit Agreement. Among other things, the Waiver amended the terms of the Revolving Credit Agreement to increase the borrowing base to $125,000,000.
The foregoing summaries of the terms of the Revolving Credit Agreement and Waiver do not purport to be complete and are subject to, and qualified in their entirety by, the full text of the Revolving Credit Agreement and Waiver, copies of which are filed as Exhibits 10.37 and Exhibit 10.41, respectively, to this Annual Report and incorporated herein by reference.

PART III

Item 10.     Directors, Executive Officers and Corporate Governance

For information concerning Item 10, see the definitive Proxy Statement of Lilis Energy, Inc., relating to the Company’s 2019 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.

The Company has adopted a code of ethics, our Code of Business Conduct, that applies to the Company’s chief executive officer, chief financial officer and chief accounting officer. The full text of such code of ethics has been posted on the Company’s website at www.lilisenergy.com and is available free of charge in print to any stockholder who requests it. Request for copies should be addressed to the Vice President of Human Resources at mailing address, 1800 Bering Drive, Suite 510, Houston, Texas 77057.

Item 11.     Executive Compensation

For information concerning Item 11, see the definitive Proxy Statement of Lilis Energy, Inc., relating to the Company’s 2019 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.

Item 12.     Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
 

52



For information concerning Item 12, see the definitive Proxy Statement of Lilis Energy, Inc., relating to the Company’s 2019 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.
 
Item 13.    Certain Relationships and Related Transactions, and Director Independence

For information concerning Item 13, see the definitive Proxy Statement of Lilis Energy, Inc., relating to the Company’s 2019 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.

Item 14.     Principal Accounting Fees and Services

For information concerning Item 14, see the definitive Proxy Statement of Lilis Energy, Inc., relating to the Company’s 2019 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.

53



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 reserve in which we own a working interest, reported at the 100% or 8/8ths level. For example, the number of gross wells is the total number of wells in which we own a working interest.

Lease. A legal contract that specifies the terms of the business relationship between an energy company and a landowner or mineral rights holder on a particular tract of land.

Leasehold. Mineral rights leased in a certain area to form a project area.

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

MBBLs. One thousand barrels of crude oil or other liquid hydrocarbons.


54



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.


55



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.

56



PART IV
 
Item 15. Exhibits, Financial Statement Schedules


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

(i)
The consolidated financial statements of Lilis Energy, Inc. are listed on the Index to this Form 10-K, page 58.

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


b)    Exhibits


57




58




59



101.INS*
XBRL Instance Document
101.SCH*
XBRL Taxonomy Extension Schema Document
101.CAL*
XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*
XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*
XBRL Taxonomy Extension Label Linkbase Document
101.PRE*
XBRL Taxonomy Extension Presentation Linkbase Document

60



*
Filed herewith.
Indicates management contract or compensatory plan.
+
To be filed by amendment.

c)    Financial Statement Schedules

Not applicable.

Item 16. Form 10-K Summary

None.

61



SIGNATURES
 
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 
LILIS ENERGY, INC.
 
 
 
Date: March 7, 2019
By:
/s/Ronald D. Ormand
 
 
Ronald D. Ormand
 
 
Chief Executive Officer
(Authorized Signatory)
 
Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated.
Signature
 
Title
 
Date
 
 
 
 
 
/s/Ronald D. Ormand
 
Executive Chairman of the Board & Chief Executive Officer
 
March 7, 2019
Ronald D. Ormand
 
(Principal Executive Officer)
 
 
 
 
 
 
 
/s/ Joseph C. Daches
 
President and Chief Financial Officer
 
March 7, 2019
Joseph C. Daches
 
(Principal Financial and Accounting Officer)
 
 
 
 
 
 
 
/s/ Mark Christensen
 
Director
 
March 7, 2019
Mark Christensen
 
 
 
 
 
 
 
 
 
/s/ Nuno Brandolini
 
Director
 
March 7, 2019
Nuno Brandolini
 
 
 
 
 
 
 
 
 
/s/ R. Glenn Dawson
 
Director
 
March 7, 2019
R. Glenn Dawson
 
 
 
 
 
 
 
 
 
/s/ John Johanning
 
Director
 
March 7, 2019
John Johanning
 
 
 
 
 
 
 
 
 
/s/ Markus Specks
 
Director
 
March 7, 2019
Markus Specks
 
 
 
 
 
 
 
 
 
/s/ Michael G. Long
 
Director
 
March 7, 2019
Michael G. Long
 
 
 
 
 
 
 
 
 
/s/ David M. Wood
 
Director
 
March 7, 2019
David M. Wood
 
 
 
 
 
 
 
 
 
/s/ Nicholas Steinsberger
 
Director
 
March 7, 2019
Nicholas Steinsberger
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


62



Index to Financial Statements



63




Report of Independent Registered Public Accounting Firm
 



Shareholders and Board of Directors
Lilis Energy, Inc.
Houston, Texas

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Lilis Energy, Inc. (the “Company”) and subsidiaries as of December 31, 2018 and 2017, the related consolidated statements of operations, changes in stockholders’ equity (deficit), and cash flows for the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company and subsidiaries at December 31, 2018 and 2017, and the results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company's internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) and our report dated March 7, 2019 expressed an unqualified opinion thereon.

Basis for Opinion

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

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud.

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

/s/ BDO USA, LLP

We have served as the Company's auditor since 2017.
Dallas, Texas
March 7, 2019



64



Report of Independent Registered Public Accounting Firm
 

Shareholders and Board of Directors
Lilis Energy, Inc.
Houston, Texas

Opinion on Internal Control over Financial Reporting

We have audited Lilis Energy, Inc.’s (the “Company’s”) internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of the Company and subsidiaries as of December 31, 2018 and 2017, the related consolidated statements of operations, changes in stockholders’ equity (deficit), and cash flows for the years then ended, and the related notes and our report dated March 7, 2019 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Item 9A, Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit of internal control over financial reporting in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of 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 or procedures may deteriorate.

/s/ BDO USA, LLP

Dallas, Texas
March 7, 2019





65



Lilis Energy, Inc. and Subsidiaries
Consolidated Balance Sheets
(In thousands, except share and per share data)

 
December 31,
 
2018
 
2017
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
21,137

 
$
17,462

Accounts receivable, net of allowance of $25 and $39, respectively
20,546

 
7,426

Derivative assets
2,551

 

Prepaid expenses and other current assets
1,851

 
584

Total current assets
46,085

 
25,472

Property and equipment:

 
 
Oil and natural gas properties, full cost method of accounting, net
430,379

 
170,305

Other property and equipment, net
524

 
76

Total property and equipment, net
430,903

 
170,381

Other assets
3,785

 
91

Total assets
$
480,773

 
$
195,944

LIABILITIES, MEZZANINE EQUITY AND STOCKHOLDERS EQUITY (DEFICIT)

 
 
Current liabilities:

 
 
Accounts payable
$
47,112

 
$
10,488

Accrued liabilities
14,794

 
7,634

Revenue payable
14,546

 
6,460

Derivative instruments
515

 
853

Total current liabilities
76,967

 
25,435

Asset retirement obligations
2,433

 
726

Long-term debt
157,804

 
127,794

Derivative instruments
4,699

 
72,937

Long-term deferred revenue and other liabilities
52,513

 

Total liabilities
294,416

 
226,892

Commitments and contingencies (Note 19)

 


Mezzanine Equity:
 
 
 
Series C-1 9.75% Convertible Participating Preferred Stock, 10,000,000 shares authorized, 100,000 shares issued and outstanding with a liquidation preference of $24.3 million as of December 31, 2018.
106,774

 

Series C-2 9.75% Convertible Participating Preferred Stock, 10,000,000 shares authorized, 25,000 of shares issued and outstanding with a liquidation preference of $5.7 million as of December 31, 2018.
25,522

 

Series D $8.25% Convertible Participating Preferred Stock, 10,000,000 shares authorized, 39,254 shares, issued and outstanding with a liquidation preference of $10.0 million as of December 31, 2018.
40,729

 

Stockholders’ equity (deficit):

 
 
Common stock, $0.0001 par value per share; 150,000,000 shares authorized, 71,182,016 and 53,368,331 shares issued and outstanding as of December 31, 2018 and 2017, respectively.
7

 
5

Additional paid-in capital
321,753

 
272,335

Treasury stock, 253,598 shares as of December 31, 2018
(997
)
 

Accumulated deficit
(307,431
)
 
(303,288
)
Total stockholders’ equity (deficit)
13,332

 
(30,948
)
Total liabilities, mezzanine equity and stockholders’ equity (deficit)
$
480,773

 
$
195,944


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

66



Lilis Energy, Inc. and Subsidiaries
Consolidated Statements of Operations
(In thousands, except share and per share data)

 
Year Ended December 31,
 
2018
 
2017
Revenues:
 
 
 
Oil sales
$
58,042

 
$
17,826

Natural gas sales
5,246

 
2,125

Natural gas liquid sales
6,928

 
1,661

 Total revenues
70,216

 
21,612

Operating expenses:
 
 
 
Production costs
13,843

 
5,832

Gathering, processing and transportation
3,392

 
1,191

Production taxes
3,709

 
1,187

General and administrative
33,251